The analysis of shaly sand gas reservoirs with low and variable formation water salinity presents specific challenges. These formations usually exhibit low resistivity contrast between water and hydrocarbon zones, and high apparent clay content. Calculated water saturations are high, and need to be accurately split between clay-bound, capillary-bound and free water. In addition to these reservoir characterization problems, we observe effects caused by the drilling process, such as gas dissolution in OBM filtrate, and time-lapse effects between LWD and Wireline logs. NMR measurements of porosity, bound fluid volume, pore size distribution, and direct fluid identification can be applied to resolve the challenges mentioned above. We demonstrate the use of NMR data to calculate total and effective porosity, and volume of irreducible water in productive reservoir sands and in shales, to validate the petrophysical model. We also present a method based on NMR analysis to estimate net producible pay and its uncertainty. We apply fluid typing from NMR Relaxation and Diffusion maps to quantify small volumes of gas present in the water zone. This analysis enables us to calculate the fluids composition in the invaded zone and to improve the accuracy of density porosity, even when LWD and Wireline logs are combined. We also show how the NMR measurement of gas volume in the invaded zone can be correlated to sonic measurements for quantitative fluid substitution. We identify gas in thin and shaly reservoirs from NMR standalone fluid typing, and present examples of successful sampling with wireline tester in these elusive reservoirs. The various examples presented in this paper describe practical petrophysical methods used to improve the formation evaluation of shaly gas reservoirs in fresh formation water, and demonstrate how the NMR data can be integrated into an existing petrophysical analysis, improving the accuracy of results in this challenging environment.

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