Hydrocarbon saturation and viscosity estimation from NMR logging in the belridge diatomite

Nuclear Magnetic Resonance (NMR) logs have been recorded in Shell's North Belridge Diatomite and Brown Shale using an experimental logging tool, the CMR^∗ Combinable Magnetic Resonance tool. The CMR tool successfully logged porosity and T₂-distributions over 1500 ft of formation. In the Diatomite and Brown Shale formations, the CMR porosity is a measure of the total liquid filled porosity even in this tight lithology because of the high signal-to-noise ratio and short interecho spacing (320 μsec). CMR porosity values were found to be in good agreement with core porosity, even in zones with appreciable gas saturation, indicating complete flushing of the gas within the depth of investigation of the tool. T₂-distributions from both the borehole and lab measurements are distinctly bimodal, with the shorter T₂ peak at about 10 msec originating from water in contact with the diatom surface and a longer T₂ peak at about 150 msec originating from the light oil. The T₂ of the oil peak correlates roughly with oil viscosity. This indicates that the Diatomite is predominantly water wet. The water and oil peaks are well separated in the light oil zones, which allows estimation of oil saturation by integrating the T₂- distribution beyond a certain cutoff. The assignment of the oil peak and selection of the T₂ cutoff was determined by laboratory NMR measurements on native state cores after diffusing in D₂O to eliminate the water signal. Because of the tight lithology and good fluid loss control, estimates of oil saturation from the shallow-reading CMR tool are in good agreement with resistivity logs and core analysis. T₂-distributions have been measured on 31 crude oil samples from Belridge spanning a range of viscosities from 2.7 to 4300 cp. The CMR estimate of oil T₂ correctly predicts oil viscosity and shows that the upper 150 ft of Diatomite formation in this well undergoes a transition to heavier oil.