A Novel Single-Well Field Test of a Micellar Solution Slug

Abstract

The performance of a micellar solution slug displaced by thickened water was inexpensively and quickly evaluated in a novel single-well test. Oil saturation analyses on eight post-test cores permitted the construction of an oil-displacement-efficiency vs slug-size curve. Introduction Several field tests of the Maraflood* oil recovery process have been conducted since its inception in 1961. process have been conducted since its inception in 1961. Most of the test patterns have been regular or inverted five-spots with several back-up wells outside the pattern. While these tests indicate flooding performance pattern. While these tests indicate flooding performance and give complete injection and production histories, they are costly, require at least 2 years to complete, and are difficult to analyze. Laboratory work on micellar solutions containing high water concentrations produced slug compositions that performed sufficiently well in the laboratory to warrant testing in the field. In April, 1968, a feasibility study of conducting such a test was undertaken. To avoid the high cost and long completion time required by the more conventional pilot patterns, a project consisting of a single injection well and no production wells was proposed, with the objective of evaluating the new micellar solution's injectability and capacity to displace oil. The test was approved, and slug injection into a watered-out reservoir sand near Robinson, III., began on Oct. 1, 1969. Eight months later the test was completed, including the drilling of eight core tests. Displacement performance was evaluated by using core-test oil saturations. Test-Site Information The test was located on the Henry lease in the Robinson sand in Crawford County, III. The test area had originally been developed in 1906 with primary production by solution gas drive. The primary production by solution gas drive. The field was then produced on vacuum and by air repressuring in the 1940's. In 1957 waterflooding was started, which reduced the oil saturation in the area from 55 to about 40 percent. This post-waterflood oil saturation value was determined from a material balance, from water-flood calculations, and from pressure interference tests, as detailed in another paper. pressure interference tests, as detailed in another paper. The Robinson sand is a moderately water-wet, fluvial, lower Pennsylvanian deposit. The top of the formation is at a depth of 975 to 980 ft, and the sand thickness averages about 30 ft in the region of the test well, Reservoir porosity averages 20 percent, and the permeability ranges from about 100 to 300 md. permeability ranges from about 100 to 300 md. Bottom-hole pressure and temperature at the start of the test were respectively 50 psig and 72 degrees F. The reservoir crude has a viscosity of 7 cp and a gravity of 36 degrees API. Salinity of the reservoir water before the test was about 20,000 ppm total dissolved solids (TDS). Field Operations A new fluid injection well, HWCI-1, was drilled for the test. Casing was set at 978 ft at the top of the formation. The well was completed open hole through the sand to a total depth of 1,007 ft, and was equipped with a surface recording bottom-hole pressure gauge. An existing oil well, FW-7, located 50 ft due north of HWCI-1, was also equipped with a surface recording bottom-hole gauge. It was used as an observation well for pressure response only. JPT P. 1371