Rock physics provides a dynamic tool for quantitative analysis by developing the basic relationship between fluid, lithological, and depositional environment of the reservoir. The elastic attributes such as impedance, density, velocity, V p/V s ratio, Mu-rho, and Lambda-rho are crucial parameters to characterize reservoir and non-reservoir facies. Rock physics modelling assists like a bridge to link the elastic properties to petrophysical properties such as porosity, facies distribution, fluid saturation, and clay/shale volume. A robust petro-elastic relationship obtained from rock physics models leads to more precise discrimination of pay and non-pay facies in the sand intervals of the study area. The Paleocene aged Lower Ranikot Formation and Pab sandstone of Cretaceous age are proven reservoirs of the Mehar gas field, Lower Indus Basin. These sands are widely distributed in the southwestern part of the basin and are enormously heterogeneous, which makes it difficult to distinguish facies and fluid content in the reservoir intervals. So, an attempt is made in this paper to separate the reservoir facies from non-reservoir facies by using an integrated approach of the petro-elastic domain in the targeted sand intervals. Furthermore, missing logs (S-sonic and P-sonic) were also synthesized in the wells and missing intervals along with improving the poor quality of the density log by captivating the washouts and other side effects. The calibrated rock physics model shows good consistency between measured and modelled logs. Petro-elastic models were predicted initially using petrophysical properties and incorporated at true reservoir conditions/parameters. Lithofacies were defined based on petrophysical cut-offs. Rock physics modelled elastic properties (Lambda-rho versus Mu-rho, impedance versus V p/V s ratio) were then cross-plotted by keeping lithofacies in the Z-axis. The cross-plots clearly separated and demarcated the litho-fluid classes (wet sand, gas sand, shale, and limestone) with specific orientation/patterns which were randomized in conventional petrophysical analysis.

Overpressure conditions in Potwar Basin of Pakistan pose significant drilling and completion problems. Specifically, in eastern Potwar, abnormally high pressures are observed within structural compartments of Murree Formation of Neogene age. Compaction disequilibrium and tectonic stresses are considered as two major factors, controlling pore pressures in this foreland basin. Undercompaction of sediments due to high sediment influx affects the porosity-depth relationship as the rock deviates from the normal compaction trend. Demarcation of structural geometries is critical in understanding abnormal pressure conditions within thick molasse deposits of Murree Formation. Eastern Potwar is divided into three zones on the basis of structural geometries, including duplex thrust sheets, salt-cored anticlines, and triangular zones. Geohistory analysis and pore pressure prediction have been performed for determining the overpressuring mechanism. Log-based pressure prediction in different oil fields of eastern Potwar depicts anomalous pressure conditions in some of the wells. High-sedimentation rate during Miocene times resulted in a low porosity reduction rate due to the inability of fluid to escape out of the pores. Eaton’s method was used to predict the pore pressure, and these pressure curves were calibrated against measured pressure to validate the results. Pressures predicted in Qazian-1X well showed very good correlation with measured pressure data. Most of the wells with overpressure intervals exhibited high porosity values, showing deviation from the normal compaction trend. This pressure prediction revealed that compaction disequilibrium is the primary cause of overpressure conditions within Murree Formation, resulted in response to the rapid rate of sedimentation. The deformation mechanism and presence of different structural geometries also contributed in the development of abnormal pressures.

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