03 vsp processing
TRANSCRIPT
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Borehole Seismic Survey
1 Borehole Seismic Introduction
2 Borehole Seismic Tool and Acquisition
3 VSP Processing
4 Sonic Calibration and Synthetic Seismogram5 VSP Examples
Kieu Nguyen Binh
HCMC-2010
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#3
VSP Processing
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One-Way Time vs. Two Way Time
OWT
TWT
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50 % overlap
100 % overlap
200 % overlap
Trace display parameters – Trace Overlap
Trace overlap is computed on the maximum amplitude in each trace
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-Trace-by-tracenormalisation
- 100% overlap
- One Way Time
- Gather normalisation- 1000% overlap
- One Way Time
VSP display options – Trace Normalisation
A VSP display can be normalised individually trace-by-trace, or by a single
normalisation value (gather normalisation) for the whole data set. Gather normalisation
show the real amplitudes of the data.
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-Trace-by-tracenormalisation
- 1000% overlap
- One Way Time
- Trace-by-trace
normalisation
- 1000% overlap
- Zero Aligned Time
- Trace-by-trace
normalisation
- 1000% overlap
- Two Way Time
VSP display options – OWT, TWT
and Aligned
TWT – traces are shifted
by the transit time pick at
each level
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VSP display options – Wiggle or VDL
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VSP display options – Trace separation
… by depth … by trace
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Wavefield
Separation
Deconvolution
Processing Sequence
BPF, NRM, TAR
Static correction
Corridor
Stack
Median
StackData Edit
Upgoing
Wavefield
Downgoing
Wavefield
Field
Data Data Preparation
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Reference sensors
Time break sensors, there is also a
hydrophone hanging ~ 5 metres
below the gun
The hydrophone is the red
device – it will hang about 5
metres below the gun when
deployed
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Raw shotsHydrophone
At the surface near the airgun
GeophoneDownhole in tool
3 or 5 shots per level.
These are stacked to reduce noise
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Mean stack
Hydrophone
Geophone
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Median stack
Hydrophone
Geophone
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Stacked Z component
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Transit Time
Picking
(3215 metres)
Inflection Point Tangent
Peak Zero crossing
Trough
Inflection Point Time varying from
IPT = 1209.1 msec
IP = 1212.9 msecT =1216.8 msec
ZC = 1222.1 msec
P =1229.3 msec
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Transit Time pick
(Shallow level at 744 metres depth)
Inflection Point Tangent = 392.5 msec
Trough = 396.2 msec
3.7 msec difference … deeper levels give 7.7 msec difference
Shallow depths ->
More high frequency
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Transit Time Picking
(Hydrophone)
Inflection Point Tangent = 28.6 msec
Trough = 31.2 msec
2.6 msec difference
Filtering and
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Filtering and
Transit time
picking No Filtering
4-120 zero phase filter
4-60 zero phase filter
4-90 zero phase filter
Level at 744 metre.
The effect of filtering on the time
picks is most severe at shallower levels
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Earth Filter
Stacked Data Stacked Data
Aligned on time pick Expanded time scale
2 msec drift in the
trough
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Pre-processing after Stacking
Spectral Analysis
Band pass filter - to remove noise outside of signal range
Trace normalization
- to equalize downgoing waves of the same amplitude arrive for all receivers
Geometrical spreading correction
- to recover amplitude of later arrival
Static correction to SRD
- Correct reference time to Seismic datum
- For offshore job > SRD = MSL (Mean Sea Level)
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Frequency Spectrum
Frequency content versus depth. Attenuation of high frequency exponentially with depth
To remove frequencies that may correspond to noise
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Bandpass Filter To remove frequencies that may correspond to noise
To remove frequencies that may be aliased
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Normalization
Normalisation – equalize amplitudes along the first break line
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Amplitude Recovery
where t is time and t0 is break time
- compensate for spherical divergence & attenuation along the trace
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Wavefield
Separation
Deconvolution
Processing Sequence
BPF, NRM, TAR
Static Correction
Corridor
Stack
Median
StackData Edit
Upgoing
Wavefield
Downgoing
Wavefield
Field
Data
Data Processing
W fi ld S ti V l it Filt i
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Wavefield Separation - Velocity Filtering
A VSP is made up of two distinct wave types
The upgoing waves - the primary interest
• The complete downgoing waves being reflected at each acoustic reflector
• A whole suite of events generated by multiple reflections
The downgoing waves
• The direct compressional signal
• A whole suite of events generated by
multiple reflections
• It can be quite long and reverberatory in
character • Masks the other type, the upgoing waves
UpgoingDowngoing
One Way Time
D e p t h
Velocity filtering separates these two signals which have different apparent velocities
across the data array. Velocity filtering is done in 3 main stages
E ti ti f D i E
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1. Estimate DowngoingEnergy
Subtract transit time to vertically
align all downgoing energy
Apply median filter to enhancein-phase downgoing energy and
suppress all out of phase energy
Shift each trace back to its
original one-way time
One Way Time
D e p t h
Estimation of Downgoing Energy
E ti ti f D i E
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Median Stack Traces
Aligned to FirstBreak
Estimation of Downgoing Energy
VerticalGeophone (Z)
Aligned Enhanced
Downgoing
Wavefield
Time
D e
p t h
D o w n g o i n g W a v e
f i e l d
S btraction of Do ngoing Energ
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Subtraction of Downgoing Energy
UpgoingDowngoing
One Way Time
D e p t h
One Way Time
D e p t h
By subtracting the downgoing energy from the total
wavefield, a residual wavefield is left, which contains
background noise and the desired upgoing wavefield
Enhance Upgoing Energy
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Enhance Upgoing Energy
Upgoing
One Way Time
D e p t h
Add first break
transit time to
vertically align all
upgoing energy at
it’s two-way time
D e p t h
Residual Wavefield
after Subtraction of Downgoing Wavefield
Two-Way Time
Enhance Upgoing Energy
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U p g o i n g W a v e f i e l d
Add TT - Median Stack
Two Way Time
D e p t h
Apply median filter to
enhance in-phase
upgoing energy and
suppress all out of
phase energy
Enhance Upgoing Energy
D e p t h
Two-Way Time
Enhanced UpgoingWavefield
Velocit Filter
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Velocity Filter
D l i
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Deconvolution
The function of deconvolution is to precisely improve theresolution capabilities of the upgoing wavetrain:
It removes the near surface multiples & the bubble effects
It optimizes the resolution characteristics of the source
signature
Deconvolution filters are computed on the downgoing
wavetrain and applied to both the downgoing and upgoing
waves
Deconvolution
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Deconvolution
Long
Signal
Mixed
Reflections
Short
Signal
Well
Separated
Reflections
Reflector 1
Reflector 2Original
Signals
Deconvolved
Signals
1
2
1
2
1
2 2
1
Deconvolution
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Depth
Time
Depth
TimeDepth
Time
Depth
Time TWT
Airgun bubble suppression (multiple) by deconvolution, on both up and down
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Zero Phase Deconvolution
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Zero Phase Deconvolution
Enhancement
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Enhancement
Corridor Stack
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Corridor Stack
Reasons for corridor stack- Shortest raypath
- Least effect from formation dip
- Deconvolution is most accurate
VSP – Surface Seismic merge
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S Su ace Se s c e ge
Good match at 1300 msec. Not so good deeper down.
VSP is 8-75 Hz. Using lower frequency VSP decon does not improve the match
VSP is the correct answer. This can be confirmed with a synthetic seismogram
Triaxial VSP Wavefield projection
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Why Triaxial Geophones ?
Needs of Triaxial Geophones in VSPs
* Related to Survey Geometry (OVSP, WVSP,…)
* Related to Geophysical Phenomena (Mode ConvertedWavefields, out of plane energy)
Triaxial VSP – Wavefield projection
Near vertical well
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Z contains most of the downgoing compressional
X and Y are rotating in the borehole as the tool moves up
X
Z
Y
X Y and Z
0.01 sec
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X, Y and Z
X & Y projected to max and min
0.02 sec
0.04 sec
0.06 sec
0.05 sec
0.03 sec
Particle motion cross plot to determine
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x
y
pHorizontal MaXimum component
HMX
HMX=X. COS + Y.SIN
HMN=Y. COS - X.SIN
X geophone response
Y geophone response
Projections on X and Y
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Can repeat this procedure using HMX and Z as input.Outputs are TRY and NRY (Tangent and Normal).
Not too relevant in vertical well
HMX
HMN
Z
H i t l C tV ti l C t
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Horizontal Component
(HMX)
Vertical Component
(TRY)
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Horizontalcomponent
Vertical
component
VS = (2500-800)/(2.15-1.0)
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HMX
Z
VS (2500 800)/(2.15 1.0)
= 1478 m/sec
F = 60 hz
VP = (2500-800)/(0.88-0.32)
= 3035 m/sec
F = 80 hz
Compressional and Shear acquisition
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p q
In a vertical well, Z geophone is up-downorientation.
Z will see compressional
X and Y will see shear ParticleMotion
Particle
Motion
Z geophone
X & Y geophone
Wavefield projection – simple angle based
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Assumptions:
no ray bending from source to receiver
TRY angle in deviated well
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TRY angle vs deviation for GAC
50
55
60
65
70
75
80
85
90
95
100
3 5 7 9
3 5 2 2
3 4 6 4
3 4 0 7
3 3 5 0
3 2 9 2
3 2 3 4
3 1 7 7
3 1 2 0
3 0 6 3
3 0 0 5
2 9 4 8
2 8 9 0
2 8 3 3
2 7 7 6
2 7 1 9
2 6 6 1
2 6 0 4
2 5 4 7
2 4 8 9
2 4 3 2
2 3 7 4
2 3 1 7
2 2 6 0
2 2 0 2
2 1 4 5
depth
d e g r e e s
deviation
TRY ang
Rig Source & VI Source VSPRig Source & Vertical well
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VI-source & Deviated wellRig Source & Deviated well
Rig Source & VI Source VSP
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O W
T
T W
T
Rig Source & Vertical well
Rig Source & Deviated well
VI-source & Deviated well
Rig Source & VI-source VSP
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Transit Times corrected to Vertical
Rig VSP Deviated well has 4 msec
OWT error at TD
Pro’s and Cons or Rig source / VI source VSP
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Rig Source (+’s)
Can deploy the airgun from the rig
crane. Easy logistics.
Cheaper to do the survey.
Rig Source (-’s)
Sonic log and seismic raypath not
necessarily the same.
Seismic raypaths affected by
refraction.
Seismic travel times affected by
anisotropy.
VSP image requires migration.
VI-VSP (+’s)
Get the true vertical transit time at each
geophone level. No migration required of VSP image for
horizontal layered formation.
VI-VSP (-’s)
Require a boat to deploy the crane.
Require offset shooting equipment to fireairgun.
Require Navigation to location airgunposition.
Sonic log and seismic raypath are not thesame – assume no lateral velocity
variations above the well trajectory
Review - Rig Source VSP
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Shifting each trace by the transit time pick, gives the
correct TWT
Rig Source VSP
Upgoing OWT
Rig Source VSP
Upgoing TWT correction
Rig Source VSP
Downgoing OWT
Offset Source VSP
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Offset Source VSP
Upgoing OWT
Offset Source VSP
Upgoing TWT correction
Offset Source VSP
Downgoing OWT
Shifting each trace by the transit time pick, no longer givesthe correct TWT. The time is too long, and gets
progressively worse for the shallower traces
NMO correction at first arrival for Offset VSP
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Rig Source VSP
TWTOffset Source VSP
TWT correctionOffset Source VSP
NMO correction(Simple) Normal move-out correction
shifts each trace, such that the firstbreak is at the correct TWT value, but
using a simple geometricalrelationship.
A narrow window corridor stack, wouldgive the seismic trace at the wellbore
The data deeper in the trace has notbeen corrected properly.
The spatial offset traces from thewellbore for the data deeper in thetrace is not shown.
NMO correction is OK for small offset,but not good for large offsets.
A more complicated NMO algorithm canbe used that shifts every point in the
trace correctly…. However …. Better to…. Need migration
Migration for Offset VSPRig Source VSP Offset Source VSP Offset Source VSP Migration
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Rig Source VSP
TWT
Offset Source VSP
TWT correction
Offset Source VSP Migration
Horizontal axis is now in metres
offset from the well
To locate the reflection
point at the correct
time
To locate the reflection at
the correct spatialoffset
Is model driven
Walkaway VSP
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One level with walkaway can give an image, but needat least 5 levels to do up-down wavefieldseparation.
Typically use 8 or more simultaneous levels
Common shot gather
Common receiver gather
Walkaway VSP after Migration
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Same as for Offset VSP
To locate the reflection points at the correct spatial and
time positionsIs model based.
Rig Source VSP
TWT
Gather 5 – bottom geophoneGather 1 – top geophone
Non-vertical incidence VSP’s
Summary
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Summary
Three component (X, Y &Z) acquisition andprocessing techniques essential for Offset and
Walkaway VSP’s
A rig source VSP in a deviated well with flat
formations, requires Offset VSP processing
technique.
A rig source VSP in a vertical well with dipping
formations, requires Offset VSP processing
technique.
Migration is required for non-vertical incidence.(NMO can be used for a first approximation.)
Borehole MultiplesUpgoing Multiples
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Upgoing Multiples
Borehole Multiples
Downgoing Multiple
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Downgoing Multiple