Shell's
Auger deepwater field in the Gulf of Mexico, a decade after its
first production, is still yielding valuable data — as well as
hydrocarbons — and helping to advance a variety of technologies,
including the use of 4-D seismic to optimize reservoir depletion.
In fact,
the 10 years of production that made Auger an ideal fit for testing
4-D seismic techniques and data.
Auger was
discovered in 1987 using 2-D seismic data — before 3-D seismic
blanketed the Gulf of Mexico. The first 3-D seismic survey was acquired
over the field in 1988 to aid in development and evaluation, according
to Tom Kratochvil, staff geophysicist with Shell. A second, orthogonal
baseline seismic survey was acquired over Auger in 1990.
Kratochvil
presented a paper at the AAPG Annual Meeting in Dallas titled "The
Auger 4-D Case Study: Exploiting a Gulf of Mexico Turbidite Field
by the Use of Time Lapsed Seismic Surveys."
It wasn't
until Auger came on production in 1994 and several non-exclusive
seismic surveys were available over the field that Shell scientists
realized there was an opportunity to monitor the progress and pattern
of reservoir depletion through the use of 4-D seismic. Reservoir
depletion through production was monitored via non-exclusive surveys
in 1997 and 1999, and in 2002 using a proprietary survey.
The studies
focused primarily on the seven producing reservoirs.
"By 1997
we saw the 4-D effects on the seismic data and knew we had pockets
of hydrocarbons we could go after in the field," Kratochvil said.
Over the
next several years the 4-D studies advanced Shell's knowledge of
the geophysics, the geology and the reservoirs at Auger.
"Geophysically
we built on Shell's worldwide experience with 4-D seismic technology,
particularly from the North Sea, to optimize our results at Auger,"
he said. "We progressed from interpretation of legacy surveys to
detailed analysis of dedicated 4-D surveys."
Shell's
current best practice is to use dedicated, non-legacy 4-D seismic
data sets to monitor production, as noted by Raoul Restucci, CEO
of Shell Exploration and Production — The Americas, in the February
2004 edition of the Leading Edge, "Oil and Gas in the United
States: The Geophysical Challenge."
Equalizing
the Data
One
challenge from a geophysical perspective was integrating the seismic
acquisition advancements into each survey while retaining repeatability.
"For example,
from 1997 onward, the surveys were shot using metric units — but
Auger's earlier surveys were shot in English units," Kratochvil
said. "We had to account for those changes.
"For the
2002 survey we utilized the latest acquisition technology, which
was a substantial improvement over the 1990 baseline survey, and
then simplified the effective geometry during the seismic processing
to be equivalent to the earlier data for the sake of 4-D comparisons,"
he said. "We then took advantage of today's state-of-the-art processing
technology utilizing the full acquisition suite to create a separate
data set to get additional stratigraphic and structural details
from the seismic."
This technique
gave scientists a chance to get higher frequency data with better
resolution.
"New acquisition
techniques allowed us to acquire a denser lateral sampling and better
vertical resolution," he said, "which provides more detail. This
data set definitely showed more of the subtle stratigraphic breaks."
His example:
There is a 4-D amplitude anomaly that is located outside an area
of well control. The amplitude may indicate commercial hydrocarbons,
but also could be uneconomic residual, so understanding structurally
and stratigraphically why hydrocarbons might be left behind in that
area is important.
"Better
resolution from the newer data allows you to see layers that are
40 feet thick instead of 80 feet thick at a lateral spacing of 50
feet instead of 100 feet," Kratochvil said, "which may allow you
to describe structural or stratigraphic details that explain why
an amplitude might remain isolated from producing wells."
'Prolific
Producers'
Shell's
knowledge of turbidite reservoirs and how they perform during production
grew substantially as a result of the 4-D study, particularly when
it was integrated with geochemical data and seismic stratigraphy
to better understand the field's geology.
"These
turbidite reservoirs are prolific producers," Kratochvil said. "Based
on whole cores taken at the field we knew the S sand, for instance,
had thin shale stringers within the reservoir package. A monitor
well was drilled, and based on periodic-pulsed neutron logs we saw
that water flowed differently through each of the individual sand
units separated by the shale stringers. While our sweep efficiency
was somewhat piston-like, it wasn't uniform displacement from bottom
to top because different units flowed at different rates.
"Based
on those studies, we realized there was potential for stranded attic
opportunities as well as unswept bypassed reserves. Geochemistry
also provided evidence that certain barriers actually broke down
over the productive life of a reservoir."
Shell recently
drilled the A-5ST well to tap a down dip unswept portion of the
S sand, and the well "validates the presence of bypassed hydrocarbons
and 4-D expectations," he said. "There is a second attic well on
the other side of the field from the A-5ST that we will pursue in
the future."
Other
Benefits
The 4-D
seismic studies also:
Helped
validate Shell's overall development plan.
"We
were also pleased that the 4-D told us where not to drill wells,"
Kratochvil said, "thus saving Shell the costs of drilling unnecessary
wells in the field."
Helped
the team discover additional deeper targets.
"Often
we are fortunate in the Gulf of Mexico to have stacked pays,"
he said, "but there is so much stacked pay at Auger that some
of the deeper amplitudes were masked by shallow hydrocarbons on
pre-production 3-D seismic surveys and remain untested. When the
hydrocarbons were withdrawn from Auger's shallower zones, we found
that bright spots and flat spots for even deeper sands began showing
up on the 4-D surveys."
He
said Shell may target the deeper T sand series in the future.
The Auger Basin is productive down to about 24,000 feet, but Auger
Field proper is on a high where the window for pay is a little
shallower between 16,000 to 20,000 feet. These deeper pay opportunities
are generally about 1,000 feet below existing production.
Identified
redevelopment opportunities remaining at Auger, including undrained
attic hydrocarbons, unswept down-dip and laterally-isolated hydrocarbons
and newly delineated deeper reservoir potential.
Confirmed
that Shell's course of action at the field was on track.
However, the impact
of the 4-D studies stretches beyond the boundaries of Auger.
"We have a good idea
of what to expect going forward with any future basin redevelopment,"
he said. "Four-D offers a practical alternative in monitoring
production performance of subsea developments in lieu of drilling
expensive wells, which may be unnecessary.
"For years we saw
4-D effects on the Gulf of Mexico shelf, but didn't necessarily
have a dedicated program of shooting surveys, since drilling costs
were relatively low and we had a great deal of well control,"
Kratochvil said. "Auger was one of the first fields to transition
into deepwater and subsea technology, which had a much higher
risk profile. Those factors made 4-D seismic cost effective."
The final word: "Dedicated
4-D seismic technology will figure prominently in new developments
in the deepwater Gulf where water depths and drilling costs are
continuing to climb."