ABSTRACT

Producibility estimates in carbonate formations have always been a challenge for log interpretation. Broad pore size distributions in carbonates, from microcrystalline to large vugs, have a large effect on productivity, permeability, and estimation of hydrocarbon saturation from resistivity logs. In mixed complex carbonates it is even difficult to obtain accurate porosities from conventional wireline logs without calibration against core. An experimental logging tool, the CMR Combinable Magnetic Resonance tool, has been evaluated in the Glorieta and Clearfork carbonates in West Texas. The logged interval is complicated by significant amounts of separated vuggy porosity. The lithologies consist of dolomite, limestone, anhydrite and clastic material (silt containing quartz, feldspar and clay). The CMR porosity is derived independent of formation lithology. In the clean mixed carbonates, the CMR porosity is equal to total porosity. In the silt zones, the CMR porosity measures the effective porosity because it is insensitive to microporosity associated with the clastic material. Using the CMR free fluid porosity, the producing oil-water contact was identified in this well, which was difficult to determine using the conventional wireline logs alone. Twenty-seven core plugs from the well were analyzed by low field NMR (nuclear magnetic resonance) and conventional core analysis. Estimates of producible fluid obtained from the T2 distributions using a free fluid cutoff of 92 milliseconds agreed with centrifugeable fluid from the plugs. Petrophysical properties depending on the relative amounts of intergranular and vuggy porosity were found to be well correlated with the long end of the NMR. T2 distributions. Permeability estimation from the porosity with T2 < 750 msec using the relation k ~ ?4 T22 was superior to that based on total porosity. Finally, the cementation exponent m was found to increase with the fraction of long T2 porosity.

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