The rapidly expanding use of carbon dioxide, CO2, to enhance the production of crude oil has given rise to reports of apparent formation damage covering a wide range of oil and reservoir properties from different parts of the United States. In 1979 research was initiated at New Mexico State University to define the causes and re-commend solutions to the CO2 formation damage problems. One plausible damage mechanism concerns the precipitation of organic particulates as CO2 dissolves in the reservoir crude.
Three crude oils from pilot CO2 tests were studied to determine their tendency to form precipitates at their respective reservoir pressure and temperature. The three crudes selected for study were a Wilmington crude (California), a Maljamar crude (New Mexico) and a Hilly Upland crude (West Virginia).
To estimate formation damage potential for individual crude oils, volumetric flow versus time through an 8 micron absolute filter has been recorded for the crude saturated with CO2 at temperatures in the range of 77°–123°F (25°–50.5°C) and at pressures in the range of 300–1800 psig (3–18 MPa). The results, surprisingly, show no correlation with the asphaltic content of the crude, previously determined by inducing precipitation by the addition of either pentane or hexane to the crude.
Maljamar crude oil was the only crude that produced CO2 precipitated organic type particules. This crude was subjected to tests in an unconsolidated sand-pack to quantify its damage potential. Under tertiary recovery conditions a permeability reduction of 25% was observed even after 29% of the residual oil had been displaced. Under conditions simulating CO2 secondary recovery (no previous waterflood) some permeability reduction was observed. The relative permeability to water at residual oil saturation was 34% lower using CO2 as a secondary recovery phase as compared to a conventional waterflood.