Waterflood feasibility of the Brushy Canyon Formation: Red Tank field, Lea County, New Mexico
The U. S. Department of Energy estimates that 5 billion barrels of oil will remain in existing slope basin clastic reservoirs of the Permian Basin unless new and innovative recovery methods are implemented. This clearly highlights the need for operators to take a more comprehensive look into secondary recovery methods such as waterflooding. In this study, the author used a variety of tools to characterize this reservoir and to predict its response to water injection. Sequence stratigraphy was used to construct the geologic framework of the field. Scanning electron microscopy, X-ray diffraction, and thin section analysises were used to determine the bulk and clay mineralogy of the reservoir. Core analysis helped to determine Archie log parameters and net pay cutoffs needed in determining reserves from volumetrics. Analytical waterflood models recommended in SPE Monograph 3 were used to predict the reservoirs response to water injection.
Sequence stratigraphy indicated that the basal Brushy Canyon contains cyclic deposits. Five highstand and five lowstand deposits were identified in three wells along a 1-1/2 mile cross-section. These deposits were interpreted to have been transported by a variety of mechanisms during an overall drop in relative sea level within an intermediate-order cycle. The drop in sea level was most likely caused by glaciation with cyclic waxing and waning induced by Milankovic climate cycles.
Bulk mineralogy of this reservoir indicate it to be a subarkosic sandstone with quartz, K-feldspar, and carbonate cements comprising the major minerals. Clay mineralogy indicate that the average laboratory volume of clay is 11.6%, of which 55% is illite and 45% is iron-rich chlorite. The iron-rich chlorite renders this reservoir acid sensitive. There were no significant amounts of swelling clays detected.
Using a porosity-permeability transform a minimum core porosity cutoff for a minimum economic permeability of 1.0 md was 11%. Formation resisitivity factor measurements indicate a cementation exponent of 1.41 and an a coefficient of 1.28. A saturation exponent of 1.80 was obtained using a modified Maute method (1992). Relative permeability measurements indicate this reservoir to be uniformly water-wet. From the relative permeability curves it was noted that permeability to oil was insignificant at saturations above 50%. This value was used as the saturation cutoff in the net pay criteria. Using the Archie equation with the above parameters and cutoffs, along with a volume of clay cutoff less than 15%, the total reserves in the area studied were 9.07 MMstb.
Waterflood calculation indicate a mobility ratio of 0.33 and permeability variance of 0.3. Fractional flow calculations predict piston like displacement Predicted injection rates are low and should continually reduce throughout the life of the waterflood due to a low average permeability and low water mobility. Using the Dykstra-Parsons and modified Craig-Geffen-Morse methods the predicted waterflood reserves were 276.7 and 123.7 Mstb of oil per 40 acre five-spot pattern.