American Oil and Gas Reporter - April 2019 - 97

carbon recovery.
In the Phoenix Field area, there is significant reservoir heterogeneity with lobe
architecture sediments fed into the basin
from the north, and latter structural faulting. Post-depositional salt migration from
below also contributes to some of the
structural elements in the area, which
made it difficult for early interpretations
of seismic data to establish the broad
extent of reservoir sands. Reprocessed
wide-azimuth 3-D confirmed the presence
of thicker sand packages.
After discovering the B-6 reservoir
with the Tornado 1 exploration well, it
was appraised updip with the Tornado 1
sidetrack, which logged a net oil pay of
297 vertical feet. The formation evaluation program for both wells included a
suite of open-hole logs, formation pressures, fluid samples and rotary sidewall
cores in. The collected data indicate that
the B-6 reservoir is a thick, clean, fullto-base sandstone with excellent permeability (averaging 300-600 md) and
undersaturated 30-degree API gravity
oil with a gas-to-oil ratio of 1,224 cubic
feet per barrel.
A key feature in the reservoir heterogeneity is a shale break interval logged
within the B-6 sand in both No. 1 well
penetrations, dividing the B-6 sand into
upper and lower lobes separated by a
silty layer. However, Talos has interpreted
the B-6 sand to be a single reservoir vertically, with the upper and lower sand
lobes believed to be in hydraulic communication and containing a single fluid
system. This interpretation is supported
by the indication of a single fluid system
from a fluid gradient plot generated from
pressure data collected in both wells
using real-time logging-while-drilling
formation-pressure testing and wireline
modular formation dynamics testing tools.
The silt break interval is visible on
the seismic data and believed to disappear
in portions of the reservoir. Areas of
"sand-on-sand" help explain the single
fluid system and may allow hydrocarbons
to move between layers during the field's
productive life.
Real-time NMR was deployed in both
the Tornado 2 exploratory and sidetrack
development wells. An important application for magnetic resonance is to help
define reservoir quality in terms of silt
capillary bound and clay distribution.
The logs indicate the silt break interval
present in the No. 1 wellbores has better
reservoir characteristics in the No. 2 sidetrack. LWD formation-pressure testing
shows horizontal communication with
the No. 1 in the B-6 lower zone as well
as vertical communication between the
B-6 lower and upper zones.

Real-Time Magnetic Resonance
Magnetic resonance was included in
the evaluation program to assess permeability variations, and to provide a lithology-independent porosity for accurate
bulk rock volumes. A previous well in
the Phoenix Field had shown a permeability profile that did not correlate with
the fining-upward sequence observed on
the gamma ray and density logs. In addition, NMR data help characterize in situ
reservoir fluid compositions and hydrocarbon fluid contacts.
A low-gradient, vibration-tolerant LWD
magnetic resonance instrument was used

to acquire real-time measurements to accurately identify porosity and fluid type,
and estimate permeability. The tool's design makes it possible to acquire highquality T2 spectra while drilling under a
range of downhole conditions.
The T2 spectra acquired is equivalent
to the intrinsic T2, as the tool's design
has almost no diffusion component. On
the Tornado 2 exploration and sidetrack
wells, the wait-time (Tw) was set to 12
seconds, long enough for 98 percent polarization, and drilling rates of penetration
ranged between 50 and 100 feet an hour.
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American Oil and Gas Reporter - April 2019

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