The Effect of Fluid Properties and Stage of Depletion On Waterflood Oil Recovery
Authors: Arnold Marion D. , Hall Phillips C. , Crawford Paul B. 
Published: December 2007

Abstract
An experimental study has been made to determine the optimum flooding pressures for four different oils. The oil formation volume factors ranged fro in 1.08 to 2.13, and solution gas-oil ratios ranged from about 200 cu ft/bbl to 2,250 cu ft/bbl. Viscosities ranged from 0.38 to 0.95 cp at the respective bubble points of the fluids and from 0.7 to 20 cp at atmospheric pressure. Water floods were conducted at various pressure levels from run to run. The recovery as a junction of flooding pressure was found to be different for each fluid, with optimum gas saturations ranging fro in 7 up to 35 per cent. The data indicate that substantially higher recoveries may be obtained if water floods are conducted at an optimum pressure and that this optimum pressure is a function of fluid properties. The same core was used for all tests, and the reproduction of saturations for various runs indicates that wettability in the predominantly water-wet core did not change.

Introduction
A paper was presented by Bass and Crawford which described an experimental study of the effects of flooding pressure and rate on oil recovery by water flooding. This work was conducted using high-pressure models operated in a manner similar to that of an actual reservoir, with gas saturations being obtained by a solution-gas-drive mechanism. They found that the greatest oil recovery was obtained for the system studied by flooding in the presence of a 5 to 7 per cent gas saturation. Another experimental study simulating field conditions was presented by Richardson and Perkins. They used an unconsolidated sand pack containing kerosene- natural gas fluid and interstitial water. They flooded at various pressures and flooding rates. For their system it was found that the recovery was independent of the pressure level at which the water flood was performed. Kyte, et al, found that oil recovery by water flooding was increased as the free gas saturation at waterflood initiation was increased. However, after the initial gas saturation was increased above 15 per cent, the increase in oil recovery tended to level off. All of their runs were made at the same pressure using a light oil saturated with helium. The desired gas saturation was obtained by injecting helium into the core. Dyes made calculations which showed that an optimum gas saturation of 12 to 14 per cent may result in an increase in oil recovery of 7 to 12 per cent over that obtained by flooding at the bubble-point pressure. Others have also found that the presence of a free gas saturation may increase the waterflood oil recovery. In each case shrinkage was small and changes in fluid properties with respect to pressure were small. A careful review of the literature reveals that at the present time there is a wide difference of opinion on the factors affecting waterflood recoveries. This diversity of opinion is probably due to the fact that very little research has been done which has taken into account the many variables existing in an actual field being water flooded. Since the literature contains little information on high-pressure waterflooding studies using various types of reservoir fluids, it was believed appropriate that such a study should be made.

EQUIPMENT AND PROCEDURE
All tests were made using the same consolidated sandstone core. Torpedo sandstone was used to turn a cylindrical core 13.5-in. long and with a 2.92-in. average diameter. The core had a porosity of 28 per cent and a permeability to brine of 146 md. This brine was made up by adding 20,000-ppm sodium chloride and 30,000-ppm sodium nitrite to distilled water. This was used as connate water and flooding water. No fresh water was ever brought in contact with the core, as tests showed the sandstone contained argillaceous material which swelled in the presence of fresh water and plugged the stone. The core was sealed in a section of 6-in. N–80 tubing with Woods metal filling the annulus. The core was mounted horizontally; an injection well was placed in the center of one end and a production well in the center of the other. Pressure control was maintained by placing a back-pressure regulator (upstream control) on the producing well. The "live" oil was stored in a separate bottle and water was injected into this bottle to displace the oil for saturating the core using a two- cylinder standard-proportioning pump. This same pump was used for water flooding the core at a constant rate.
JPT
P. 1165^