Well-Seismic Ties

Slide 1

• Slide to introduce topic: Well-Seismic Ties

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

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

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)

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

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)

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

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

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

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

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

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

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

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

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

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)

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

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)

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