Diffusion NMR on fluids contained in porous rock can be interpreted quantitatively in terms of oil saturation. This is a new application, which has proven to be very useful to supplement conventional saturation evaluations. This new method utilises the differences in molecular self diffusion between oil and water. The application requires at least two T2 decay measurements taken with different interecho spacings in a gradient magnetic field. The method has been applied successfully to the data recorded in wells that contain heavy oil. The NMR-derived saturations are in good agreement with core and log data, and have the advantage that core calibration is not required for each field; in this case available core data verified the method. A sensitivity analysis showed that saturations can be derived with an uncertainty of some 5 to 7 percent pore volume, provided that the oil and water diffusion coefficients differ by at least a factor of five. The uncertainty in saturation is mainly due to the noise level of the data, and may thus be further reduced by improvements in hardware. The NMR measured saturation is at a very shallow depth (typically 10 cm from the borehole) and is only representative of the virgin saturation if no, or only very shallow, invasion has taken place, or if the interval is at ?residual? oil saturation, e.g. after water flood. Interpretation of the ?standard? T2 data for distinguishing between bound water and movable fluid (water and/or oil) failed in the presented cases because of the short relaxation time of the viscous oil. Numerical simulation has shown that under most conditions encountered in sandstones the Free Fluid Index concept remains valid for oils with T2 greater than 50 ms, which corresponds to in-situ viscosities less than 20 cP.

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