attempts have been made throughout the history of modern seismic to image
thin beds (<1/4 of dominant wavelength) by extracting higher frequencies
from seismic. In addition to simply imaging zones below normal resolution,
two of the more common goals to aid in reservoir development are:
- To define pinch-outs of
- To resolve internal bed
enhance seismic frequencies are critical to achieve optimum thin bed resolution.
The most common
post-stack method is spectral whitening or boosting the amplitudes of
all frequencies within a certain bandpass to the same level. The problem
with this method is that it does not discriminate noise from signal. Noise
is boosted along with the subsurface signal and, depending on the signal-to-noise
ratio (SNR), whitening may fail to extract the very information we hope
such as coherence cube technology and seismic inversion also can help
define some of the thin bed properties we seek through a different approach
but can still be limited by the inherent bandwidth of standard seismic.
This column focuses
on application of a method that attempts to separate the signal from the
noise while enhancing only the high frequency "earth signal" -- a technique
that helped identify new well locations in thinly bedded reservoirs that
would not have otherwise been drilled.
it helped to nearly quadruple daily production rates and add significant
new reserves to a 27-year-old Gulf of Mexico field.
The example used
here comes from South Marsh Island Block 128 Field (Figure
1). The discovery well for this prolific field was drilled in June
1974. The field is a stratigraphically complex, salt cored NW-SE trending
anticline bounded on the west by a large down-to-the-west fault.
ranges from Angulogerina B (Early Pliestocene) to Lenticulina 1 (Late
Pliocene) at depths of 4,500 to 9,000 feet subsea. Paleobathymetry ranges
from inner neritic at the shallower levels to upper bathyl in the deeper
zones, with all reservoirs being normally pressured.
The field has
seven exploratory wells and 93 development wells, including sidetracks,
drilled from four offshore platforms. In January 2000, cumulative production
was 115 MMBO and 203 BCF, and average daily production rates were 3,500
BO and 4 MMCF.
there had been difficult from the outset with various interpreters producing
different structural pictures (the lack of seismically mapped faulting
was the variable in the interpretations). Even with the acquisition of
proprietary, first generation 3-D seismic in 1989, the uncertainties persisted.
working the field were aware of the stratigraphic variations between wells
but were hard pressed to visualize this level of depositional complexity
with the currently available seismic. Distinguishing between faulting
and stratigraphic discontinuities was problematic at best, leading to
complex fault patterns that were suspiciously "ungeologic."
many of the reservoir thicknesses were below standard seismic resolution
-- thus impossible to map with much reliability.
A 1994 vintage
speculative 3-D dataset was reprocessed in early 1998, employing target-oriented
prestack Kirchoff time migration in an attempt to resolve some of these
issues. Field acquisition employed a 4,000-meter streamer with 25-meter
group and shot intervals, four millisecond sample rate and an eight second
record length. A 15,000-foot migration aperture was selected to optimize
imaging of dipping reflectors.
was greatly improved, leading to the conclusion that many of the discontinuities
previously interpreted as faulting were in fact stratigraphic variation.
Pressure data supported the fact that certain wells were in separate compartments,
but this was still not clearly imaged in the 3-D seismic.
In hope of resolving
these stratigraphic details, a post-stack frequency enhancement routine
was applied to the reprocessed data. This technique employs a branch of
mathematics originally developed in quantum mechanics for treating technically
unsolvable systems (undetermined equations) in combination with the math
evolved for the decoding of encrypted messages.
After all, this
is essentially what the seismic trace is.
In the data set,
two wells were selected as calibration wells. The selection criteria dictated
that good quality logs of velocity and density data be available for synthetic
information also was incorporated. The logs were carefully edited by experienced
petrophysicists to compensate for washouts, cycle skipping and any other
problems. The consequent reflectivity series were convolved with 50, 60,
75 and 80 hertz Ricker wavelets to produce synthetic seismograms. These
served as calibration points and quality control for the seismic processing.
traces were compared to the data to optimize parameters of the high frequency
data volume. At frequencies approaching 120 hertz, non-geologic "artifacts"
or events not correlative to the log-generated synthetic traces appeared
in the data, so the data was filtered back to the point where these artifacts
disappeared. The resultant high frequency data was integrated with well
information to identify and evaluate new drilling targets.
inversion was also employed to support the results and, in some cases,
was a determining factor for picking drillsites.
In June 2000,
the partners initiated a multi-well drilling program to test some of the
identified opportunities, including two wells drilled early in the field's
- The B-6 was drilled in
the field's southern portion in April 1976 and encountered 47 feet of
net oil pay in two zones.
- The B-9 was drilled 2,300
feet to the southwest of the B-6 in June 1976 and encountered 149 feet
of net oil pay in four zones.
Both are directional
platform wells drilled into generally east dipping strata with no water
contacts encountered by either well in any pay zone.
For this article
we concentrate on a reservoir referred to as the L-10 zone, a Lentic-1
The first generation
interpretation (Figure 2) shows a geologist's
subsurface log cross-section between the B-6 and B-9 wells connecting
all of the L series sands (L-1 thru L-10). Note that the L-1 zone in the
updip B-9 wellbore is interpreted as absent in the down dip B-6 wellbore.
All other L series horizons (L-4, 6 and 10) are shown to be continuous
except for variations in thickness and log character.
generally was accepted by the partners during the early stages of field
development. However, after years of production, the bottom hole pressure
(BHP) profiles show a divergent trend between these two zones (Figure
3), demonstrating that they could not be in communication with each
other. Furthermore, the L-10 zone (-7021 SSTVD) in the B-9 well watered
out in September 1991, after producing 2,083 MBO and 2,369 MMCF. The L-10
completion (-7587 SSTVD) in the B-6 well continued to produce until watering
out in April 1994 after recovering 539 MBO and 690 MMCF.
How do we explain
the fact that the updip well watered out before the down dip well? Clearly
some type of stratigraphic separation exists, but can we define it with
Before the application
of the frequency enhancement technique, the standard frequency reprocessed
version of the 1994 vintage speculative 3-D data (Figure
4) was used to study the accuracy of reservoir correlations. Figure
5 shows the location of an arbitrary seismic line from the 3-D volume
as A-A'. It directly connects the B-6 and B-9 wells, showing their SP
and resistivity log curves overlain on the data.
The red trough
seismic event representing the L-10 is indicated by the arrows.
Note that the
reflector is essentially continuous between the B-6 and B-9 wells. This
leads to a revised cross-section (Figure 6)
where the L-10 sandstone correlation from the B-6 well has shifted to
a shallower sand in the B-9 well.
original nomenclature for the reservoirs, the L-4 and L-6 zones in the
B-6 well are now shown as absent in the B-9 well. More importantly, the
L-10 zone of interest ties to a continuous reflector that now connects
it to what was previously identified as the L-1 in the B-9 well.
Maybe -- but does other information verify this? Records indicate that
there is a pressure difference of over 1,000 psi between these two zones,
suggesting that they cannot be in the same reservoir.
Once again standard
bandwidth seismic fails to resolve the correct correlation.
want to image a zone that according to logs is on the order of 20-40 feet
in gross thickness. Although our data quality is very good, we are limited
by the inherent bandwidth of the data. The dominant frequency in the zone
of interest is roughly 25 hertz with the high end imaging at 48 hertz.
The interval velocity is 8,850 feet/second, making the dominant tuning
thickness about 89 feet (1/4 wavelength) with the thinnest possible resolution
at 47 feet.
We may expect
to see a reflection at the top of the zone, but imaging the base is not
achievable -- and, due to bandwidth limitations, not resolvable as a separate
seismic event. The pay is not associated with a classic "bright spot,"
so an amplitude extraction does little to reveal any reservoir boundaries.
the 3-D seismic suggests that the separation is not fault-related. Yet
pressure and production data confirm that we are dealing with two separate
reservoirs. The separation must be stratigraphic.
It is now time
to apply the high frequency version of the 3-D dataset to see if it can
image what we know exists.
7 is the same A-A' arbitrary seismic line shown in Figure
4, except that the frequency enhancement technique has been applied.
The dominant frequency is now 45 hertz, making the dominant tuning thickness
roughly 49 feet. The upper end signal frequencies, however, extend to
80 hertz, allowing resolution of beds as thin as 27 feet.
reservoir units now begin to tie discreet events on the seismic. The zone
of interest is again indicated by the arrows. Note that the event that
ties the L-10 zone in the B-6 well appears to have a break or termination
before it reaches the B-9 well. It is interpreted as a stratigraphic
pinch-out and explains the reservoir separation indicated by the pressure
and production data. This prompts a reinterpretation of the geologic cross-section
(Figure 8) that honors the break in correlation
seen by the high frequency data.
exhibits more stratigraphic discontinuity than any previous interpretation.
It also offers an interpretation that reconciles the pressure and production
history and defines a new drilling target.
Is this coincidence
or truly the product of higher seismic resolution?
month: More successes from the South Marsh Island Field as high frequency
seismic targets development drillsites.