The BHGM log shown in Figure 1 was
run in the Sag Delta 6 well through the Lisburne group
carbonate reservoir adjacent to the Prudhoe Bay field in
Alaska. The principal reservoir unit is the Wahoo
formation, a cyclical Pennsylvanian shelfal carbonate.
The matrix rock is 30% dolomite, 55% limestone and 15%
shales, silts and cherts, indicating an average matrix
density of 2.75 g/cc. The porosity was formed by three
stages of dissolution and dolomitization. The youngest
porosity development postdates faulting and also cleared
fractures of cement by partial dissolution. A variety of
intercrystalline, moldic and micromoldic porosity is
present. Porosity values range up to .30 pu but most
porosities are in the .10 to .20 pu range.
Microfractures, small-strata bound fractures,
megafractures and seismically resolvable faults are also
present. The megafractures are faults below seismic
resolution. The faults and megafractures conduct fluids
vertically from the tight and less permeable strata to a
upper bounding alteration zone where fractures provide
horizontal drainage to wells.
Figure 1 shows a comparison of the BHGM density log
with a gamma gamma density log (FDC). The BHGM and FDC
density values averaged over the BHGM station intervals
are shown in the right hand track. The left hand track
shows the BHGM minus the FDC densities. This density
difference trace indicates differences between the
formation within a few inches of one side of the well
(FDC) and a volume over the same depth extending tens of
feet into the formation on all sides.
When hydrocarbons are flushed away from the well by
drilling mud filtrate the BHGM density is lower than the
FDC density. Fractures show on the FDC log only if they
intersect the well. Fractures show on the BHGM log when
they lower the average bulk density of the BHGM volume of
From 10600 to 9240 feet the BHGM density is generally
slightly higher than the FDC density. There are several
low density spikes on the FDC caused by bad pad contact.
These show as positive spikes on the density difference
trace. On average, in the zones where the FDC log is not
influenced by washouts or fluid invasion, the BHGM
densities are higher than the FDC densities by 0.021
g/cc. This difference may be due to a structural offset
of the BHGM densities, or a small mis-calibration of the
FDC density. This +0.021 g/cc is the base line difference
where conditions are the same near and far from the well.
In the reservoir interval from 9,000' to 9,240' the
BHGM densities are consistently lower than the FDC
densities. The average FDC and BHGM densities are 2.58
g/cc and 2.489 g/cc respectively. The BHGM has been
corrected down by 0.021 g/cc. The FDC indicates a maximum
water filled porosity of 0.098 pu. (1.01 g/cc water
density). The minimum possible calculated BHGM density of
2.559 g/cc corresponds to this porosity filled with 0.80
g/cc hydrocarbon. To account for the lower actual BHGM
density the average porosity away from the well bore must
be at least 0.135 pu, which is higher than the porosity
indicated at the well bore by .038 pu.
The implications of the higher average reservoir
porosity shown by the BHGM to fluid saturation
calculations using the Archie equation are that average
water saturations are decreased by about 20%.