Abstract
Laboratory benchtop nuclear magnetic resonance and mercury injection capillary pressure measurements were made on representative core plugs to facilitate rock property modeling of East Texas Jurassic Cotton Valley tight gas sandstones. NMR provides porosity data that is calibrated to downhole NMR and bulk density porosity measurements. Combined with mercury injection data, NMR provides information on the pore body -pore throat network characteristics of the reservoir sandstones. These data, combined with routine core data and petrographic observations, show that the Cotton Valley sands have low permeability, but that they are probably not capable of allowing water-free production.
Mercury injection data indicate that the bound (irreducible) water saturations in these rocks should be greater than 90% of the total Sw. This means that most of the water in the formation should be held in the reservoir by capillary forces and that gas production from these rocks should be relatively water-free. This is not the case.
NMR data indicate that there could be substantial water production with little gas flow. Combined data indicate that the reservoir sandstones have small to medium sized pores with small to medium pore throats. The rocks have low porosity and permeability overall, but are not tight enough to hold most of the formation water in the reservoir. Primary depositional facies, clay content, and subsequent diagenesis created complex pore geometry. NMR responses are controlled by the pore sizes; mercury injection behavior is controlled by pore throat diameters.
Improved permeability / petrophysical rock type models have been derived and used to calibrate downhole NMR measurements in both vertical and horizontal wells, resulting in improved recoverable gas in place estimates, fractional flow predictions, well targeting, and completion optimization in horizontal wells.
