Converted Wave: PS Wave Seismic Exploration

What Is a Converted Wave?

Converted wave (also called a PS wave or mode-converted wave) is a seismic wave that travels downward from the source as a compressional P-wave but converts to a shear S-wave upon reflection or refraction at a subsurface interface, then travels upward to the receiver as an S-wave recorded on multi-component geophones or ocean-bottom nodes. Because P-to-S conversion occurs at the reflecting horizon, converted waves carry complementary subsurface information to conventional PP reflections, including lithology discrimination, fracture characterization, and the ability to image beneath gas clouds that severely attenuate P-wave energy.

Key Takeaways

A converted wave travels down as a P-wave and up as an S-wave, so it is designated a PS wave in seismic notation.
The PS conversion point is geometrically offset toward the receiver, not at the midpoint; correct binning requires common conversion point (CCP) gathers rather than CMP gathers.
Multi-component acquisition uses 3-component (3C) geophones or 4-component (4C) ocean-bottom nodes to record the horizontal particle motion of the upgoing S-wave.
The VP/VS ratio derived by comparing PP and PS two-way times is a direct indicator of Poisson's ratio, separating brine sands from gas sands and shales.
Gas clouds that scatter and absorb P-wave energy are largely transparent to S-waves, making PS data the primary imaging tool beneath shallow gas accumulations.

How Converted Waves Are Generated and Recorded

When a P-wave impinges on a subsurface interface at non-normal incidence, Snell's law permits a portion of the energy to be transmitted and reflected as both P-waves and S-waves simultaneously. The converted (PS) reflection travels upward at the S-wave velocity of the overburden, which is typically 1.5 to 2 times slower than the P-wave velocity. Because the two legs of the raypath travel at different velocities, the PS reflection arrives later than the PP reflection from the same interface and exhibits a different moveout pattern on shot records. This velocity asymmetry is exploited to extract the VP/VS ratio, a petrophysical discriminator linked directly to Poisson's ratio and pore-fluid content.

Recording converted waves requires horizontal-component sensors. On land, 3C geophones measure vertical (Z), inline horizontal (X), and crossline horizontal (Y) particle velocity. The PP wavefield dominates the Z component while the PS wavefield appears primarily on the horizontal components after rotation into radial and transverse directions. Offshore, 4C ocean-bottom nodes or cables add a hydrophone (pressure) channel to the three geophone channels, enabling P-Z summation to suppress receiver-side ghosts and separation of up- and downgoing wavefields before PS extraction. Conventional towed-streamer surveys cannot record converted waves because the streamer records only pressure, not particle velocity.

Processing PS data requires a separate workflow from PP. Because the conversion point is asymmetrically located closer to the receiver (its exact position depends on the VP/VS ratio and reflector depth), traces cannot be sorted into conventional CMP bins. Instead, processors compute common conversion point (CCP) gathers iteratively, updating the VP/VS model until the CCP locations converge. Subsequent NMO correction uses an anisotropic moveout equation that accommodates the asymmetric raypath. Amplitude variations with offset on PS gathers carry different AVO signatures than PP data and must be interpreted with separate AVO intercept/gradient frameworks tuned to S-wave reflectivity.

Fast Facts: Converted Wave

Wave designation: PS (P down, S up); PP is the conventional all-compressional reflection
Sensor requirement: 3C geophones (land) or 4C ocean-bottom nodes/cables (marine)
Typical VP/VS ratio: 1.7-2.0 for brine-saturated sandstone; drops toward 1.5-1.6 for gas-saturated sand
Poisson's ratio range: 0.1-0.2 (gas sand) vs. 0.25-0.35 (brine sand or shale)
CCP offset fraction: conversion point lies approximately VP/(VP+VS) of the offset from the source
Gas cloud transparency: S-waves are unaffected by gas saturation in the overburden, unlike P-waves
4D PS monitoring: time-lapse PS surveys detect fluid movement and pressure changes in producing reservoirs
Fracture indicator: PS azimuthal anisotropy (fast and slow S polarizations) maps fracture strike and density

Acquisition Tip:

When planning a 3C land survey over a prospect with shallow gas hazards, orient the receiver lines to maximize offset-to-depth ratios above 1.5 for the target horizon. PS conversion efficiency peaks at incidence angles of 30-45 degrees; if the lines are too short, CCP coverage of the target will be sparse because the CCP migrates toward the receiver and may fall outside the patch. Discuss CCP fold maps with the processor before finalizing the geometry.

Converted wave is also referred to as:

PS wave — the standard two-letter notation indicating P down, S up raypath legs
Mode-converted reflection — emphasizes the change of wave mode at the reflecting interface
C-wave — shorthand used in ocean-bottom and 4C literature, particularly in the North Sea
Shear reflection — informal term used when the context makes it clear the wave was mode-converted rather than pure shear throughout

Frequently Asked Questions About Converted Waves

Why can't converted waves be recorded on a conventional marine streamer?

A towed hydrophone streamer measures pressure changes only, which are scalar quantities insensitive to the polarization direction of shear waves. Because the upgoing S-wave carries particle motion predominantly in the horizontal plane, it requires vector sensors (geophones) planted on the seabed to capture the horizontal components. Ocean-bottom nodes and cables with 4C sensors solve this problem; towed streamers fundamentally cannot, regardless of cable length or channel count.

How is VP/VS ratio derived from PS and PP data?

If the PP two-way time to a reflector is T_PP and the PS two-way time to the same reflector is T_PS, then VP/VS = (2 * T_PS / T_PP) - 1 under the assumption of a single horizontal layer. In practice, a layered-earth VP/VS model is built iteratively during CCP binning and refined by tying the PP and PS sections at well locations. The resulting VP/VS cube is input to fluid substitution workflows (Gassmann equations) to distinguish gas from brine in the pore space.

What is azimuthal PS anisotropy and why does it matter for fracture detection?

When S-waves travel through a fractured medium, they split into a fast component polarized parallel to the fracture strike and a slow component polarized perpendicular to it. The time delay between the fast and slow PS arrivals is proportional to fracture density. By acquiring PS data with multiple source-receiver azimuths and measuring the delay as a function of azimuth, geophysicists can map fracture orientation and intensity across the survey area, which is critical for horizontal well placement in tight carbonate or shale reservoirs where natural fractures dominate permeability.

Why Converted Waves Matter in Oil and Gas

Converted wave surveys add a physically independent dataset to conventional P-wave seismic interpretation. The VP/VS ratio directly constrains Poisson's ratio, one of the most reliable fluid indicators available without drilling a well. In basins where shallow gas clouds degrade PP image quality — the Gulf of Mexico shelf, the North Sea, offshore West Africa, and parts of the Barents Sea — PS data has been instrumental in de-risking prospects that were undrillable based on PP data alone. As ocean-bottom node technology improves and per-node costs decline, 4C PS acquisition is becoming standard on complex deepwater developments. Time-lapse 4D PS monitoring provides a window into sweep efficiency and bypassed pay zones that PP 4D monitoring cannot access when gas saturation changes in the reservoir alter P-wave impedance ambiguously. For operators targeting naturally fractured carbonates or unconventional plays, azimuthal PS anisotropy maps directly inform completion strategies and expected production per stage.