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The idea
of lowering a geophone down a well bore to get a better handle on rock
velocity is hardly a new concept. Geophysicists have engaged in the
practice with increasing precision since the1930s -- around the time
when the first geophones were designed to withstand the rigors of the
borehole.
The
presence of a drilled well presents a truly unique opportunity to:
·
Investigate a target formation
more closely with acoustic measurements.
·
Minimize subsurface attenuation
phenomena.
·
Measure depth accurately.
·
Overcome the formidable
limitation of all surface geophysical measurements -- the lack of
accurate depth control.
Figure Captions
Figure 1. Typical
equipment setup and seismic ray paths in a borehole seismic survey.
In a checkshot velocity survey, only the first directly arriving signals
sensed by the downhole geophone are used. In vertical seismic profiling,
both directly arriving and reflected signals are used.
Figure 2. Zero
or near offset  VSP (left panel) and a corridor stack of VSP traces
(right panel). The VSP has been corrected to two-way time so that
reflections from horizontal reflectors appear at the same time on traces
recorded at different levels. The corridor stack (right) is a partial
summation or stacking of the VSP traces (left). Stacking, a summing of
data to produce a single output trace, enhances the signal to noise
ratio of seismic data.
Figure 3.
Extracted line from 3-D surface seismic -- well trajectory marked. Note
poor data quality resolution of possible unconformity above truncated
dipping beds.
Figure 4.
Processed VSP/CDP transform image recorded from vertical incident VSP
survey.
Figure 5.
VSP/CDP transform image spliced into seismic data.
Figures 3 and 4
combined to yield superior interpretation tool.
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Geophysicists are familiar with the velocity survey's one-way acoustic
travel time as a critical component that is necessary to help convert
surface seismic's two-way travel time to depth. In the absence of the
check shot velocity survey, accurate velocity information can sometimes
be extracted from the tried and true sonic log. Relying solely on sonic
logs, however, may entail considerable risk involving interval velocity
errors.
What may
not be clearly acknowledged are how limited check shot data are -- and
how very limited sonic logs travel times are inconsistently aiding the
time to depth conversion process. The sonic log excels as a formation
boundary and indirect porosity measurement log, but it can only see
one-two feet into the formation under good downhole conditions -- and
can be subject to cycle skipping and washed-out zones.
When the
sonic log is used to produce a synthetic seismogram for surface seismic
correlation purposes, one hopes that a check shot velocity survey is
available from the same well to calibrate the sonic log. Calibration and
correction of the sonic log often may be needed because the production
of a synthetic seismogram from a sonic log is a hybridization and
transform process that can introduce seismic travel time error if cycle
skipping, tool sticking, and washed-out zone effects are present in the
sonic log. The sonic log is also of very limited use in identifying
interval velocity inversions -- or any abrupt rock density and velocity
change that are an appreciable distance from the well.
The check
shot velocity survey can be used to produce a corrected sonic log,
allowing sonic log pitfalls to be alleviated by enabling a data
processing analyst to correlate effectively and more accurately through
questionable zones that were traversed by the sonic logging tool
downhole.
A
check-shot-corrected sonic log also makes it easier to determine
interval velocities between key formations, since familiar formation
boundaries can be readily recognized from the sonic log. If density log
information is also available, a more accurate synthetic seismogram log
integration usually results.
A check
shot velocity survey measures a much larger cylindrical volume of rock
compared to the relative soda straw volume measured by the sonic log.
The check shot survey and the more precise vertical seismic profile (VSP)
should at least be considered in the logging program of every
exploration and key development well being planned to minimize or
eliminate the ever-present and costly danger of surface seismic time to
depth conversion error.
Borehole
seismic data are the most effective correlation bridge available between
the well bore and the surface seismic data. Borehole seismic data that
include the check shot velocity survey and the VSP can measure large
volumes of rock -- and will indicate the presence of velocity anomalies,
which may be totally missed by the sonic log. These velocity anomalies
must be measured and dealt with accurately when mapping the velocity
fields that are so critical to an effective surface-seismic time to
drill-depth conversion process.
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The
vertical seismic profile (VSP) is a truly remarkable, versatile, and,
unfortunately, under-utilized innovation--under-utilized perhaps because
of its greater cost than the more routine check shot velocity survey and
the possible over-reliance within the industry on 3-D surface seismic
data.
The
effective utility of the VSP was developed by the Soviets in the 1960s,
made its way into Europe, and finally arrived in earnest in the United
States in the 1970s. The VSP was quite an industry sensation when it
started to be used in this country because of its "a look ahead" of the
drill bit capability and its use as an aid in predicting the depth at
which a target formation would be encountered after drilling continued.
The Look
Ahead or Prediction Ahead of the Bit (PAB) VSP, which is actually an
inversion routine performed during the data processing of ideally
zero-offset VSP survey data, has proven itself as a useful exploration
tool over the years. It has been used to predict the depth of
overpressured zones ahead of drilling offshore wells and to locate
granite-sediment and salt-sediment interfaces.
A zero- or
near-offset VSP survey has the energy source positioned as close as
possible to the well head to focus the energy down and ahead of the well
bore -- and is the preferred geometry for well correlation as opposed to
the offset VSP survey configuration, which positions the energy source
away from the well head to image a distance laterally away from the
well.
Look ahead
offset VSP surveys also have been used recently successfully to locate
subsurface features such as pinnacle reefs in East Texas. The look-ahead
VSP survey may seem like quite a leap of faith to the uninitiated --
until one realizes that all surface seismic data (2-D and 3-D) are all
look-ahead, as all measurements are made at the surface!
VSP Perspective
The VSP is
simply a precision level step change up from the check shot velocity
survey.
The basic
difference between the check shot survey and the VSP is that the VSP
measures nearly all seismic waveforms in the well bore (up-going and
down-going energy), whereas the check shot velocity survey measures
basically only the down-going energy (Figure
1). Note that a VSP is also a check shot velocity survey -- but a check
shot velocity survey is not a VSP!
Check shot
velocity survey measurements are typically taken every 250-500 feet
downhole and were designed to measure the down-going waveforms used in
velocity determination. VSP measurements are much more closely spaced
(50-100 feet).
The VSP,
like the check shot survey, also measures down-going energy. The smaller
measurement interval (level interval) required by the VSP is necessary
also to record the reflected energy in the well bore. The basic computed
product of the VSP is known as a corridor stack, which in appearance
resembles the synthetic seismogram. In reality it is a vastly superior
well correlation tool, because it contains actual seismic reflection
data as well as the down-going wave field.
The
down-going wave field is all that a check shot velocity survey records.
The corridor stack made from the VSP is the well bore converted to a
full reflection waveform seismic trace basically free of multiples (Figure
2). Another significant limitation of relying only on check shot
velocity surveys is that the surface seismic data that they are being
correlated with contain almost entirely reflected waveforms. Surface
seismic does not measure down-going energy because all the detectors are
at the surface.
VSP
surveys are routinely performed in many parts of the world -- especially
in Europe, because of the recognized superiority and versatility of the
VSP over the simpler and less expensive check shot survey. More and more
VSP surveys are being conducted -- especially offset surveys and a more
detailed variation of the offset survey called the walk-away VSP survey
-- as the advantages become clearer and survey reliability increases.
Pre-survey
ray trace modeling has gained wide acceptance and is used to design more
accurately offset VSP surveys and offset energy source placement. The
computed product of the offset VSP is known as a VSP/CDP transform --
basically a high-resolution, mini-seismic section resembling a surface
seismic CDP (Common Depth Point) stack display.
The VSP/CDP
transform has been converted or "transformed" from its original recorded
one-way time to two-way time and displayed at a convenient scale to
match the surface seismic data it is to be correlated with (Figure 3).
The VSP/CDP transform data set can be migrated, filtered, and processed
just like any surface seismic data set.
Because VSP
data has a broader bandwidth and contains high frequency events, subtle
features like small faults, stratigraphic changes, and amplitude
anomalies can be observed in the vicinity of the well bore, whereas they
are not discernible on the surface seismic coverage in the same area (Figure
4). Note the marked improvement in resolution that the VSP/CDP
transform yields in this example (Figure 5):
It is a VSP/CDP transform display made from a vertical incident VSP
survey, recorded to provide better resolution over a 2-D reconstruction
line from a 3-D seismic volume prior to deepening this directional well
bore.
A vertical
incident VSP survey requires the energy source to be positioned at the
surface directly over the downhole geophone tool. Vertical incident
geometry is generally preferred over the rig source option and has
proven to be a more accurate way to obtain velocity control and image a
highly deviated borehole. Displaying the VSP/CDP Transform and the
seismic section together yields a far more useful product for
interpretation.
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Downhole
tool design has improved significantly over the last 20 years.
Three-component geophone configurations are routine -- the tools have
evolved from single component analog designs to digital multi-tool
designs or actual downhole geophone arrays composed of up to 24 or more
individual tools or satellites.
Multi-station tools greatly reduce the historic bane of bore hole
seismic surveys -- rig time consumption -- and record higher quality
data. Slim (1-inch and 11/16-inch O.D.) downhole geophone tools have
proven their versatility and have made it possible to record high
quality VSP data in producing wells.
Logging
While Drilling (LWD) sonic, check shot and VSP tools are available to
meet the real-time demands of directional drilling. LWD tools designed
to record borehole seismic data are becoming increasingly more
sophisticated as LWD logging replaces conventional wireline logging on
many directional wells.
The two
most important benefits of running a VSP survey are reduced risk and
saved drilling dollars. The VSP survey reduces risk by measuring the
seismic velocities accurately in the well bore; this allows accurate
time-to-depth conversion of the surface seismic data. VSP data also has
been used to help reprocess older seismic data to yield more clearly
interpretable results.
The
accurate velocity information from the VSP helps make the velocity
analysis involved in processing and stacking surface seismic data more
precise. VSP data also can be used to remove multiples from surface
seismic data by providing parameters for an earth filter inversion
process known as signature deconvolution. Accurate time-to-depth
conversion is a must in producing reliable drilling prospect maps, and
it helps avoid missed drilling targets.
Money is
saved early on with VSP surveys conducted in the first wells drilled in
a play by increasing the accuracy of the interpretation and mapping
process -- and later, as more wells are drilled and the velocity field
is better understood.
Most of
the VSP surveys performed are of the zero- or near-offset type, which is
primarily used for velocity determination and surface seismic
correlation. Offset VSP surveys are gaining wider acceptance, as they
have proved successful in locating stepout locations to discovery and
producing wells.
The sonic
log and the check shot velocity survey have been the standard seismic
correlation tools for many years and have proven their utility -- but
today's exploration and production challenges require more precision.
The VSP survey meets that challenge, and is currently considered to be
the ultimate and most effective tool available for matching the well
bore to the sizable investment of surface seismic data that each
exploration company makes. More VSP surveys will be needed in the future
-- and may become a standard logging service -- as we strive to meet the
accuracy demands of our industry.
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