Section 2.4
GEOLOGY
APPLICATION FOR APPROVAL OF THE
CARMON CREEK PROJECT
VOLUME 1: PROJECT DESCRIPTION
SEISMIC DATA AND MODELLING
2.4.1
SEISMIC DATABASE
Shell has acquired, or purchased and reprocessed, over 1,700 km of 2-D seismic
data for the Shell lease boundary, to delineate the bitumen resource. Several
high-fold 2-D swath and 3-D seismic programs have also been acquired to further
delineate the resource and to help plan and drill development wells.
To facilitate monitoring steam conformity and reservoir processes, Shell has also
conducted an extensive monitoring program over the development area. This
involved acquiring time-lapse seismic, vertical seismic profile (VSP),
microseismic, tiltmeter and interferometric synthetic aperture radar (InSAR) data.
Table 2-2 summarizes the database that Shell has used to interpret the resource
development area.
Table 2-2: Peace River Seismic Database
Source
Recent 2-D delineation
seismic
Year
2002 to 2007
Coverage
Source
Spacing
Receiver
Spacing
Source and
Receiver Line
Spacing
280 km
20 to 40 m
20 m
N/A
Older 2-D seismic
1960 to 1985
1,340 km
Various
Various
N/A
2-D swath seismic
2001 to 2007
82 km of source lines
20 m
10 m
160 m
Walk-away vertical seismic
profile (VSP)
2005 to 2006
15 km of source lines
10 m
8m
N/A
3-D VSP
2006
300 m x 500 m
source array
15 m x 15 m
8m
N/A
Time-lapse 2-D swath
seismic
2004 to 2006
43 km of source lines
20 m
10 m
160 m
3-D seismic
1996 to 1997
Two surveys totalling
2
7.5 km
10 m
10 m
80 m
3-D seismic
2001 to 2006
7 km2
10 m
10 m
N/A
2
10 m
10 m
Receiver: 80 m
Source: 100 m
10 m
10 m
Receiver: 80 m
Source: 100 m
3-D seismic
2007 to 2008
30 km
3-D seismic
2008 to 2009
60 km2
Microseismic arrays
Since 2002
Six arrays
N/A
N/A
N/A
Tiltmeter arrays
2002 to 2007
Two arrays
N/A
N/A
N/A
InSAR or global positioning
system arrays
Since 2005
Six GPS stations
30 InSAR radar
reflectors
N/A
N/A
N/A
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Section 2.4
GEOLOGY
2.4.2
SEISMIC DATA AND MODELLING
ACQUISITION PARAMETERS
The parameters for seismic data acquired over the winters of 2006–2007 and
2007–2008 were based on Shell’s previous experience in the area, as well as field
testing and modelling. For the acquisition of the recently acquired 2-D
delineation seismic, a source spacing of 40 m and receiver spacing of 20 m were
used. Where needed, such as for well placement, 2-D swath or full 3-D datasets
were acquired to obtain an improved lateral and vertical resolution in the seismic
image of the reservoir, using a source spacing of 20 m and a receiver spacing
between 10 m and 20 m.
For the time-lapse experiments and walk-away vertical seismic profiles (VSPs),
even tighter spacings were used to achieve more detailed imaging of reservoir
processes for monitoring. Tests with different charge sizes indicated that small
charges were better for achieving higher frequencies, and still transmitted
sufficient energy into the ground to receive an adequate signal. Based on this,
charges of 0.25 kg were used for all recent programs.
In the latest seismic acquisition programs, three component digital sensor units
with micro electro-mechanical systems were used to record the vector wavefield.
Although acquisition parameters were selected for optimum imaging of the
reservoir interval, proper imaging of the Devonian Wabamun was also required,
as it is an excellent regional marker used for calibrating seismic. Therefore,
longer offsets were recorded than those necessary for reservoir imaging, to
ensure more effective multiple attenuation and higher fold at depth.
The acquisition parameters described previously led to good data quality in most
parts of Shell’s lease boundary. However, a deep, near-surface channel filled
with glacial debris causes some data quality problems in the northwestern part of
the resource development area. The thick layer of glacial debris impedes energy
transmission to the reservoir interval. Consequently, source records there are
dominated by multiple energy, with only a small amount of primary reflection
energy received at recorders.
In addition to the 2-D seismic data from the last couple of years, Shell also
acquired older 2-D lines and purchased and reprocessed other older 2-D lines.
The older lines generally have larger station intervals and larger charge sizes, but
are often adequate for imaging the bitumen reservoir interval and the Devonian
Wabamun.
2.4.3
MODELLING AND INTERPRETATION
Interpreting the seismic data over the area is relatively straightforward.
Synthetics (see Figure 2-15) were used to tie in selected seismic lines to well
control. The remaining lines were then correlated using the lines already tied to
the well as baselines. The result was a set of zero-phase seismic lines that tied
both lines in terms of phase and time at the intersection points.
In the synthetic, the top of the reservoir can be picked as a trough on the seismic
directly below two low-amplitude peaks that are characteristic of the base of the
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Section 2.4
GEOLOGY
SEISMIC DATA AND MODELLING
Metre
Wilrich shale. The velocity contrast between the Wilrich shale and the underlying
bitumen-saturated sand is small, although the density contrast is significant.
Therefore, to represent the trough corresponding to the top of the reservoir
properly, both velocity and density had to be included in the model.
Bluesky
Detrital
Debolt
Figure 2-15: Example of Synthetic Seismic from Logs
The Debolt Formation was picked as a strong peak on the seismic. Given the
strong velocity and density contrasts between the softer overlying sands and the
harder Mississippian carbonates, the Mississippian unconformity event,
corresponding here to the Debolt, is usually distinct and easy to identify. All
sections in the area were interpreted using this approach.
A typical seismic section (see Figure 2-16) illustrates how an interpretation looks
using real data. Note the high amplitude of the Mississippian unconformity (red
horizon). When all sections had been interpreted, a Bluesky to Debolt isochore
map was created from the two sets of horizons. This was then converted to a
Bluesky to Debolt thickness based on interval velocities calculated at the well
control points.
Where the Bluesky sand directly overlies the Mississippian unconformity, the
Bluesky to Debolt map represents the thickness of the reservoir. However, this is
not the case where the unconformity is overlain by a detrital lag. Although the
top of the detrital lag can sometimes be identified on seismic lines, allowing the
true base of the reservoir to be picked, the acoustic properties of the detrital layer
are variable, and this pick is often impossible to make. In these cases, the
thickness of the detrital layer is determined from well control and extrapolated to
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Section 2.4
GEOLOGY
SEISMIC DATA AND MODELLING
the seismic control, where it is subtracted from the total reservoir plus detritus
isochore. The result of this has been used to create maps of the Bluesky reservoir
thickness.
Bluesky
Mississippian Unconformity
Wabamun
Leduc Reef
Figure 2-16: Typical Seismic Section
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