synthetic seismogram, Oil & Gas Glossary

What Is a Synthetic Seismogram?

A synthetic seismogram is a modelled seismic trace computed by convolving the reflection coefficient series derived from wireline density and sonic log data at a well location with a seismic wavelet, producing a simulated seismic trace that can be directly compared with the real surface seismic data to calibrate the time-depth relationship, identify the geological origin of seismic reflectors, and validate the seismic interpretation at the well control point.

Key Takeaways

The reflection coefficient series is computed from acoustic impedance contrasts: RC = (Z2 - Z1)/(Z2 + Z1) at each interface.
Acoustic impedance is the product of bulk density and compressional wave velocity (Z = rho × Vp).
The wavelet used for convolution must match the dominant frequency content of the actual seismic data at the well location.
Synthetic-to-real tie quality is improved by check-shot calibration of the sonic log time-depth relationship.
A good synthetic tie confirms the geological identity of seismic reflectors; a poor tie signals log quality issues or wavelet extraction errors.

How Synthetic Seismograms Are Constructed

The construction of a synthetic seismogram begins with the acoustic impedance log, computed by multiplying the bulk density log (g/cm³) by the compressional wave velocity (m/s) from the sonic log at each depth sample. At each interface between depth samples, the reflection coefficient RC is calculated from the impedance contrast: RC = (Z_below - Z_above) / (Z_below + Z_above). This provides a series of reflection coefficients distributed in depth throughout the well, representing the theoretical reflectivity of the earth at the well location as a function of depth.

The depth-domain reflection coefficient series is converted to the time domain using the check-shot calibrated time-depth relationship from the velocity-shot survey, producing a reflectivity trace as a function of two-way seismic time. This time-domain reflectivity is then convolved with the seismic wavelet to produce the synthetic seismogram. Convolution simulates the effect of the seismic source waveform passing through the reflectivity series: each reflection coefficient becomes a scaled copy of the wavelet, and overlapping responses from closely spaced reflectors interfere constructively or destructively depending on their polarity and separation.

Synthetic Seismogram Applications Across International Jurisdictions

In Canada, synthetic seismograms are a standard deliverable from exploration and appraisal well logging programmes in the WCSB. AER well data submissions include sonic and density logs used to generate synthetics; the seismic-to-well tie from synthetic seismograms is documented in the formation evaluation report that supports pool establishment applications under Directive 065. Montney and Deep Basin tight gas play development uses synthetic seismograms to calibrate amplitude maps for reservoir thickness prediction at well locations before extending those relationships to interwell prediction.

In the United States, synthetic seismograms are required components of Gulf of Mexico deepwater field development technical packages submitted to BSEE; they provide the evidence that the seismic attribute maps used to justify field development well locations have been calibrated at existing well control points. In Norway, Equinor's Johan Sverdrup field development used extensively calibrated synthetic seismograms at every appraisal well to tie the Upper Jurassic reservoir reflector to the log-based formation top picks, enabling the seismic amplitude map to be converted to a net-pay thickness map for resource estimation across the 200 km² field area. In Australia, NOPSEMA-regulated Browse Basin exploration programmes require synthetic seismogram tie documentation as part of the resource estimation methodology review for SEC or PRMS-compliant reserve bookings.

Fast Facts

The seismic wavelet typically used for synthetic seismogram generation has a dominant frequency of 20-60 Hz for conventional exploration seismic data, corresponding to vertical resolutions (quarter wavelength) of 10-30 metres at typical sedimentary basin velocities. Broadband seismic acquisition that preserves frequencies from 2-3 Hz to 100+ Hz enables generation of higher-frequency synthetics that resolve thinner beds and improve the precision of seismic-to-well tie. The difference between a synthetic computed from a standard-bandwidth wavelet and one from a broadband wavelet can be as large as one seismic cycle (approximately 10-20 ms), sufficient to misidentify the geological marker associated with a seismic reflector.

Wavelet Extraction and Tie Quality

The quality of the synthetic seismogram tie to the real seismic data depends critically on the wavelet used for convolution. If the wavelet does not match the actual frequency content, phase, and amplitude spectrum of the seismic data near the well, the synthetic will not match the real seismic regardless of log quality. Wavelet extraction from the real seismic data in the vicinity of the well, using the statistical properties of the seismic traces or deterministic extraction using the known reflectivity from the well, produces a wavelet tuned to the actual seismic survey. Deterministic wavelet extraction using the known reflectivity of a seismic calibration well provides the most accurate wavelet for the subsequent tie, provided that the well's reflection coefficient series has sufficient contrast events to constrain the extraction.

Tip: When evaluating the quality of a synthetic seismogram tie, look at the cross-correlation coefficient between the synthetic and the real seismic trace in the target interval and report it alongside the visual tie display. A cross-correlation of 0.9 or higher indicates an excellent tie; 0.7-0.9 a good tie; below 0.7 a poor tie that should not be used for direct interpretation of reflector identities without investigation. Poor ties are commonly caused by cycle-skipped sonic logs, density logs with washout problems, or wavelet extraction issues rather than by geological complexity, and each of these causes has a different corrective action.

Synthetic seismogram is also known as:

Synthetic — the universal shorthand used in seismic interpretation, well-site geology, and geophysics teams; context establishes that "synthetic" means "synthetic seismogram" rather than any other synthetic quantity
Well tie or seismic-to-well tie — the process of comparing the synthetic seismogram to the real seismic data; sometimes used as a synonym for the synthetic itself in conversation
Zero-offset synthetic — the specific variant computed from vertical-incidence reflection coefficients assuming normal-incidence reflectivity; distinguished from angle-dependent or AVO-based synthetics that require elastic property logs

Frequently Asked Questions

Why is check-shot calibration necessary before generating a synthetic seismogram?

The sonic log measures compressional wave travel time between two receivers separated by approximately 60 cm on the tool; this measurement can contain cycle-skip errors and altered-zone effects that accumulate when the log is integrated to produce a time-depth curve. The check-shot survey measures the direct first-arrival travel time from surface to downhole receiver, providing the ground-truth time-depth relationship without any integration errors. Before generating a synthetic seismogram, the sonic log time-depth curve is forced to agree with the check-shot time-depth curve through a drift correction that redistributes the discrepancy while preserving the detailed interval velocity information. Without this calibration, the synthetic seismogram may be offset in time from the correct geological position by 10-50 ms, causing reflectors to be misidentified or geological horizons to be correlated to the wrong seismic event.

What causes a poor synthetic seismogram tie?

Poor ties arise from four main sources: log quality issues (cycle-skipped sonic, bad-hole density from washout), time-depth errors from uncalibrated or sparse check-shots, wavelet mismatch (using a wrong-frequency or wrong-phase wavelet), and genuine geological complexity (thin alternating beds, lateral velocity variation, or anisotropy effects). Diagnosing the cause requires examining each component: check the caliper log for washout (density issue), compare the integrated sonic time with check-shot times (time-depth issue), examine the statistical properties of the extracted wavelet versus the seismic spectrum (wavelet issue), and look at how ties vary across multiple wells in the area to identify systematic or random patterns.

Why Synthetic Seismograms Matter in Oil and Gas

Seismic reflection data is the primary tool used to map subsurface structure and stratigraphy across the lateral distances between wells, and the reliability of all seismic-based predictions depends on how well seismic events can be calibrated to known geological boundaries at well control points. Synthetic seismograms are the bridge that connects the high-vertical-resolution geological truth of the well log with the lower-resolution but spatially extensive seismic survey. In every field development programme from Cardium waterflood pattern design in the WCSB to turbidite reservoir delineation in the deepwater Gulf of Mexico to Arab Formation mapping at Ghawar, the synthetic seismogram tie at well control points is the foundation of confidence that the seismic interpretation being used to place development wells is correctly anchored to the geological model. A wrong or unvalidated synthetic tie propagates systematic errors through the entire seismic interpretation and can lead to wells that land in the wrong zone, miss the reservoir, or encounter unexpected fluid contacts.

Synthetic Seismogram: Definition, Seismic-to-Well Tie, and Log Integration