Page 460 - Petrophysics

428 PETROPHYSICS: RESERVOIR ROCK PROPERTIES

contribute to the filling process. This leads to fractures with porosities
ranging from very small to 100%. In addition, the connate water saturation
in these fractures can be zero or 100% depending on the preferential
wettability of the reservoir rock.
Equation 7.34 is, therefore, valid only for the case where the fracture is
totally open and clean of any filling particles, i.e., @f = 1. It also assumes
that the connate water saturation in the secondary pores is zero, or
So = 100% such as in reservoirs where the oil entered into a tight, oil-wet
formation by upward migration along fractures from deeper zones. The
Ain Zalah oil field, Iraq, appears to be such a reservoir [12]. In cases
where @f < 1 and Swcf > 0, Equation 7.34 must be modified. However,
determining the values of the fracture porosity and the connate water
saturation within the fracture is difficult even with whole core analysis,
because cores tend to break along the natural fracture plane as they
are brought to the surface. In addition, many fractures form during the
process of core recovery. The most common laboratory technique for
estimating directly the matrix and fracture porosity was presented in
1950 by Locke and Bliss [ 133. The actual permeability of the fracture can
be determined from the equation of actual velocity of the fluid flowing
through the fracture:

(7.35)

where @f is the fractional porosity of the fracture and Swcf is the connate
water saturation in the fracture. By definition:

(7.36)

The apparent velocity from Equation 7.35 is:

where the actual velocity is expressed as the actual rate of fluid flow
through the fracture divided by the fracture area, or:

(7.38)

and the flow rate q is expressed by Equation 7.3 1. Substituting for Va and
q in Equation 7.37 gives:

(7.39)