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Description
Exaggeration of non aqueous phase liquid (NAPL) hydrocarbons in monitoring wells is a long-recognized phenomena. Early models (Hall et al, 1984) suggest that this exaggeration occurs because hydrocarbon saturation occurs in a layer above the groundwater capillary fringe. Pore space below the top of the groundwater capillary fringe was assumed to be fully saturated with water. More recent work by Lenhard and Parker (1990) and Farr et al (1990) shows that, under equilibrium conditions, hydrocarbon NAPL does not occur as a distinct layer above the groundwater capillary fringe, but the hydrocarbon saturation in the formation increases from the oil/water interface up to (and slightly above) the oil/air interface in a monitoring well. The degree of hydrocarbon NAPL saturation was shown to be a function of the apparent thickness of hydrocarbon in a monitoring well, the height above the oil/water interface, and the capillary pressure/saturation characteristic curve of the soil. The difference between the two conceptual models is significant, particularly with respect to hydrocarbon mobility. The work of Wallace and Huntley (1992) indicates that typical hydrocarbon saturations expected for the fine-grained Bay Point Formation of San Diego are approximately 5% to 20% for one meter of apparent hydrocarbon NAPL thickness. These low saturations imply relative hydrocarbon NAPL permeabilities that are several orders of magnitude less than the permeabilities expected for a hydrocarbon saturated soil. To test these models and their implications with respect to hydrocarbon NAPL mobility, five boreholes were drilled in a hydrocarbon-contaminated area of downtown San Diego that was underlain by the Bay Point Formation. Apparent hydrocarbon NAPL thickness varied from zero to over five feet in the monitoring wells. Up to eight feet of continuous core was obtained form each of the boreholes and split into 0.1 foot intervals. Alternating 0.1 foot samples were analyzed for total petroleum hydrocarbon, and the remaining samples were stored for grain-size analysis and measurement of capillary characteristic curves. In addition, slug-withdrawal tests were conducted on the hydrocarbon intervals and constant-rate discharge tests were conducted on the water saturated intervals of the monitoring wells. These data were used to compare measured hydrocarbon saturations and total volume with those predicted by both models. They were also used to assess the relative permeability of the hydrocarbon NAPL contaminated interval. The results show typical hydrocarbon saturations of 5% to 20%, with one borehole showing a limited zone of up to 50% saturation. Hydrocarbon NAPL mobility (relative permeability) is greatly reduced due to the low saturations, as predicted by capillary theory. These observations are consistent with very low recoveries using hydrocarbon skimming systems. Theoretical hydrocarbon NAPL volume predictions compared favorably with measured total volumes in wells with free product, but predicted no hydrocarbon in wells with measurable low saturations and no free product. Recent water level changes due to offsite dewatering have induced non-equilibrium conditions on the site.
