Amplitude

Key Takeaways

• Seismic reflection amplitude is proportional to the acoustic impedance contrast at a subsurface interface, making it the primary seismic attribute for identifying lithology changes and fluid substitution effects, with amplitude anomalies (deviations from the background trend) used as direct hydrocarbon indicators when gas or oil reduce the acoustic impedance of a reservoir sand below that of the overlying shale, reversing the normal positive impedance sequence and generating a negative polarity (soft) or high-magnitude (bright) reflection: In a typical sand-shale sequence, clean reservoir sand has higher acoustic impedance than water-saturated sand (because quartz mineral modulus is higher than pore fluid bulk modulus), and shale has intermediate impedance between water-saturated and gas-saturated sand. Gas saturation reduces the bulk modulus of the pore fluid from approximately 2.2 GPa (water) to approximately 0.02 GPa (gas), lowering the acoustic impedance of the gas sand below the impedance of the overlying shale and generating a negative reflection coefficient at the shale-gas sand interface (soft reflection, negative polarity on SEG-normal convention displays). The magnitude of this soft reflection scales with the acoustic impedance contrast: for Viking gas sands in central Alberta (porosity 25 to 32%, gas saturation 70 to 85%, formation depth 500 to 800 m), the reflection coefficient at the shale-gas sand interface ranges from -0.08 to -0.18, generating amplitudes 1.5 to 3 times the background shale-shale reflections and visually identifiable as bright spots on 2D seismic sections and high-amplitude anomalies on 3D amplitude maps.
• Amplitude extraction from 3D seismic volumes along interpreted formation horizons produces amplitude maps that image reservoir architecture at a horizontal resolution of 15 to 40 m (one-quarter of the dominant seismic wavelength at the target depth), providing the primary input for Cardium and Viking shoreface reservoir mapping, Mannville channel sand delineation, and Montney sweet spot identification in WCSB exploration and development programs: Three-dimensional seismic amplitude extraction involves picking (interpreting) the reflection horizon corresponding to the top of the target formation on the seismic volume (using autotracking algorithms guided by seed points from well ties), then extracting amplitude values in a time window around the horizon (either the peak amplitude, the RMS amplitude over a gate, or the sum of amplitude over the net-sand time thickness derived from well log calibration). In the Cardium Formation at Pembina, amplitude extracted in a 4 ms gate around the Cardium D3 reflection correlates with shoreface sand net-to-gross ratio (R² = 0.72 in the calibration dataset of 68 wells) and with reservoir permeability (R² = 0.61), providing a spatial prediction of reservoir quality at 25 m spatial resolution between the existing well grid. These amplitude maps are used by Cardium operators to select infill drilling locations (targeting the highest amplitude cells within the proven productive area), to design waterflood injection patterns optimised for the actual sand distribution rather than the assumed uniform distribution, and to identify amplitude anomalies outside the drilled area that represent undrilled Cardium D3 extensions worth testing.
• Amplitude versus offset (AVO) analysis extends the information content of seismic amplitude beyond the normal-incidence reflection coefficient by measuring how amplitude changes with the angle of the seismic ray arriving at the reflector, providing the Vp/Vs ratio (compressional-to-shear velocity ratio) that discriminates lithology from fluid effects more definitively than normal-incidence amplitude alone, because gas substitution changes Vp strongly but Vs weakly, creating a characteristic AVO signature used to distinguish gas from brine in WCSB Viking and Cardium reflections: The Shuey (1985) approximation describes amplitude as a function of angle of incidence: R(θ) ≈ R₀ + G × sin²θ + F × (sin²θ × tan²θ), where R₀ is the normal-incidence reflectivity, G is the AVO gradient (controlling amplitude change from near to far offset), and F is the far-angle curvature term. The AVO gradient G is proportional to -2(ΔVs/Vs)(Vp/Vs)² × ρ̄/Δρ̄, meaning that reflectors with anomalous Vp/Vs (such as gas sands at Vp/Vs approximately 1.5 versus shale at Vp/Vs approximately 1.9) plot off the background trend on intercept-gradient crossplots, forming distinctive quadrant populations (Class III gas sands in the negative-intercept, negative-gradient quadrant) that are visually identified as hydrocarbon indicators. AVO analysis of Viking Formation gas sands in central Alberta reliably discriminates gas-saturated sands (AVO Class III, amplitude increasing with offset, crossplot in quadrant III) from brine-saturated sands (AVO Class I or IIp, amplitude decreasing or flipping polarity with offset) at exploration stage, improving pre-drill success rates by 20 to 35% compared to amplitude-only direct hydrocarbon indicator analysis.
• Four-dimensional (4D or time-lapse) seismic monitoring uses repeat amplitude surveys to track fluid substitution effects in WCSB heavy oil and conventional oil reservoirs during production, with amplitude changes between the base survey (pre-production) and monitor surveys (during or after production) indicating steam chamber growth in SAGD operations, gas cap expansion in gravity drainage pools, or waterflood front advancement in pattern floods, enabling production optimisation decisions that improve recovery without additional drilling: In Athabasca oil sands SAGD operations (Cenovus Foster Creek, CNRL Kirby, ConocoPhillips Surmont), the steam chamber that develops around the horizontal injector pair replaces cold bitumen (acoustic impedance approximately 4.2 MPa·s/m) with steam-heated mobile bitumen and steam (acoustic impedance approximately 2.5 to 3.0 MPa·s/m), creating a large negative impedance change that generates a strong amplitude anomaly on repeat 3D seismic. Annual 4D seismic surveys at Foster Creek (one of the most active SAGD 4D monitoring programs in North America) map the steam chamber geometry in three dimensions with 12 m vertical resolution and 40 m horizontal resolution, identifying wells where the steam chamber has not expanded to expected dimensions (indicating reservoir heterogeneity or fluid communication problems) and guiding decisions to add lateral wells, increase steam injection rates, or modify produced water reinjection to improve steam conformance. The economic value of 4D seismic at a major SAGD project is estimated at CAD 25 to 80 million per survey cycle through improved steam-to-oil ratio management and deferred workovers.
• Seismic amplitude is affected by many non-geological factors including recording geometry (near-surface coupling, source-receiver offset distribution), processing decisions (AGC scaling, spherical divergence correction, migration aperture), and overburden velocity variations that focus or defocus energy (amplitude distortion from velocity anomalies above the target), requiring careful amplitude-preserving processing and overburden calibration against well data before amplitude anomalies are interpreted as lithology or fluid indicators rather than processing or acquisition artifacts: Automatic gain control (AGC) applied during data processing normalises amplitude variations with depth by applying a time-varying gain factor that equalises trace energy over a sliding time window, suppressing the amplitude variation that would otherwise reflect both acquisition effects and genuine lithology/fluid changes. Amplitude-preserving processing for DHI analysis requires replacing AGC with spherical divergence correction (compensating for the expected geometric spreading of wave energy with distance from the source), Q-compensation (correcting for frequency-dependent attenuation in the overburden), and relative amplitude recovery (ensuring that the processing sequence does not destroy the relative amplitude relationships between reflections that carry DHI information). In the WCSB, overburden velocity variation above the Viking and Cardium targets (particularly from buried channel fills, gas chimneys above shallow gas zones, and deep glacial scour valleys) causes focusing and defocusing of seismic energy that creates apparent amplitude anomalies at the target level unrelated to reservoir properties — a class of amplitude artifact that has led to multiple dry exploratory wells in the Hanna and Olds areas of central Alberta, requiring tomographic velocity model building and anisotropic migration to mitigate.