حسين عليوي جفيت

Petrophysical analysis provides essential data for subsurface formation evaluation and resource estimation. Key parameters like porosity, permeability, and water saturation are not direct outputs but are derived through the interpretation of well logs, a multi-step process involving acquisition, processing, and calibration, each introducing uncertainty. This research aims to quantify porosity uncertainty using the Monte Carlo technique and to determine how it is affected by different parameters. First, we did a quick analysis of the data to understand the well lithology and the fluid type. Second, we calculated the input parameters (densities) from the logs, and due to the interpretation challenges and the lithology changing, we had to do a zonation of the log interval and assign a specific RHO matrix value for each interval. Then, we did an uncertainty analysis for the RHO matrix within one of the zones to clarify uncertainty, and we had ±0.05 standard deviation of matrix density. Finally, the effect of uncertainty on input parameters will be studied using Monte Carlo analysis. Our key finding shows that a ± 0.05 g/cm3 standard deviation in matrix density (RHO matrix) propagates to a ± 0.02 uncertainty in porosity value. The standard deviation of the interval changes from depth to depth, and an average was used in calculations. Results indicate that the uncertainty in porosity increases proportionally with the increase in standard deviation of matrix density due to the linearity of the porosity equation.

The study focuses on the Mishrif carbonate reservoir in the X oilfield, southern Iraq, which presents characterization complexities of a difficult nature due to its complex geology. The field, sited in the Zubair subzone, the most prolific and the southernmost of the Mesopotamian Plain hydrocarbon production units, is a good example of the structural complexity of the unstable shelf of the region of southern Iraq, where salt tectonics, basement faulting, and deformation of the region together produce characteristic anticline structures. This study uses an integrated petrophysical method combining core analysis from Wells 1 and 5, nuclear magnetic resonance (NMR) T2 distribution measurements, and conventional well log data to characterize the heterogeneous Mishrif carbonate reservoir comprehensively. A hierarchical pore classification system was developed based on mercury injection capillary pressure (MICP) analysis and geological observations, classifying the pore network into three different types: micropores, mesopores, and macropores. Through systematic calibration with MICP data, specific T2 relaxation time cutoffs were established to partition total porosity into these pore-size classes. The analysis shows that micropores mainly contain bound fluids, with a T2 cutoff value of 50 ms effectively describing irreducible water saturation. Strong relationships between NMR-derived porosity division and MICP-based pore size distributions confirm the integrated methodology. The method successfully quantifies critical reservoir parameters, including porosity, permeability, and pore size distribution. The results demonstrate that integrating core-calibrated NMR analysis with conventional petrophysical evaluation significantly enhances characterization accuracy in complex carbonate systems. This methodology provides essential parameters for reservoir engineering applications and establishes a robust framework applicable to similar heterogeneous carbonate reservoirs. The successful application of this integrated approach in the structurally complex Mishrif Formation emphasizes its potential for improving reservoir characterization in challenging geological settings. © The Author(s), under exclusive licence to Springer-Verlag GmbH Germany, part of Springer Nature 2025.