Page 85 - Reservoir Formation Damage

68 Reservoir Formation Damage

A practical approach to quantify wettability is to facilitate the work
involving the fluid displacement processes (Sharma, 1985). As stated by
Grattoni et al. (1995), the displacement process is referred to as imbibition
when the wetting phase saturation increases and drainage when the
wetting phase saturation decreases. The work of displacement per unit
bulk volume is equal to the area indicated by the capillary pressure curve
(Yan et al., 1997):

(4-1)

Therefore, Donaldson et al. (1980) have alleviated the difficulty of
defining the wettability of porous media in a practical manner, by defining
+
a wettability index as the logarithm of the ratio of the areas, A and A~,
of the capillary pressure curve above and below the zero capillary
pressure line, as [the USBM Method by Donaldson and Crocker (1980)]

+
WI = Iog 10 (A 1 A~) (4-2)
Thus, according to Equation 4-2, porous materials are classified
as following:

1. WI > 0, water-wet,
2. WI ~ 0, intermediately-wet, and
3. WI < 0, oil-wet.

Many studies have reported wettability variation during formation damage
due to alteration of pore surface characteristics by rock, fluid, and particle
interactions. Figure 4-1, by Donaldson (1985), shows that the capillary
pressure curves of the sandstone and therefore the wettability variation
by clay fines plugging.
Alternatively, the wettability can be expressed in terms of the Amott
(1959) indices to water and oil. As stated by Jerauld and Rathmell (1997),
"The Amott (1959) index of a phase is defined by the ratio of the volume
spontaneously imbibed to the sum of that imbibed and forced." Thus,

; j = water or oil (4-3)

Then, the Amott-Harvey wettability index is defined as:

(4-4)