Seismic Section

Key Takeaways

• The wiggle-trace display and variable-area display are the two fundamental formats for showing seismic data on a section — the wiggle trace shows each individual seismic trace as an oscillating waveform with amplitude proportional to the reflection coefficient at each interface, while variable-area shades the peaks of the waveform black (for standard polarity conventions where a positive reflection coefficient — hard reflection — appears as a positive peak), creating the visually compelling black-and-white patterns that characterize classic seismic sections; color displays now dominate in workstation interpretation, where amplitude is mapped to a color scale (typically warm colors for positive amplitudes, cool colors for negative) that allows interpreters to visually distinguish bright spots (high absolute amplitude) from dim areas and to trace reflector continuity across the section more easily than in grayscale; the choice of display color scheme and clipping (saturation) of extreme amplitudes significantly affects the visual appearance of a seismic section and can either reveal or obscure subtle amplitude anomalies, making display parameter selection an important and sometimes subjective step in seismic quality control and interpretation.
• Fault interpretation on seismic sections requires identifying discontinuities in reflector continuity — places where reflectors that are traceable across most of the section abruptly terminate and offset to a different two-way time on the other side of the discontinuity; normal faults (where the hanging wall has moved down relative to the footwall) create characteristic roll-over structures in the hanging wall in extensional basin settings, while reverse faults (where the hanging wall has moved up) create thrust ridges visible as anticlines with steeply dipping seismic reflectors on the upthrown side; growth faults in deltaic settings thicken sedimentary packages in the downthrown block, visible as a wedge of reflectors that is thicker on the downthrown side of the fault; identifying faults on 2D seismic sections is challenging because the 2D cross-section may not be perpendicular to the fault strike, creating apparent offsets that are smaller than the true throw; 3D seismic sections allow fault surfaces to be mapped in three dimensions using coherence or similarity attribute slices that reveal fault patterns invisible on individual vertical sections.
• Stratigraphic interpretation on seismic sections uses the geometry of reflector patterns (termination styles, thickness variations, and stacking patterns) to reconstruct the depositional history of the sedimentary sequence — the key termination styles defined in sequence stratigraphy (onlap, offlap, toplap, and truncation) are directly observable on seismic sections; a clinoform package (the progradational geometry of a delta front advancing into deeper water) appears as a set of downlapping reflectors that thin updip and thicken downdip, with the rollover point of the clinoform marking the paleo-shelf edge; channels appear as erosional surfaces (reflector truncation at the base) with internal fill reflectors that may differ in amplitude and frequency content from the surrounding stratigraphy; the connection between the seismic section's geometric pattern and the depositional interpretation requires knowledge of regional geology and sequence stratigraphy, and the same seismic pattern can support multiple geological interpretations when the well control is sparse.
• The seismic-to-well tie is the critical calibration step that anchors the seismic section to true geological depth and allows reflections to be assigned to specific stratigraphic units — the tie is accomplished by generating a synthetic seismogram (a trace calculated from the sonic log and density log at the well by computing the reflection coefficients from the impedance contrasts and convolving them with the seismic wavelet) and matching the synthetic trace against the seismic traces nearest the well; a good tie shows the major reflection events (bright reflectors, distinctive wavelet shapes) appearing at the same two-way time in both the synthetic and the real seismic data, confirming that the time-to-depth relationship at the well is correctly represented in the seismic section; a poor or impossible tie indicates either poor log quality (caving, invasion, or bad hole conditions causing incorrect velocity and density readings), an incorrect velocity model used in seismic processing, or a significant difference between the seismic wavelet and the wavelet assumed in the synthetic generation.
• Time-depth conversion transforms the seismic section from the two-way time domain (which preserves data accuracy) to the depth domain (which is needed for geological maps and well placement decisions) using the velocity model derived from seismic velocity analysis, well check-shot surveys, and VSP (vertical seismic profile) data; the converted depth section appears geometrically different from the time section in areas of lateral velocity variation — a salt body with much higher velocity than the surrounding shale will cause a velocity pull-up effect (reflections beneath the salt appear at shorter two-way time and therefore at shallower converted depth than their true position in a time section, an artifact corrected in depth conversion by using the true salt velocity in the conversion); in areas of simple geology with predictable velocity gradients, time and depth sections look qualitatively similar; in areas of complex velocity variation (salt provinces, gas clouds that reduce velocity, overpressured zones), the time section can give a significantly misleading structural picture that only depth conversion with accurate velocity modeling can correct.