Page 91 - Standard Handbook Petroleum Natural Gas Engineering VOLUME2

Basic Principles, Definitions, and Data 79

saturation is less than the critical value, gas is not mobile but does impede oil
flow and reduces km.
Three-phase relative permeabilities pertaining to simultaneous flow of gas,
oil, and water have been provided in the literature [ 19,501. Since the occurrence
of such three-phase flow in a reservoir is limited [20], relative permeabilities
for these conditions will not be discussed in this chapter, and the reader is
referred to other souxes [ 19,20,137,140,159,160~.
Based on the work of Corey [150] and Wyllie [23,50], empirical equations
have been summarized by Slider [20] to estimate relative permeabilities. These
equations permit the estimation of k, from measurements of k,. Other empirical
equations for estimating two-phase relative permeabilities in consolidated rocks
are available in the literature [lsl].
Early work in unconsolidated sands showed that fluid viscosity or the range
of permeability had negligible effects on the relationship between relative
permeability and fluid saturation [76,100]. Geffen et al. [141] confirmed that
relative permeabilities in cores are not affected by fluid properties provided
wettability is not altered. However, others [ 162,1631 have found that viscosity
ratio influences relative permeability data when the displacing fluid is non-
wetting. For constant wettability conditions, the higher the viscosity of one of
the liquids, the lower is the relative permeability of the other liquid [163].
Geffen et al. [141] did cite a number of factors, in addition to fluid satura-
tions, that affect relative permeability results. Because of capillary hysteresis,
saturation history was important in that fluid distribution in the pores was
altered. Flow rates during laboratory tests need to be sufficiently high to
overcome capillary end effects (retention of the wetting phase at the outlet end
of the core) [141]. According to Wyllie [23], relative permeability varies because
of varying geometry of the fluid phases present, which is controlled by effective
pore size distribution, method of obtaining the saturation (saturation history);
heterogeneity of the core sample, and wettability of the rock-fluid system.
Controversy continues to exist regarding the effect of temperature on relative
permeabilities (for example see the discussion and prior citations in References
164 and 165). Miller and Ramey [164] observed no change in relative per-
meability with temperatures for clean systems, and speculated that for reservoir
fluid/rock systems, effects such as clay interactions or pore structure would need
to be considered. Honarpour et al. [165] summarized the effects of temperature
on two-phase relative permeabilities as measured by various researchers. In field
situations, the larger overburden pressure associated with greater depths may
be more important in affecting relative permeabilities than the associated
temperature increases. As with many other tests, relative permeability measurements
should be conducted at reservoir conditions of overburden pressure and tem-
perature with crude oil and brine representative of the formation under study.
Effect of Wettability on Fluid-Rock Properties
OH Recovery and Fluid Saturations. Since a reservoir rock is usually composed
of different minerals with many shapes and sizes, the influence of wettability
in such systems is difficult to assess fully. Oil recovery at water breakthrough in
water-wet cores is much higher than in oil-wet cores [106,110,166-1691, although
the ultimate recovery after extensive flooding by water may be similar, as shown
in Figure 5-56. These authors have shown that oil recovery, as a function
of water injected, is higher from water-wet cores than from oil-wet cores at
economical water-oil ratios. In 1928, Uren and Fahmy E1701 observed better
recovery of oil from unconsolidated sands that had an intermediate wettability,