Hamaca: Solution Gas Drive Recovery in a Heavy Oil Reservoir, Experimental Results

Abstract

Abstract Oil recovery greater than 10% OOIP in the Hamaca area of Venezuela's Orinoco heavy oil belt has been forecast based on field observations and experimental data.1,2 This high recovery can be modeled using drastically different mechanisms: a high critical gas saturation; a very low critical gas saturation combined with a large effective drainage area; or the formation of finely divided free gas that flows with its associated liquid. This paper details an experimental evaluation of solution gas drive recovery and the production mechanism present in the Hamaca region of the Orinoco heavy oil belt. Critical gas saturation data were collected using a sand pack filled with live Hamaca crude oil at reservoir conditions. The sand pack was 2 inches in diameter, 12 inches in length, and had a pore volume of 200 cc. Pressure depletion of the pore fluids was achieved with a sequence of small fluid expansions. A flow rate was picked to mimic the fluid flux at 1000 ft from a vertical well. Pore fluids were allowed to reach phase equilibrium after every expansion. Pore and produced fluid compressibility, produced fluid gas oil ratio and CT scanner derived gas saturations were measured after every expansion. As the pressure declined the produced fluid exhibited a decreasing GOR and a compressibility consistent with liquid while the sand pack fluids showed an increasing compressibility consistent with increasing gas saturation. Free gas production was observed by a simultaneous jump in the produced fluid GOR and compressibility and was also observed with CT scanner images. The CT scanner derived critical gas saturation was found to be 8.3 PV%. A material balance calculation indicated a critical gas saturation of 10.2 PV%. CT scanner images showed free gas accumulating in gas rich regions which were generally surrounded by oil with little free gas. Gas saturation in gas rich regions could reach 70 PV%. As gas saturation increased, gas rich regions began to connect until a network of high gas saturation traversed the length of the sand pack. CT scanner images taken at the beginning of free gas flow were used to visualize this connected network of high gas saturation. The experimental data show that the high solution gas drive recovery is the result of a high critical gas saturation. The data show that the high recovery is not associated to low critical gas saturation and a large drainage area. No finely divided foam or appreciable associated gas was observed in the produced fluid. When a 9 PV% critical gas was combined with oil compressibility and the expected formation compressibility, field performance predictions yielded a 12.5% OOIP oil recovery estimate.