Borehole Seismic Survey 1
Borehole Seismic Introduction
2
Borehole Seismic Tool and Acquisition
3
VSP Processing
4
Sonic Calibration and Synthetic Seismogram
5
VSP Examples
Kieu Nguyen Binh HCMC-2010
Borehole Seismic Survey 1
Borehole Seismic Introduction
2
Borehole Seismic Tool and Acquisition
3
VSP Processing
4
Sonic Calibration and Synthetic Seismogram
5
VSP Examples
Kieu Nguyen Binh HCMC-2010
#3 VSP Processing
One-Way Time vs. Two Way Time OWT
TWT
Trace display parameters – Trace Overlap 50 % overlap
100 % overlap
200 % overlap
Trace overlap is computed on the maximum amplitude in each trace
VSP display options – Trace Normalisation -Trace-by-trace normalisation - 100% overlap - One Way Time
- Gather normalisation - 1000% overlap - One Way Time
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.
VSP display options – OWT, TWT and Aligned -Trace-by-trace normalisation - 1000% overlap - One Way Time
TWT – traces are shifted by the transit time pick at each level
- Trace-by-trace normalisation - 1000% overlap - Two Way Time
- Trace-by-trace normalisation - 1000% overlap - Zero Aligned Time
VSP display options – Wiggle or VDL
VSP display options – Trace separation … by depth
… by trace
Processing Sequence Field Data
Data Edit
Median Stack
Data Preparation
BPF, NRM, TAR Static correction Wavefield Separation Upgoing Wavefield
Deconvolution Corridor Stack
Downgoing Wavefield
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
Hydrophone At the surface near the airgun
Raw shots
Geophone Downhole in tool
3 or 5 shots per level. These are stacked to reduce noise
Hydrophone
Mean stack
Geophone
Hydrophone
Median stack
Geophone
Stacked Z component
Inflection Point Tangent
Inflection Point
Transit Time Picking (3215 metres) Time varying from IPT = 1209.1 msec IP = 1212.9 msec T =1216.8 msec ZC = 1222.1 msec P =1229.3 msec
Trough
Zero crossing
Peak
Transit Time pick (Shallow level at 744 metres depth)
Shallow depths -> More high frequency Inflection Point Tangent = 392.5 msec Trough = 396.2 msec 3.7 msec difference … deeper levels give 7.7 msec difference
Transit Time Picking (Hydrophone)
Inflection Point Tangent = 28.6 msec Trough = 31.2 msec 2.6 msec difference
No Filtering
4-120 zero phase filter
4-90 zero phase filter
4-60 zero phase filter
Filtering and Transit time picking
Level at 744 metre. The effect of filtering on the time picks is most severe at shallower levels
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 - For offshore job > SRD = MSL (Mean Sea Level)
Frequency Spectrum
Frequency content versus depth. Attenuation of high frequency exponentially with depth
Bandpass Filter
To remove frequencies that may correspond to noise To remove frequencies that may be aliased
Normalization
Amplitude Recovery
where t is time and t 0 is break time - compensate for spherical divergence & attenuation along the trace trace
Processing Sequence Field Data
Data Edit
Median Stack BPF, NRM, TAR Static Correction Wavefield Separation
Upgoing Wavefield Data Processing
Deconvolution Corridor Stack
Downgoing Wavefield
Wavefield Separation - Velocity Filtering A VSP is made up of two distinct wave types One Way Time Downgoing
Upgoing
The downgoing waves • The direct compressional signal • A whole suite of events generated by multiple reflections
h t p e D
• It can be quite long and reverberatory in character • Masks the other type, the upgoing waves
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 Velocity filtering separates these two signals which have different apparent velocities across the data array. Velocity filtering is done in 3 main stages
Estimation of Downgoing Energy 1. Estimate Downgoing Energy Subtract transit time to vertically align all downgoing energy One Way Time
h t p e D
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
Estimation of Downgoing Energy Time h t p e D
d l e i f e v a W g n i o g n w o D
Vertical Geophone (Z)
Median Stack Traces Aligned to First Break
Aligned Enhanced Downgoing Wavefield
Subtraction of Downgoing Energy One Way Time
One Way Time Downgoing h t p e D
Upgoing h t p e D
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 One Way Time Upgoing
h t p e D
Two-Way Time
Residual Wavefield after Subtraction of Downgoing Wavefield
h t p e D
Add first break transit time to vertically align all upgoing energy at it’s two-way time
Enhance Upgoing Energy Two Way Time
h t p e D
h t p e D
Two-Way Time d l e i f e v a W g n i o g p U
Enhanced Upgoing Wavefield
Add TT - Median Stack Apply median filter to enhance in-phase upgoing energy and suppress all out of phase energy
Velocity Filter
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
Well Separated Reflections
Short Signal
2 2 1 1
1
1 Reflector 1 2
Original Signals
2
Reflector 2
Deconvolved Signals
Deconvolution Time
Time
Depth
Depth
Time
Depth
Depth
TWT
Time
Airgun bubble suppression (multiple) by deconvolution, on both up and down
Zero Phase Deconvolution
Enhancement
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
Triaxial VSP – Wavefield projection 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
Y
X
Z contains most of the downgoing compressional X and Y are rotating in the borehole as the tool moves up
0.01 sec
X, Y and Z 0.02 sec
0.03 sec
0.04 sec
X & Y projected to max and min 0.05 sec
0.06 sec
Particle motion cross plot to determine Horizontal MaXimum component y
HMX
x
X geophone response Y geophone response HMX=X. COS HMN=Y. COS
+ Y.SIN X SIN
Projections on X and Y
Z
HMN 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
Vertical Component (TRY)
Horizontal Component (HMX)
Horizontal component
Vertical component
VS = (2500-800)/(2.15-1.0) = 1478 m/sec
HMX
F = 60 hz
VP = (2500-800)/(0.88-0.32) = 3035 m/sec
Z
F = 80 hz
Compressional and Shear acquisition Z geophone
X & Y geophone
Particle Motion
Particle Motion
In a vertical well, Z geophone is up-down orientation. Z will see compressional X and Y will see shear
Wavefield projection – simple angle based
Assumptions: no ray bending from source to receiver
TRY angle in deviated well
TRY angle vs deviation for GAC depth 9 2 2 6 4 0 7 5 0 9 2 3 4 7 7 2 0 6 3 0 5 4 8 9 0 3 3 7 6 1 9 6 1 0 4 4 7 8 9 3 2 7 4 1 7 6 0 0 2 4 5 7 5 3 5 3 4 3 4 3 3 3 2 3 2 3 1 3 1 3 0 3 0 2 9 2 8 2 8 2 7 2 7 2 6 2 6 2 5 2 4 2 4 2 3 2 3 2 2 2 2 2 1 3
50
55 60
65
70 s e e r g e d
75
deviation TRY angle
80
85
90 95
100
Rig Source & Vertical well
Rig Source & VI Source VSP
Rig Source & Deviated well
VI-source & Deviated well
Rig Source & VI Source VSP
Rig Source & Vertical well
T W O
Rig Source & Deviated well
VI-source & Deviated well
T W T
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)
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.
Sonic log and seismic raypath not necessarily the same.
Seismic raypaths affected by refraction.
Require Navigation to location airgun position.
Seismic travel times affected by anisotropy.
VSP image requires migration.
Sonic log and seismic raypath are not the same – assume no lateral velocity variations above the well trajectory
Review - Rig Source VSP Rig Source VSP Downgoing OWT
Rig Source VSP Upgoing OWT
Rig Source VSP Upgoing TWT correction
Shifting each trace by the transit time pick, gives the correct TWT
Offset Source VSP Offset Source VSP Downgoing OWT
Offset Source VSP Upgoing OWT
Offset Source VSP Upgoing TWT correction
Shifting each trace by the transit time pick, no longer gives the correct TWT. The time is too long, and gets progressively worse for the shallower traces
NMO correction at first arrival for Offset VSP Rig Source VSP TWT
Offset Source VSP TWT correction
Offset Source VSP (Simple) Normal move-out correction NMO correction shifts 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 Is model driven
Walkaway VSP
Common receiver gather
Common shot gather
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
Walkaway VSP after Migration Rig Source VSP TWT
Same as for Offset VSP To locate the reflection points at the correct spatial and time positions Is model based.
Gather 1 – top geophone
Gather 5 – bottom 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.)
Borehole Multiples Upgoing Multiples
