03 VSP Processing

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