September-October 2000
Volume 1 No. 5
INVITED TALK
E. C. Thomas
A practical approach to mapping fractures in the deep Twin Creek reservoir in the Lodgepole field, northeast Utah, is to characterize fracture zones at the borehole scale and then to use other methods such as seismic measurement techniques to map the zones at interwell scales. For this approach to succeed it is imperative to relate the petrophysical properties to the distribution of fractures within the reservoir. We studied the Twin Creek Formation by integrating cuttings, petrography, well logs, a synthetic seismogram, and migrated 2-D surface seismic data. The integration identified seismic events associated with geological units in the formation. The seismic data allow delineation of the major geological boundaries between members of the formation, and petrographic and petrophysical analyses demonstrated that most fracturing occurs in dolomitic mudstone rocks of the Watton Canyon and Rich Members.
The fracture intensity was based on a fracture grade system
constructed from FMS logs. A velocity anomaly observed in the velocity
inversion image correlated with a dolomitic fractured zone in the Watton Canyon
Member intercepted by a horizontal well. In addition, the velocity image
integrated with the gamma ray logs identified the petrophysical units in the
interwell region, in particular, the presence of shales and dolomites. Since
the fractures are in dolomitic zones about 100 ft (30 m) thick or less,
high-resolution, 3-D seismic measurements could be used to map the fractured
zones. In particular, high velocity contrast between the shale and the dolomite
units suggests that reflection imaging has the potential to capture
dolomite-shale interfaces.
Experimental full-waveform sonic data were collected in an exploration well penetrating unconsolidated sand-shale sequences. Using a low frequency (2,000 Hz) compressional wave source drive, formation compressional (P) wave arrivals were recorded in acoustically slow, gas bearing sands. In some intervals formation velocities were slower than the borehole fluid speed. Standard (10,000 Hz) P-wave acquisition failed to detect formation signals across the same intervals. Shear wave acquisition was accomplished using dipole transducers. Interpretation of the measured com- pressional to shear wave velocity ratio (VP/VS) highlighted gas-bearing intervals where the VP/VS ratio dropped below the background compaction trend.
One of these gas-bearing intervals had commercial saturations of gas while the other zones were both sands and shales with low, non-commercial gas saturations. The low velocity zones appeared to be caused by a variety of mechanisms. Very slow P-wave velocities (borehole fluid speed or slower), positively indicating the presence of gas, were noted in several shale formations. Using a model of thin, gas charged silts or sand embedded in the shale matrix, effective medium modeling indicated that the recorded slowness could be caused by a concentration of less than 20 percent gas charged silt layers. This is significant because it indicates that gas charged shales can give amplitude anomalies, indicating hydrocarbons, on the seismic section.
Slow P-wave velocities indicating the presence of gas were also noted in high-porosity sands that appeared wet, with the water saturation approximately 90 percent, using conventional log interpretation. Pressure profiling gave a water gradient, confirming that water was the dominant phase in those intervals and indicating only a low gas saturation. However, this low gas saturation was sufficient to cause a significant slowing of the P-wave velocity and a corresponding amplitude anomaly on the seismic section.