03 VSP Processing

7/29/2019 03 VSP Processing

http://slidepdf.com/reader/full/03-vsp-processing 1/66



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



#3

VSP Processing



One-Way Time vs. Two Way Time

OWT

TWT



50 % overlap

100 % overlap

200 % overlap

Trace display parameters – Trace Overlap

Trace overlap is computed on the maximum amplitude in each trace



-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.



-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



VSP display options – Wiggle or VDL



VSP display options – Trace separation

… by depth … by trace



Wavefield

Separation

Deconvolution

Processing Sequence

BPF, NRM, TAR

Static correction

Corridor

Stack

Median

StackData Edit

Upgoing

Wavefield

Downgoing

Wavefield

Field

Data Data Preparation



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



Raw shotsHydrophone

At the surface near the airgun

GeophoneDownhole in tool

3 or 5 shots per level.

These are stacked to reduce noise



Mean stack

Hydrophone

Geophone



Median stack

Hydrophone

Geophone



Stacked Z component



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



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

2.6 msec difference

Filtering and



Filtering and

Transit time

picking No Filtering

4-120 zero phase filter



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

To remove frequencies that may correspond to noise



Bandpass Filter To remove frequencies that may correspond to noise

To remove frequencies that may be aliased



Normalization

Normalisation – equalize amplitudes along the first break line



Amplitude Recovery

where t is time and t0 is break time

- compensate for spherical divergence & attenuation along the trace



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



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



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



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



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




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




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


D e p t h

Two-Way Time

Enhanced UpgoingWavefield

Velocit Filter



Velocity Filter

D l i



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



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



Depth

Time

Depth

TimeDepth

Time

Depth

Time TWT

Airgun bubble suppression (multiple) by deconvolution, on both up and down



Zero Phase Deconvolution



Zero Phase Deconvolution

Enhancement



Enhancement

Corridor Stack



Corridor Stack

Reasons for corridor stack- Shortest raypath

- Least effect from formation dip

- Deconvolution is most accurate

VSP – Surface Seismic merge



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



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



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



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



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



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



Horizontal Component

(HMX)

Vertical Component

(TRY)



Horizontalcomponent

Vertical

component

VS = (2500-800)/(2.15-1.0)



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



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



Assumptions:

no ray bending from source to receiver

TRY angle in deviated well



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



VI-source & Deviated wellRig Source & Deviated well

Rig Source & VI Source VSP



O W

T

T W

T

Rig Source & Vertical well

Rig Source & Deviated well

VI-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 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



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 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



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



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



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



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



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



Upgoing Multiples

Borehole Multiples

Downgoing Multiple



Downgoing Multiple

03 VSP Processing

Documents

Transcript of 03 VSP Processing