The Retention of Connate Water In Hydrocarbon Reservoirs

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Abstract
The application of capillary pressure data to the determination of connate water distributions hydrocarbon reservoirs is reviewed. Generally, it has been assumed that the reservoir will be at capillary equilibrium after geologic time. Comparisons of experimental capillary pressure data for sphere packings with model calculations show that the former do not represent capillary equilibrium. at the irreducible saturation. In estimating equilibrium data for the reservoir. Leverett assumed that equilibrium would he achieved after geologic time and corected experimental data for clean sands accordingly. Subsequently, the equilibrium theory was accepted, but it was assumed that experimental capillary pressure data represented equilibrium and corresponded to the distribution in the reservoir. The fair agreement of water saturations of cores taken with oil-base muds from above the transition zone with laboratory-measured irreducible saturations was claimed as support for the equilibrium theory. In fact, this agreement is strong evidence that the reservoir does not drain to a capillary equilibrium distribution even after geologic time. The basis for using capillary pressure tests must therefore rest larger on the fair empirical agreement observed between water saturations of cores taken with oil-base muds and the irreducible saturations of these cores. Capillary equilibrium can be expected in the transition zone, but the prediction of fluid distribution in this zone is uncertain because of capillary pressure hysteresis. Furthermore, the saturation distribution in this zone cannot be determined directly by coring because both fluid phases are mobile. Introduction A Substantial Fraction of the pore space in an oil reservoir is occupied by water. This water is especially significant to property evaluation and the estimation of petroleum reserves. For over thirty years, researches have been directed toward establishing a satisfactory method of determining the connate water saturations of oil reservoirs, and there is now an extensive literature on oilfield water. In this paper, the theoretical basis of the methods which are now in general use will be examined. It was not immediately obvious to the early oil producers that sands which produced water-free oil also contained connate water. In a brief history of the discovery of interstitial water in oil sands, Torrey(1) relates how evidence of substantial water saturations in sands which produced clean oil was at first discounted on the grounds that the pressure drop causing oil flow should also act on the water and cause it to be produced along with the oil Water found in cores was usually believed to have come from the drilling mud. When-cores taken with an oil-base mud were also found to contain water(2–11), the presence of interstitial water in oil sands was generally accepted. Furthermore, as the connate water was immobile, it was assumed that analysis of the fluid content of cores cut with oil-base mud should give accurate values of reservoir water saturation. However, the expense and inconvenience of using oil-base muds in coring led to a search for alternative methods of determining water saturation.

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