Page 240 - Standard Handbook Petroleum Natural Gas Engineering VOLUME2

Formation Evaluation 209

The constant 7,758 is the number of barrels in each acre-ft, V, is bulk volume
in acre-ft, $ is the porosity, (QV, is pore volume), S, is the initial oil saturation,
B, is the initial oil formation volume faaor in reservoir barrels per stock tank barrel,
A is area in ft2, h is reservoir thickness in ft, and S, is the initial water saturation.
In addition to the uncertainty in determining the initial water saturation, the
primary difficulty encountered in using the volumetric equation is assigning the
appropriate porosity-feet, particulary in thick reservoirs with numerous non-
productive intervals. One method is to prepare contour maps of porosity-feet
that are then used to obtain areal extent. Another method is to prepare isopach
maps of thickness and porosity from which average values of each can be
obtained. Since recovery of the initial oil can only occur from permeable zones,
a permeability cutoff is used to obtain the net reservoir thickness. Intervals with
permeabilities lower than the cutoff value are assumed to be nonproductive.
The absolute value of the cutoff will depend on the average or maximum
permeability, and can depend on the relationship between permeability and
water saturation. A correlation between porosity and permeability is often used
to determine a porosity cutoff. In cases in which reservoir cores have been
analyzed, the net pay can be obtained directly from the permeability data. When
only logs are available, permeability will not be known; therefore a porosity
cutoff is used to select net pay. These procedures can be acceptable when a
definite relationship exists between porosity and permeability. However, in very
heterogeneous reservoirs (such as some carbonates), estimates of initial oil in
place can be in error. A technique [222] has been proposed in which actual
pay was defined using all core samples above a specific permeability cutoff and
apparent pay was defined using all core samples above a specific porosity cutoff;
the relationship between these values was used to find a porosity cutoff.
Initial Gas In Place

For the foregoing case of an undersaturated oil (at the bubble point with no
free gas), the gas in solution with the oil is:

7,’758AhQ(l -S,)R,
G= (5-126)
B,

where G is the initial gas in solution in standard cubic feet (scf), R, is gas
solubility in the oil or solution gas-oil ratio (dimensionless), and the other terms
are as defined in Equation 5-125.
Free Gas In Place

Free gas within a reservoir or a gas cap when no residual oil is present can
be estimated

7,758Vg$(1 - S,)
G= (5- 1 27)
B,

where 7,758 is the number of barrels per acreft, V, is the pore volume assigned
to the gas-saturated portion of the reservoir in acre-ft, B, is the initial gas
formation volume factor in RB/scf, and the other terms are as already defined.
(Note: If the formation volume factor is expressed in ft*/scf, 7,758 should be
replaced with 43,560 ftJ/acre-ft.)