Borehole Seismic Survey
Borehole Seismic Survey
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1 Borehole Seismic IntroductionBorehole Seismic Introduction 2
2 Borehole Seismic Tool and AcquisitionBorehole Seismic Tool and Acquisition 3
3 VSP ProcessingVSP Processing
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4 Sonic Calibration and Synthetic SeismogramSonic Calibration and Synthetic Seismogram 5
5 VSP ExamplesVSP Examples
Kieu Nguyen Binh Kieu Nguyen Binh HCMC-2010
Borehole Seismic Survey
Borehole Seismic Survey
1
1 Borehole Seismic IntroductionBorehole Seismic Introduction 2
2 Borehole Seismic Tool and AcquisitionBorehole Seismic Tool and Acquisition 3
3 VSP ProcessingVSP Processing
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4 Sonic Calibration and Synthetic SeismogramSonic Calibration and Synthetic Seismogram 5
5 VSP ExamplesVSP Examples
Kieu Nguyen Binh Kieu Nguyen Binh HCMC-2010
#3
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VSP Processing
One-Way Time vs. Two Way Time
OWT
50 % overlap
100 % overlap
200 % overlap
Trace display parameters – Trace Overlap
-Trace-by-trace normalisation - 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.
-Trace-by-trace normalisation - 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
VSP display options – Trace separation
Wavefield Separation Deconvolution
Processing Sequence
BPF, NRM, TAR Static correction Corridor Stack Median Stack Data Edit Upgoing Wavefield Downgoing Wavefield FieldReference 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
Raw shots
Hydrophone
At the surface near the airgun
Geophone
Downhole in tool
3 or 5 shots per level.
Mean stack Hydrophone
Median stack Hydrophone
Transit Time
Picking
(3215 metres)
Inflection Point TangentPeak Zero crossing
Trough
Inflection Point Time varying from
IPT = 1209.1 msec
IP = 1212.9 msec
T =1216.8 msec
ZC = 1222.1 msec P =1229.3 msec
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
Transit Time Picking
(Hydrophone)
Inflection Point Tangent = 28.6 msec Trough = 31.2 msec
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
Earth Filter
Stacked Data Stacked Data
Aligned on time pick Expanded time scale
2 msec drift in the trough
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
Frequency Spectrum
Bandpass Filter
Normalization
Amplitude Recovery
Amplitude Recovery
where t is time and t
where t is time and t00is break timeis break time
Wavefield Separation Deconvolution
Processing Sequence
BPF, NRM, TAR Static Correction Corridor Stack Median Stack Data Edit Upgoing Wavefield Downgoing Wavefield Field Data Data ProcessingWavefield 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
Upgoing Downgoing
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
1. Estimate Downgoing Energy
Subtract transit time to vertically align all downgoing energy
Apply median filter to enhance in-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
Median Stack Traces Aligned to First
Break
Estimation of Downgoing Energy
Vertical Geophone (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
Subtraction of Downgoing Energy
Upgoing Downgoing
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
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
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 Upgoing Wavefield
Deconvolution
The function of deconvolution is to precisely improve the resolution 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
Long Signal Mixed Reflections Short Signal Well Separated Reflections Reflector 1 Reflector 2 Original Signals Deconvolved Signals 1 2 1 2 1 2 2 1Depth Time Depth Time Depth Time Depth Time TWT
Deconvolution
Corridor Stack
Reasons for corridor stack - Shortest raypath
- Least effect from formation dip - Deconvolution is most accurate
VSP – Surface Seismic merge
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
Why Triaxial Geophones ?
Needs of Triaxial Geophones in VSPs
* Related to Survey Geometry (OVSP, WVSP,…)
* Related to Geophysical Phenomena (Mode Converted Wavefields, out of plane energy)
Near vertical well
Z contains most of the downgoing compressional
X and Y are rotating in the borehole as the tool moves up
X
Z
X, Y and Z
X & Y projected to max and min
0.01 sec 0.02 sec 0.04 sec 0.06 sec 0.05 sec 0.03 sec
x
y
Particle motion cross plot to determine
Horizontal MaXimum component
HMX
HMX=X. COS
+ Y.SIN
HMN=Y. COS
X SIN
X geophone response
Y geophone response
Projections on X and Y
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
Horizontal Component
(HMX)
Vertical Component
(TRY)
Horizontal
component
Vertical
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 hzCompressional and Shear acquisition
In a vertical well, Z geophone is up-down orientation.
Z will see compressional X and Y will see shear
Particle Motion Particle Motion Z geophone X & Y geophone
Wavefield projection
–
simple angle based
Assumptions:
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 angle
TRY angle in deviated well
Rig Source & VI Source VSP
Rig Source & Vertical well
VI-source & Deviated well Rig Source & Deviated well
Rig Source & VI Source VSP
O W T T W TRig Source & Vertical well
Rig Source & Deviated well
Rig Source & VI-source VSP
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
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 fire airgun.
Require Navigation to location airgun position.
Sonic log and seismic raypath are not the same – assume no lateral velocity
Review - Rig Source VSP
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
Offset Source VSP Upgoing OWT Offset Source VSP Upgoing TWT correction Offset Source VSP Downgoing OWTShifting each trace by the transit time pick, no longer gives the correct TWT. The time is too long, and gets
NMO correction at first arrival for Offset VSP
Rig Source VSP TWT Offset Source VSP TWT correction Offset Source VSPNMO correction (Simple) Normal move-out correctionshifts each trace, such that the first
break is at the correct TWT value, but using a simple geometrical
relationship.
A narrow window corridor stack, would give the seismic trace at the wellbore The data deeper in the trace has not
been corrected properly.
The spatial offset traces from the wellbore for the data deeper in the trace is not shown.
NMO correction is OK for small offset, but not good for large offsets.
A more complicated NMO algorithm can be used that shifts every point in the trace correctly…. However …. Better to…. Need migration
Migration for Offset VSP
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 spatial offset
Walkaway VSP
One level with walkaway can give an image, but need at least 5 levels to do up-down wavefield
separation.
Typically use 8 or more simultaneous levels
Common shot gather Common receiver gather
Walkaway VSP after Migration
Same as for Offset VSP
To locate the reflection points at the correct spatial and time positions
Is model based.
Rig Source VSP TWT
Gather 5 – bottom geophone Gather 1 – top geophone
Non-vertical incidence VSP’s
Summary
Three component (X, Y &Z) acquisition and
processing 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.)