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CASE HISTORY BHGM LOG IN FRACTURED CARBONATE

Alaska North Slope - Lisburne Formation

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 investigation.

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%.

Figure 1