Page 76 - Geology of Carbonate Reservoirs

SATURATION, WETTABILITY, AND CAPILLARITY 57

V g
S g =
V p

Saturations are expressed as percentages totaling 100%, or S w + S o + S g = 100. In

plain terms, saturation is the amount of fluid in the pores expressed as a percentage
of the total pore volume. In conventional literature, water in reservoir rocks is
described as connate water , or interstitial water remaining from the time of deposi-
tion. This interstitial water occupies pores and coats grains. Because of chemical
interactions between water and rock during burial, and because formation waters
are expelled during compaction or tectonism, reservoir water saturation is really
immigrant diagenetic water rather than true connate water. Widely varying amounts
and kinds of salts and trace elements in reservoir waters testify to the mobility of
basinal liquids, as do the many episodes of late burial diagenetic change that are
documented in most reservoir rocks.
Water saturation, S w , depends on pore and pore throat size, aperture size distribu-
tion, and elevation above the free - water level. For oil or gas to enter the reservoir,
it must displace the interstitial water. If the pore volume is sufficiently large, oil will

displace water and reside in the pore centers (Figure 3.1 ), but it cannot displace
water from small pores or from coatings on grain surfaces. That unmovable water

is the wetting fluid. Reservoirs may include oil, water, and gas and which phase

becomes the wetting fluid is determined by wettability , a phenomenon associated
with the capillary properties of reservoir rocks. Most reservoirs are considered to
be water - wet, but oil - wet reservoirs do exist, notably in some carbonate rocks. As
water remains in small pores and on grain surfaces, it follows that large pores such
as vugs and intergranular pores in coarse - grained rocks have lower values of S w , and

fine - grained rocks have higher values. Oil saturation is just the opposite: lower in

fine - grained rocks and higher in coarse - grained ones. Qualitatively, an S o of about
80% indicates a productive zone in the reservoir (Figure 3.2 ), S o in the range of 50%
represents the transition zone , and S o of 10 – 20% represents the water - bearing zone
(Monicard, 1980 ). In sum, S o determines which zones are productive and which are

not. S o is represented by (1 − S w ) in oil - water systems and S w is calculated from

Grains

Water
Oil Water
Oil
Grains
Water-Wet Oil-Wet
Figure 3.1 Idealized representation of water - wet and oil - wet reservoirs with depositional,
interparticle porosity. All rocks had to be water - wet originally, but some became oil - wet after
hydrocarbon migration, and surface chemical reactions between the hydrocarbons and the
pore walls caused the rock to become oil - wet. This is especially true of carbonate reservoirs
with oils containing polar organic compounds that react with carbonates.