1. Well-Seismic Ties Lecture 7 Depth Time Synthetic Trace SLIDE 1
Slide to introduce topic: Well-Seismic Ties
Time (ms)
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L 7 – Well-Seismic 1

2. Objectives of the seismic - well tie What is a good well-seismic tie?
Outline
Objectives of the seismic - well tie
What is a good well-seismic tie?
Comparing well with seismic data
Preparing well data
Preparing seismic data
How to tie synthetics to seismic data.
Pitfalls
SLIDE 2
Here is the outline for this lecture
We will discuss:
Objectives of the seismic - well tie
What is a good well-seismic tie?
Comparing well with seismic data
Preparing well data
Preparing seismic data
How to tie synthetics to seismic data.
Pitfalls
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L 7 – Well-Seismic 2

3. Objectives of Well-Seismic Ties
Well-seismic ties allow well data, measured in units of depth, to be compared to seismic data, measured in units of time
This allows us to relate horizon tops identified in a well with specific reflections on the seismic section
We use sonic and density well logs to generate a synthetic seismic trace
The synthetic trace is compared to the real seismic data collected near the well location
Synthetic Trace
SLIDE 3
The objectives for performing a well-seismic tie are listed here
Wells, of course, are registered in units of depth – feet or meters
Seismic data is recorded and usually worked with a vertical scale of 2-way travel time
To relate well data to seismic data, and vice versa, we have to handle this change in vertical scale units
Thus:
Well-seismic ties allow well data, measured in units of depth, to be compared to seismic data, measured in units of time
This allows us to relate horizon tops identified in a well with specific reflections on the seismic section
We use sonic and density well logs to generate a synthetic seismic trace
The synthetic trace is compared to the real seismic data collected near the well location
The well-seismic tie is the bridge we need to go from seismic “wiggles” to the rocks that produced the “wiggles” and our interpretation of the subsurface geology
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4. Purposes for Well-Seismic Ties & Quality
Business Stage
Accuracy Required
Seismic Quality Required
Example Application
Regional Mapping
Within a few cycles
Within ~½ cycle
Wavelet character match
Poor/fair
Good
Very good
Mapping and tying a regional flooding surface across a basin
Exploration
Comparing a lead to nearby wells
Exploitation
Seismic attribute analysis
Inversion
SLIDE 4
The purpose and required accuracy of a well-seismic tie varies with the stage of our studies
If we are doing regional mapping, e.g., mapping a significant erosional unconformity or a flooding surface, then our tie does not need to be very precise, within 1 or 2 seismic cycles (peaks or troughs) – and the seismic data quality does not have to be very good
In the exploration stage, we would like to tie well data, e.g., the top of a stratigraphic horizon/marker within ½ a cycle
This requires good seismic data quality
In the exploitation stage (development & production), we need to not only know the seismic event within ½ a cycle, but the shape of the real and modeled seismic trace should be quite similar
For this, we need very good seismic data quality
If we obtain a good character (shape) tie between the real and synthetic traces, then:
We would then be able to extract various seismic attributes (measures of the seismic wavelets) to predict rock and fluid properties
We may also be able to use a process called inversion to transform the seismic data into an estimate of the rock properties in cross-section views or as a 3D volume (if we have 3D seismic data)
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5. Measurements In Time and In Depth
Seismic - Time Units
Log - Depth Units
Surface Elevation
SHOT
REC’R
Kelly Bushing
Elevation
Base of Weathering
SLIDE 5
This slide illustrates the differences in measurements between seismic and well data
For seismic data, measurements are usually referenced to a common surface elevation (typically sea level) and are recorded in units of two-way travel time
Zero time is when a shot is fired
We then measure the time it takes for the acoustic energy to travel down to a reflection surface and back up to the receiver at the surface
For well/log data, measurements are made relative to a device on the drill rig called the Kelly Bushing (kb)
Depths are in feet or meters along the well bore
If the well is not purely vertical, then we differentiated between ‘measured depth’ and ‘true vertical depth,’ which has to be computed
Depth
Vertical depth
Two-way time
Measured
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6. Comparison of Seismic and Well Data
Seismic Data
Samples area and volume
Low frequency Hz
Vertical resolution m
Horizontal resolution m
Measures seismic amplitude, phase, continuity, horizontal & vertical velocities
Time measurement
Well Data
Samples point along well bore
High frequency, 10, ,000 Hz
Vertical resolution 2 cm - 2 m
Horizontal resolution 0.5 cm - 6 m
Measures vertical velocity, density, resistivity, radioactivity, SP, rock and fluid properties from cores
Depth measurement
SLIDE 6
This slide compares different aspects of seismic and well/log data
Seismic data samples areas and volumes within the earth; wells sample points along the well bore
Seismic data is low frequency (5 to 60 Hz); a log that measures rock velocity uses frequencies that are much higher
Vertical resolution is quite different – for seismic we can resolve layers that are 15 to 100 m thick; with logs we can resolve layers 2 cm to 2 m thick
Horizontal resolution for seismic … for wells …..
Seismic data measures …… well data measures ….
And, as we have already discussed, seismic is measured in two-way travel time; well data is in depth (ft or meters)
100 m
100 m
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7. Seismic-Well Tie Flow-Chart
Data
Data
Processing
Real Seismic
Trace
Estimate
Pulse
SLIDE 7
Here is a simple flow chart for performing a:well-seismic tie
At the top is our seismic data – the raw field data is processed to get us images of the subsurface
The processed data gives us a “real” seismic trace at the location of the well we want to tie
As part of the data processing, we can get an estimate of the shape of the seismic pulse
Near the bottom is the well data, which may need some processing/editing
The well data we need come from the sonic log (gives us velocity information) and one of several density logs
We may also have check shots from the well – more on check shots on the next slide
If we do not have an estimated pulse from the seismic data processing, we can use a standard (external) pulse shape of a user-defined phase and frequency
Computer programs combine the sonic and density log data with the estimated or external pulse to generate a “synthetic” or “modeled” seismic trace
We then compare the real and synthetic traces and note how well they match
If the match is good enough for our purposes, we can then relate one data set to the other – well to seismic OR seismic to well
External
Pulse
Well -
Seismic Tie
Well -
Seismic Tie
Well
Data
Data
Processing
Seismic
Modeling
Synthetic Seismic
Trace
Check Shots/
Time Depth
Information
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8. Check Shot Data
Check shots measure the vertical one-way time from surface to various depths (geophone positions) within the well
Used to determine start time of top of well-log curves
Used to calibrate the relationship between well depths and times calculated from a sonic log
Seismic Shot
Borehole Geophone
Time
Depth
SLIDE 8
What is check shot data?
We would like to have some calibration between well depth and seismic time, if possible
We do this by conducting a check shot survey in a well bore
It is rather simple in concept:
We lower a geophone (listening device) into a well and record its depth
We then fire a shot at the surface and record the one-way travel time to the geophone
We can do this with the geophone at multiple depths
This allows us to calibrate the time-depth relationship
For example, we might find that when the geophone was at 2000 meters the one-way time was 0.9 seconds
A check shot survey with a large number of closely-spaced geophone positions is called a VSP – a vertical seismic profile
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9. Pulses Types Two options for defining the pulse:
Use software that estimates the pulse based on a ‘window’ of the real seismic data at the well (recommended)
Use a standard pulse shape specifying polarity, peak frequency, and phase:
Minimum phase
Zero phase
Quadrature
Known Pulse Shapes
Minimum
Zero
Quadrature RC
Phase
Phase
Phase
SLIDE 9
We need a pulse to generate a synthetic trace
There are two options
It is best to use software during or after data processing to estimate the pulse for a given window of real seismic data
This window would be at the well location and near the depth of our primary zone of interest (e.g., our main reservoir)
The second option is to use a standard pulse shape with some user-specified parameters
This is a quicker method that is fine if we do not need to match wavelet shape – development and production stages
There are three basic pulse shapes:
Minimum phase is where the wavelet starts at the position of the reflection coefficient (as shown in the diagram)
Zero phase is where the wavelet is centered on the reflection coefficient
Quadrature phase is the zero phase pulse shifted -90 degrees – looks a bit like the minimum phase but is different
For a standard pulse, the user has to input two parameters:
The polarity – does an increase in impedance give a peak or a trough, and
A central frequency (e.g., 18 Hz)
Since the seismic pulse changes in the earth with depth (e.g., due to attenuation), you may have to generate several synthetics based on different estimated or standard pulses – one for shallow targets, another for intermediate depth targets, and a third for deep targets.
Positive
Reflection
Coefficient
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10. *    x = The Modeling Process
Reflection
Coefficients 
We calculate the reflection coefficients at the step-changes in impedance
Lithology * 
Wavelet
We convolve our pulse with the RC series to get individual wavelets 
Synthetic
We sum the individual wavelets to get the synthetic seismic trace
Velocity
Density
Impedance
Each RC generates a wavelet whose amplitude is proportional to the RC
Shale
Sand x =
Shale
Sand
SLIDE 10
This summarizes the seismic modeling process
At a given location, e.g., at well A, the earth consists of layers with varying lithologies
Well logs give us velocity and density as a function of depth, which we ‘block’ to capture the significant changes
Next we compute impedance as a function of depth
From impedance we can calculate the reflection coefficients
We define a pulse – extracted or estimated
The reflection coefficient series is convolved with the pulse to get individual wavelets – the response of each reflection coefficient to the pulse
The individual wavelets are summed to give us the synthetic seismic trace
Shale
We ‘block’ the velocity (sonic) and density logs and compute an impedance ‘log’
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11. Thin beds have almost no impact due to destructive interference
Impact of Blocking
For typical seismic data, blocking on the order of m (10 ft) is the recommended minimum
Using coarser blocking helps identify the major stratigraphic contributors to the peaks and troughs
Sonic
Log
Sonic
Log RC
Synthetic RC
Synthetic - + - +
Time (sec)
SLIDE 11
Rather then inputting the sonic and density logs directly, we ‘block’ the logs to capture significant changes
This helps us associate major lithologic changes with specific peaks or troughs
The blocking process does not “corrupt” the synthetic trace
As shown here within the magenta rectangle, closely-spaced reflection coefficients of opposite sign results in destructive interference and, as a result, the closely-spaced RCs have almost no response on the final synthetic trace
Our experience is that logs can be blocked with a 3 m (10 ft) minimum layer spacing
Thin beds have almost no impact due to destructive interference
Coarse Blocking
Fine Blocking
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12. Our Example Well A SLIDE 12
Here is an example where we have cut a seismic line into a left and right portion at a well and placed a synthetic trace in a gap at the well location
On the color seismic, red is a peak; black is a trough
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13. Tying Synthetic to Seismic Data
Position of
Synthetic Trace
Position synthetic trace on seismic line.
Project synthetic along structural or stratigraphic strike if well is off line
SLIDE 13
Going through the steps, we:
Break the seismic line at the well location, forming a small gap within which we can display the synthetic trace
If we have 2D seismic and the well is not actually on the seismic line, we project the position in along strike
Time (ms)
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14. Tying Synthetic to Seismic Data
Position synthetic trace on seismic line.
Project synthetic along structural or stratigraphic strike if well is off line
Reference datum of synthetic to seismic data (usually ground level or seismic datum)
Without check shots estimate start time of first bed
Synthetic Trace
SLIDE 14
The seismic data and the well data may have different datums – so we may have to apply an up/down shift
If check shot data is available, our shift should be small since we have some time-depth calibration
If we do not have check shot data, we may need a larger up/down shift
For this example, the strong peak (black) 2/3 down on the synthetic looks like it should correlate with the strong red cycle (peak) on the real sesimic data about ½ cycle lower
Time (ms)
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15. Tying Synthetic to Seismic Data
Position synthetic trace on seismic line.
Project synthetic along structural or stratigraphic strike if well is off line
Reference datum of synthetic to seismic data (usually ground level or seismic datum)
Without check shots estimate start time of first bed
Shift synthetic in time to get the best character tie
Use stratigraphic info on detailed plot to help
determine the best fit.
Synthetic Trace
SLIDE 15
Here we have shifted the synthetic down to tie the strong peak on both data sets
We would look further up & down the trace to see if the other seismic cycles seem to line up and if the wavelet characters are similar
Here the tie looks good enough for regional mapping & exploration, but not good enough for development & production uses
Time (ms)
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16. Tying Synthetic to Seismic Data
Synthetic Trace
If justified, shift synthetic laterally several traces to get the best character tie
Character tie is more important than time tie
We can use a cross-correlation coefficient as a measure of the quality of the character tie
SLIDE 16
We may be justified to move the synthetic traces a few traces to the left or right.
One good reason to move the synthetic is if the well is not actually on the seismic line (2D seismic survey)
For 2D or 3D seismic data, there could be some positional errors (seismic or well) or the seismic data may not be adequately migrated
The older the data, the more likely the positions are not accurate (pre-GPS technology)
For this example, it looks like we get a better tie by moving the synthetic about 10 traces to the right (~125 meters)
Time (ms)
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17. Tying Synthetic to Seismic Data
Accept the tie that yields best character tie with least time shift in the zone of interest (reservoir)
SLIDE 17
We accept the tie that gives the best character (wavelet) match with the least amount of vertical and lateral shifting
The strong peak in this example is the contact between reservoir quality sands below and a marine shale (good seal) above
Thus we can relate markers in the well (top of reservoir) with a specific cycle on the seismic line and map this boundary on the rest of our seismic data
Seal
The top of the reservoir should be mapped on this peak (red)
Reservoir
Zone
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18. Assumptions for Synthetic Well Ties
Seismic Data
Noise free
No multiples
Relative amplitudes are preserved
Zero-offset section
Synthetic Seismograms
Blocked logs representative of the earth sampled by the seismic data
Normal incidence reflection coefficients
Multiples ignored
No transmission losses or absorption
Isotropic medium (vertical and horizontal velocities are equal)
SLIDE 18
There are a number of assumptions that we make in generating a synthetic trace
For the real seismic, we assume that:
The seismic data is noise free
There are no multiples
Relative amplitudes are preserved, i.e., the amplitude is proportional to the impedance change
Zero-offset section
For the synthetic seismic trace, we assume:
Blocked logs are representative of the earth sampled by the seismic data
Normal incidence (zero offset) reflection coefficients
Multiples are ignored
The pulse experiences no transmission losses or absorption
The rocks are isotropic (vertical and horizontal velocities are equal)
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19. Common Pitfalls Error in well or seismic line location
Log data quality
– washout zones, drilling-fluid invasion effects
Seismic data quality
noise, multiples, amplitude gain, migration, etc
Incorrect pulse
Polarity, frequency, and phase
Try a different pulse; use extracted pulse
Incorrect 1-D model
Blocked logs, checkshots need further editing
Incorrect start time or improper datuming
Amplitude-Versus-Offset effects
Bed tuning
3-D effects not fully captured by seismic or well data
SLIDE 19
What does it mean if the synthetic trace does not match the real seismic trace?
Here are some of the most common pitfalls
Error in well or seismic line location
Log data quality
– washout zones, drilling-fluid invasion effects
Seismic data quality
– noise, multiples, amplitude gain, migration, etc
Incorrect pulse
– Polarity, frequency, and phase
– Try a different pulse; use extracted pulse
Incorrect 1-D model
– Blocked logs, checkshots need further editing
– Incorrect start time or improper datuming
– Amplitude-Versus-Offset effects
– Bed tuning
3-D effects not fully captured by seismic or well data
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