Coring for Reservoir Connate Water Saturations
Authors: Jenks L.H. , Huppler J.D. , Morrow N.R. , Salathiel R.A. 
Published: December 2007

Coring with oil-base muds is generally accepted as the most reliable method for determining connate water saturations above the transition zone in an oil reservoir. The basis for using less expensive, indirect methods, such as capillary pressure tests rests largely on empirical agreement with cores taken using oil-base mud. Hence, testing the validity of this coring procedure is vital. procedure is vital. In coring for connate water with oil-base mud, the mechanism most likely to produce inaccurate determinations is flushing of water from the rock matrix by high pressure gradients near the bit. We know that similar flushing can occur when coring for residual oil saturations with water-base muds. However, wetting and nonwetting residual phase saturations are held by the rock in distinctly different ways. In preferentially water wet rocks, connate water is held as preferentially water wet rocks, connate water is held as hydraulically isolated volumes retained in finer pores by capillarity. Residual oil, however, is trapped in the larger pores as discontinuous globules which are not strongly attached to rock surfaces. Thus, we might expect that, during coring, flushing of connate water would be considerably less severe than flushing of residual oil. To test this hypothesis, we conducted two flooding experiments. In the first, a Berea sandstone core containing normal waterflood residual oil was further waterflooded at differential pressures sufficiently high that significant amounts of additional oil were flushed from the core. Results of this experiment are presented as the oil curve in Fig. 1. In the second experiment, a separate Berea core containing normal oilflood residual water was further oil flooded over the same range of pressure gradients employed in the first experiment. The results the brine curve in Fig. 1showed that comparatively little additional water was flushed from the core. To further test the hypothesis, we conducted two microbit coring experiments to compare degrees of residual phase flushing when coring for residual oil and for residual water. (A comprehensive study of coring for residual oil saturation with water-base muds has been reported in Ref. 1, which contains experimental details.) We prepared one rock section for coring by flooding with brine at the relatively low pressure gradient of 100 psi/ft until no more oil was pressure gradient of 100 psi/ft until no more oil was produced. We then cored the rock section, with a produced. We then cored the rock section, with a 200-psi borehole pressure differential, using brine as the coring fluid. Similarly, we flooded a second rock section with oil, at 100 psi/ft, to residual brine saturation, then cored, with oil as the coring fluid, with a 200-psi borehole differential pressure. During coring of the rock section containing residual water, pore pressure measurements along the rock section indicated that the entire rock was exposed to pressure gradients of about 1,500 psi/ft. Although pressure gradients of about 1,500 psi/ft. Although this gradient represents an extremely severe coring condition, water saturation in the core was reduced only 17 percent. In the comparable coring test using the rock section at residual oil saturation, the rock was exposed to pressure gradients of 900 psi/ft and residual oil saturation was reduced by 40 percent. Results of these laboratory flooding and coring tests show that, under similar conditions, coring for immobile water saturation is more reliable than coring for residual oil saturation. We previously demonstrated the feasibility of accurately coring for residual oil saturation by controlling the borehole to formation overbalance pressure. We conclude that controlled coring with oil-base mud should produce a satisfactory measurement of water saturation above the transition zone.
P. 932