M. Flaum

Diffusion-relaxation distribution functions of sedimentary rocks in different saturation states

We present diffusion-relaxation distribution functions measured on four rock cores that were prepared in a succession of different saturation states of brine and crude oil. The measurements were performed in a static gradient field at a Larmor frequency of 1.76 MHz. The diffusion-relaxation distribution functions clearly separate the contributions from the two fluid phases. The results can be used to identify the wetting and non-wetting phase, to infer fluid properties of the phases, and to obtain additional information on the geometrical arrangement of the phases. We also observe effects due to restricted diffusion and susceptibility induced internal gradients.

Wettability, Saturation, and Viscosity From NMR Measurements

This paper discusses a new nuclear magnetic resonance (NMR) method that can provide 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 Fluid Characterization Method and NMR “diffusion-editing” (DE) pulse sequences. We discuss the principles underlying the fluid characterization method and the pulse sequences. The fluid characterization method is used to provide robust inversions 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 fluids measured 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. The consequence of wetting-phase saturation on NMR-based wettability determination is discussed. Wettability affects the relaxation rates of both the wetting and nonwetting phases in partially saturated rocks. Surface relaxation of the wetting phase in a rock results in shorter relaxation times than would otherwise be observed for the bulk fluid. The nonwetting-phase fluid molecules do 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-free T2 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 brinesaturated. Wettability is determined by comparing the oil and brine T2 relaxation-time distributions measured in the partially saturated rocks with the bulk oil T2 distribution and with the T2 distribution of the fully brine-saturated sample. The brine and oil T2 distributions are used to compute saturation and oil viscosity values. A general discussion elucidating the sensitivity range and T2 limits of diffusion-based NMR methods is given in the appendix. The appendix also derives and displays the gain in signal-to-noise ratio that is achieved by using DE data sequences for fluid characterization in place of Carr-Purcell-Meiboom-Gill (CPMG) data suites.

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

This paper discusses a new nuclear magnetic resonance (NMR) method that can provide 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 Fluid Characterization Method and NMR “diffusion-editing” (DE) pulse sequences. We discuss the principles underlying the fluid characterization method and the pulse sequences. The fluid characterization method is used to provide robust inversions 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 fluids measured 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. The consequence of wettingphase saturation on NMR-based wettability determination is discussed. Wettability affects the relaxation rates of both the wetting and nonwetting phases in partially saturated rocks. Surface relaxation of the wetting phase in a rock results in shorter relaxation times than would otherwise be observed for the bulk fluid. The nonwetting phase fluid molecules do 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 diffusionfree T2 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 by comparing the oil and brine T2 relaxation time distributions measured in the partially saturated rocks with the bulk oil T2 distribution and with the T2 distribution of the fully brine-saturated sample. The brine and oil T2 distributions are used to compute saturation and oil viscosity values. A general discussion elucidating the sensitivity range and T2 limits of diffusion-based NMR methods is given in the appendix. The appendix also derives and displays the gain in signal-to-noise ratio that is achieved by using DE data sequences for fluid characterization in place of Carr-PurcellMeiboom-Gill (CPMG) data suites.

Effects of OBM Invasion on Irreducible Water Saturation: Mechanisms and Modifications of NMR Interpretation

In this study, the effects of synthetic oil base mud (OBM) surfactants (emulsifiers and oil-wetting agents) on wettability alteration, NMR response and irreducible water saturation (Swir) were systematically examined with Berea and limestone cores. Results show that the originally strongly water-wet Berea and limestone cores are altered to be intermediate-wet or oil-wet by OBM surfactants. As a result, Swir from NMR T2, cutoff model with the default assumption of water-wetness generally underestimates the measured value. The magnitude of underestimation depends on three parameters: the type of OBM surfactants, their concentration in the flushing fluid, and the flushing volume. The magnitude of underestimation correlates with the Amott-Harvey wettability index. These results suggest that the effects of OBM invasion on estimation of Swir can be minimized by controlling the volume of OBM invasion and the concentration of OBM surfactants. The mechanisms of Swir underestimation and modifications of NMR interpretation when wettability alteration occurs were investigated. In the case of an oil-bearing zone at irreducible water saturation, OBM invasion does not significantly decrease the actual Swir, but changes the water and oil relaxation time distributions due to wettability alteration. This is visualized by the diffusion editing technique. When wettability alteration occurs (water-wet to intermediate-wet or oil-wet), a T2, cutoff value larger than the one based on water-wetness is needed because the irreducible water relaxes at a longer relaxation time. Correlation between this modified T2, cutoff value and the Amott