Oil Recovery by Surface Film Drainage in Mixed Wettability Rocks
Material-balance data on the East Texas reservoir indicate that a very efficient water-oil displacement is being attained. Also, cores recovered with a pressure-retaining core barrel from watered-out parts of this reservoir indicate very low (less than 10 percent) residual oil saturations. This paper describes a systematic examination of mechanisms and conditions that can lead to such an unusually efficient displacement of oil by water. Experimental studies conducted to test a postulated mechanism are reported, and the significance and applicability of the mechanism are discussed.
A High-Efficiency Waterflood
Richardson et al., observed that waterflood tests on core samples from the Woodbine reservoir, East Texas field, behaved very differently when the cores were extracted rather than tested “fresh” from the core barrel or in a preserved condition. For example, they found that restored-state waterfloods on fresh East Texas cores normally leave 15 to 18 percent pore volume (PV) of oil after about 40 PV of water injection. This compared with oil residuals of about 30 percent PV in extracted cores after flooding. Values for average residual oil saturation in the reservoir estimated by material balance also fell in the range of 15 to 18 percent PV. Judging from this average range, even lower local residual saturations might occur in some parts of tie reservoir. This expectation was later verified when many of the pressure cores recovered from 20 ft or more below the present water/oil contact were found to contain less than 10 percent PV of oil. In subsequent laboratory displacement tests, it was found that residual oil saturations in preserved East Texas Field cores could be reduced to less than 10 percent PV by either of two methods – extended waterflooding (several hundred to several thousand pore volumes) or extended centrifuging under brine. Results of these tests showed that a small but finite permeability to oil exists even at very low oil saturations. This unusual flow behavior appears to depend on the wetting condition existing in this formation, since extracting fresh cores altered their flow behavior greatly. Causes for this flow behavior in fresh cores can be postulated by considering types of wetting conditions that might provide paths for oil to flow at low saturation, especially types of wetting that might occur naturally in a typical reservoir.