Wettability, Saturation, and Viscosity Using the Magnetic Resonance Fluid Characterization Method and New Diffusion-Editing Pulse Sequences

Abstract

Abstract This paper discusses a new nuclear magnetic resonance (NMR) method that canprovide wettability, saturation, and oil viscosity values in rocks partially saturated with oil and brine. The method takes advantage of two new technological advances in NMR well logging - the MRF* Magnetic Resonance FluidCharacterization Method and NMR "diffusion-editing" (DE) pulse sequences. Wediscuss the principles underlying the fluid characterization method and thepulse sequences. The fluid characterization method is used to provide robustinversions of DE data suites acquired on fully brine-saturated and partially saturated rock samples. The outputs of the inversion are separate diffusion-free brine and oil T2 distributions for the fluidsmeasured in the rocks. NMR measurements on partially saturated rocks are sensitive to wettability because of surface relaxation of the wetting phase fluid. The surface relaxation rate, however, must be significant compared to the bulk relaxation rate in order for wettability to noticeably affect the NMR response. We present results showing that the surface relaxation rate at lower wetting phase saturations is enhanced compared to that measured at higher saturations. Theconsequence of wetting-phase saturation on NMR-based wettability determinationis discussed. Wettability affects the relaxation rates of both the wetting and nonwetting phases in partially saturated rocks. Surface relaxation of thewetting phase in a rock results in shorter relaxation times than would otherwise be observed for the bulk fluid. The nonwetting phase fluid moleculesdo not come into contact with the pore surfaces and therefore their relaxation rate in the rock is the same as in the bulk fluid. We present accurate and robust computations of diffusion-freeT2 relaxation time distributions for both the wetting and nonwetting phases in four rocks that include two sandstones and two dolomites.A DE data suite was acquired on each rock measured in two different partial saturation states and also fully brine saturated. Wettability is determined bycomparing the oil and brine T2 relaxation time distributions measured in the partially saturated rocks with the bulk oilT2 distribution and with the T2distribution of the fully brine-saturated sample. The brine and oil T2 distributions are used to compute saturation and oil viscosityvalues. A general discussion elucidating the sensitivity range andT2 limits of diffusion-based NMR methods is given in the appendix. The appendix also derives and displays the gain in signal-to-noiseratio that is achieved by using DE data sequences for fluid characterization inplace of Carr-Purcell-Meiboom-Gill (CPMG) data suites. Introduction This paper discusses a new nuclear magnetic resonance (NMR) method for determining wettability, saturation, and viscosity values in partially saturated reservoir rocks. It has potential applications to wettability interpretation in native-state cores measured in the laboratory as well as to measurements made downhole by an NMR logging tool. Previous methods for determining wettability of partially saturated rocks, including NMR methods, are limited to laboratory measurements.