Acoustic Log: Definition, Sonic Waveforms, and Well Applications

What Is an Acoustic Log?

An acoustic log records the acoustic properties of subsurface formations and the borehole by measuring traveltimes, amplitudes, and waveforms of compressional, shear, and Stoneley waves generated by transducers inside a downhole tool. Run as a wireline log or acquired in real time via logging-while-drilling (LWD), the acoustic log provides foundational data for porosity calculation, mechanical property estimation, cement bond evaluation, fracture detection, and seismic-to-well calibration.

How the Acoustic Log Works

A conventional sonic tool houses one or more transmitters and an array of receivers mounted on a rigid mandrel. The transmitter fires a short acoustic pulse, and each receiver records the arriving waveform train. Because different wave modes travel at different speeds, the recorded waveform contains distinct arrivals: the compressional (P-wave) arrives first, followed by the shear (S-wave), and then the slower guided modes including pseudo-Rayleigh and Stoneley waves. The interval traveltime (delta-t, or DT) between two receivers, divided by the receiver spacing, yields slowness in microseconds per foot (µs/ft) or microseconds per metre (µs/m). Modern monopole tools use 3 to 8 receivers spaced 15 cm to 30 cm (6 in to 12 in) apart to allow semblance processing and noise rejection.

Dipole sonic tools add low-frequency flexural transmitters oriented perpendicular to the tool axis. These generate a bending (flexural) wave in the formation that can be used to derive shear slowness even in slow formations where the formation shear velocity is lower than the borehole fluid velocity and no direct S-wave head wave exists. The ratio of compressional to shear velocity (Vp/Vs) is used to compute Poisson's ratio and, through the Gassmann fluid substitution equations, to distinguish gas-bearing from brine-saturated sands. SPWLA guidelines and the API Recommended Practice 31A (formation evaluation) govern data acquisition parameters, calibration procedures, and interpretation workflows in most jurisdictions.

Slowness-Time Coherence (STC) processing maps the full waveform array onto a two-dimensional coherence plane of slowness versus time. Peaks in coherence identify individual wave modes. This technique, introduced by Kimball and Marzetta in 1984, remains the standard processing method for separating overlapping arrivals in slow formations where simple first-arrival picks fail. The output is a suite of slowness curves for each identified mode, stored as continuous log curves alongside the raw waveform data.

Acoustic Log Across International Jurisdictions

Canada (Alberta and British Columbia)

The Alberta Energy Regulator (AER) Directive 009 (Casing Cementing Requirements) mandates a cement bond log or equivalent acoustic measurement on all wells in which the cement sheath forms part of a well-barrier element, including surface casing across freshwater zones and production casing above hydrocarbon zones. Sonic log data forms a core component of reservoir characterisation workflows in the Montney Formation of northeast British Columbia and northwest Alberta, where compressional and shear slowness constrain brittleness indices used to design hydraulic fracture stimulations. The AER digital data submission system accepts sonic log curves in LAS 2.0 and DLIS format. The British Columbia Energy Regulator (BCER) imposes equivalent CBL requirements under its well construction guidelines.

United States

The Bureau of Safety and Environmental Enforcement (BSEE) under 30 CFR Part 250 requires a cement bond log on all offshore wells drilled on the Outer Continental Shelf (OCS) where the casing string serves as a well barrier. The USGS National Petroleum Wells database archives digitised sonic logs from thousands of wells across the lower 48 states. In deepwater Gulf of Mexico operations, LWD sonic tools transmit compressional slowness in real time via mud-pulse telemetry, enabling drilling engineers to detect overpressured intervals by tracking deviations from a normal compaction trend, a technique first formalised by Hottmann and Johnson (1965) and now standard practice on all deepwater wells.

Norway and the North Sea

The Norwegian Petroleum Directorate (NPD) and the Offshore Norway (NOG) industry body require submission of digital well log data, including sonic curves, to the DISKOS national data repository for all wells drilled on the Norwegian Continental Shelf (NCS). The Petroleum Safety Authority Norway (Ptil) enforces well-integrity requirements under the Activities Regulations, which include CBL evaluation on all production and injection casing strings. Sonic log data from chalk reservoirs such as Ekofisk and Eldfisk are used in time-lapse seismic (4D) workflows to track velocity changes caused by reservoir compaction and fluid substitution over the producing life of the field.

Australia

The National Offshore Petroleum Titles Administrator (NOPTA) requires submission of all well log data, including acoustic logs in LAS format, as a condition of exploration and production titles under the Offshore Petroleum and Greenhouse Gas Storage Act 2006. The National Offshore Petroleum Safety and Environmental Management Authority (NOPSEMA) enforces well-integrity regulations that include CBL requirements for offshore wells. In the Carnarvon Basin, dipole sonic logs in tight Triassic Mungaroo gas sands provide the shear velocity input needed to derive dynamic Young's modulus and Poisson's ratio for wellbore stability analysis before horizontal well drilling campaigns.

Middle East

Saudi Aramco's EXPEC Advanced Research Center has deployed Dipole Shear Imager (DSI) tools extensively across Ghawar, the world's largest conventional oil field, to characterise mechanical anisotropy in the Arab-D carbonate reservoir. Shear slowness anisotropy measured by azimuthal dipole tools reveals the orientation of maximum horizontal stress, which governs hydraulic fracture propagation direction. Abu Dhabi National Oil Company (ADNOC) maintains an extensive sonic log library for the Thamama Group carbonates, using compressional and shear slowness in Gassmann substitution workflows to distinguish oil-saturated from water-invaded zones during reservoir surveillance.

Wave Modes and Full Waveform Sonic

Four distinct wave modes appear in a full waveform sonic record, each carrying different formation information. The compressional head wave (P-wave) travels through the formation at velocity Vp and is the fastest arrival. Its slowness, DT, is the primary output of all conventional sonic tools and is used directly in porosity equations. The shear head wave (S-wave) travels at velocity Vs, which is always slower than Vp. The Vp/Vs ratio is particularly sensitive to pore fluid: gas-bearing sands show Vp/Vs ratios near 1.5 to 1.7, well below the ratio of 1.9 to 2.1 typical of brine-saturated sands, because gas dramatically lowers Vp while leaving Vs nearly unchanged.

The pseudo-Rayleigh wave is a dispersive guided wave that exists only in fast formations (formation Vs greater than borehole fluid velocity). It travels along the borehole wall and is sensitive to borehole diameter and fluid type. The Stoneley wave is a low-frequency tube wave that propagates along the borehole fluid-formation interface at a velocity close to but slightly below the borehole fluid velocity. Its phase velocity and attenuation are sensitive to formation permeability through the Biot coupling mechanism, making it the primary acoustic tool for open-hole permeability estimation. Stoneley wave reflections from fractures or lithological boundaries are also used in fracture characterisation workflows.

In slow formations, the shear head wave does not exist because the formation shear velocity is lower than the borehole fluid velocity. Dipole sonic tools solve this problem by generating a flexural wave mode whose low-frequency limit equals the formation shear velocity. Most modern wireline and LWD sonic tools include both monopole and cross-dipole transmitter-receiver pairs to acquire compressional, shear, and Stoneley data in a single pass. Cross-dipole measurements also provide shear wave splitting analysis, which reveals azimuthal anisotropy in fractured or stressed formations.

Porosity, Mechanical Properties, and Pore Pressure

The Wyllie time-average equation, published in 1958, relates compressional slowness to porosity: DT = phi x DT_fluid + (1 - phi) x DT_matrix, where DT_fluid is approximately 189 µs/ft (620 µs/m) for freshwater mud and DT_matrix ranges from 47 µs/ft (154 µs/m) for calcite to 55 µs/ft (180 µs/m) for quartz. The Raymer-Hunt-Gardner (RHG) transform, introduced in 1980, is preferred for consolidated sandstones because it accounts for the non-linear relationship between porosity and velocity at lower porosities. Sonic porosity should always be cross-checked against neutron porosity and density-derived porosity to identify gas effects, secondary porosity in carbonates, and clay content in shales.

Dynamic elastic properties derived from compressional and shear slowness and bulk density include dynamic Young's modulus (E), dynamic Poisson's ratio (nu), bulk modulus (K), and shear modulus (G). These inputs feed directly into wellbore stability models that predict safe mud weight windows for wellbore integrity during drilling, and into hydraulic fracture models that predict minimum in-situ stress profiles for completion design. The Biot coefficient, derived from bulk modulus measurements, links pore pressure to the effective stress state used in geomechanical models.

Pore pressure prediction from sonic logs relies on the compaction trend method. In normally pressured shales, compressional slowness decreases with increasing depth as burial compaction reduces porosity. Where overpressure is generated by disequilibrium compaction, the shale retains higher porosity than expected for its depth, and sonic slowness plots above the normal compaction trend. The magnitude of the deviation, calibrated to measured pore pressures from wireline formation tester readings or mud weights, yields a quantitative pore pressure estimate. This method is particularly valuable in LWD real-time applications where it provides early warning of overpressured intervals during drilling.