Page 89 - Well Logging and Formation Evaluation

Advanced Log Interpretation Techniques 79

on T 2 for distinguishing between bound and free fluid. This is the basis
for the T 2 cutoff commonly used: 33ms for water-wet sandstones and
100ms for carbonates. The 33ms is based on an assumed surface relax-
ivity of sandstones of 100mm/s. In fact the relaxivity may vary consider-
ably among different types of rock. Values as low as 14.4 have been
reported in the literature. Times as long as 200ms have also been seen in
sandstones drilled with OBM.
If the appropriate T 2 cutoff is not a constant but is facies dependent,
significant problems are caused in determining permeability accurately. In
fact, a conventional poroperm approach normally works quite well if a
different relationship is used according to facies type. A lot of the poten-
tial benefits from NMR are removed if one requires both core T 2 mea-
surements for all facies types and a means for determining which facies
is being logged. The permeability may also be severely affected if, based
on TDA, a gas/oil/water model is being assumed rather than a straight
oil/water model. Applying the gas correction may affect the permeabili-
ties by a factor of up to 100.
The total porosity of the sample is related to the strength of the initial
signal occurring from the tool following the first transverse pulse during
a T 2 acquisition. Note, however, that for the following reasons this might
read low:

• If the wait time T w (also sometimes denoted as T r , the recovery time)
prior to the CPMG excitation is too short, the transverse field will be
reduced. This is referred to as incomplete polarization, to which polar-
ization correction may be applied.
• The tool is calibrated assuming 100% freshwater in the pores, i.e., the
hydrogen index (HI) is 1.0. The HI is influenced by temperature, pres-
sure, and salinity, as well as the fluid type (water, oil, or gas).

Because clay-bound water relaxes very fast (T 2 of a few ms), a special
mode of acquisition is required to measure total porosity. In a normal acqui-
sition mode, the tool will respond to only capillary-bound and free fluids. It
should be noted that it is normally assumed that the rock is water wet. This
means that any short T 2 arrivals are the result of the wetting phase relaxing
close to the pore wall. Other fluids, such as gas and water, are assumed to be
far from the pore wall, so that one sees only their bulk fluid relaxation times.
Any kind of TDA, which exploits the differences in D, exploits this fact.
The interpretation of the tool results can be subject to serious errors if this
assumption is not true, which can be the case in a well drilled with OBM for