Page 204 - Standard Handbook Petroleum Natural Gas Engineering VOLUME2

Formation Evaluation 173

tmm, Apparent Matrix Density (ps/ft)
1 30 120 110 100 90 80 70 60 50 40 31 0
3 130

2.9 120

2.8 110
100 5
h
=L
u
90 F
w .-
80 E
s
2.4
d
Q
2.3

2.2 50

2.1 40

2 30
3 2.9 2.8 2.7 2.6 2.5 2.4 2.3 2.2 2.1 2
Pmm, Apparent Matrix Density (g/cc)

Figure 5-100. Chart for finding apparent matrix density or apparent matrix
transit time from bulk density or interval transit time and apparent total
porosity [199].
its propagation velocity is reduced. The wave then refracts to the borehole where
it is sequentially detected by the two receivers. Haw much the wave is attenuated
is a function of the dielectric permittivity of the formation. Rocks and oil have
similar permittivities while water has a very different permittivity. Therefore,
the wave responds to the water-filled porosity in the formation, and the response
is a function of formation temperature.
Since the wave is attenuated by water (and is not too bothered by oil), the
log response indicates either L, (in water-based mud systems) or bulk volume
water (in oil-based mud systems).
In order to provide usable values, the velocity of the returning wave is
measured and compared to the wave-propagation velocity in free space. The
propagation velocity of the formation is then converted into propagation time
(Tp,). A typical log presentation includes a Tpl, curve (in nanoseconds/meter),
an attenuation curve (EATT) in decibels/meter, and a small-arm caliper curve
(which measures borehole rugosity) recorded in tracks 2 and 3. Figure 5-104