Page 320 - Petrophysics 2E

FORMATION EVALUATION 29 1

a compaction correction factor, B,, as follows:

t-tm 1
Os= (tfl-tm) B,, (4.153)

The compaction correction factor is equal to:

(4.154)

where 100 is the travel time for compacted shale in yslft and tsh is
the sonic travel time of an adjacent shale. The normal range of B,, for
sandstone formations is from 1 to 2. When no compaction correction
is used, B,, = 1. The factor Bsh, which is empirically determined, is
a function of shale (clay) type. The lack of compaction is indicated when
adjacent shale beds exhibit a sonic travel time greater than 100 ps/ft. In
shaly (clayey) unconsolidated formations, the sonic porosity is calculated
from the following equation:

(4.155)

where v,h is the shale (clay) volume. In formations, consolidated or
unconsolidated, bearing oil or gas, the calculated sonic porosity tends to
be high and the following empirical correction can be used:

@ = Bhc@s (4.156)

where $s is obtained either from Equation 4.153, for clean unconsolidated
formations, or from Equation 4.155, for shaly (clayey) unconsolidated
formations. The factor Bhc may be empirically set at 0.90 for oil and 0.70
for gas. These constants seldom give good results, as Bhc depends on the
type of mud, depth of mud invasion, pore pressure, etc.
From the formation evaluation standpoint, the main objective of the
density log is the determination of formation porosity by measuring
the bulk density of the reservoir rock. In the case of saturated porous
rocks, bulk density includes the density of the fluid in the pore spaces
as well as the grain density of the rock. For a clean formation of known
matrix density, pma, having a bulk density Pb, and which contains a fluid
(except gas and light hydrocarbons) of average density, pn, the formation
porosity is equal to:

(4.157)