Acoustic logging tools
Acoustic-logging devices are comprised of:
- Transmitters (sources)
- Receiver arrays
- Accompanying electronics
They have been designed to measure one or more acoustic-wave properties to obtain data about subsurface formations. This article focuses on the varied types of acoustic-logging tools and how they collect data.
Acoustic sources (transmitters) generally consist of piezoelectric transducers that generate the acoustic signal by converting electrical signals into a sonic vibration that travels through the borehole and adjacent rock formations. Monopole (axisymmetric) transducers generate omnidirectional acoustic waves around the tool circumference, while dipole (nonaxisymmetric) transducers generate azimuthally oriented acoustic waves (Fig. 1).
Modern receivers are piezoelectric crystals that transform the received (measured) acoustic signal back into electrical signals. Different logging tools use different piezoelectric materials and operate at different frequencies to measure different energy modes (wave types). The pressure variation produced by an acoustic wave displaces the piezoelectric material causing it to ring or oscillate. When the receiver oscillates, it develops a small voltage. This voltage is amplified and the raw data are processed downhole and sent to the surface-acquisition system in the form of a:
- Waveform signal (wireline)
- Acoustic slowness (wireline and logging while drilling [LWD])
Digital data are stored, either at the surface (wireline) or downhole (LWD), for wellsite log presentations and post-acquisition processing and playback.
The energy (amplitude) of acoustic waves is lost (attenuated or dispersed) primarily by travel through the borehole fluid and rock matrix. Additional attenuation may result from a number of other factors that include:
- Internal particle friction within the propagation medium
- Changes in acoustic impedance [the product of density (ρ) and acoustic velocity (V)] at interfaces (boundaries) between different mediums
- Borehole rugosity
- Signal cancellation resulting from tool eccentering
In general, the largest signal possible occurs when the instrument is in the center of the hole; a dipole tool in an extremely large borehole may be exception to this rule. For high frequencies, the monopole signal is reduced by as much 50% of the centralized value by displacing the instrument only inches from the center of the hole. Consequently, whenever possible, centralizers should be used with acoustic-logging tools.
The acoustic wave travels through the formation much faster than it does through the borehole fluid and reaches the receiver by the longer formation route first. This is true as long as the critical spacing is less than actual spacing. Critical spacing is the transmitter-to-receiver spacing at which the fluid-signal and formation-signal arrive at the receiver at the same time. The critical-spacing value depends on:
- Diameter of the logging sonde
- Diameter of the borehole
- Time of travel through the fluid
- Time of travel through the rock
In soft formations, and under certain conditions, the critical spacing can exceed actual spacing and the fluid arrival, which exists for a noncentralized tool, can interfere with the acoustic signal. When this occurs, data-processing methods can exclude this fluid arrival, thereby reducing or possibly eliminating interference from the fluid arrival. Longer transmitter-receiver spacings are used to minimize this occurrence.
The transmitter-to-receiver spacing in modern monopole tools is set to enable separation of the compressional- and shear-energy packets to allow for accurate measurement of both in fast formations. When logging with an array-acoustic device, the receivers nearest the transmitter see stronger acoustic waves than the more distant receivers.
The transmitter emits acoustic energy uniformly around the tool. In fast formations, this energy excites three waves that travel down the borehole wall:
See Acoustic logging for a discussion of acoustic theory and wave propagation, which includes each type of wave.
The compressional wave travels away from the transmitter with a velocity, Vf, in the mud. When these waves reach the borehole face, they are reflected, refracted, and converted according to Snell’s law (Fig. 2).
For angles of incidence less than the compressional-wave critical angle (θc, Fig. 2):
- Part of the energy is transmitted into the formation in the form of compressional wave (Wave A, Fig. 2)
- Another part is converted as a (refracted) shear wave (Wave B, Fig. 2)
- The remainder is reflected back into the mud as a compressional wave (Wave C, Fig. 2)
The transmitted waves travel at velocity Vp and Vs in the formation, close and parallel to the borehole wall, while continuously radiating energy back into the mud as converted compressional-waves, at the same compressional-wave critical angle at which it entered. It is this radiated energy that is detected by the receivers.
If the formation shear-wave velocity is slower than borehole-fluid compressional velocity (Vs < Vf), shear waves cannot be refracted along the borehole wall, and no shear wave is measured. Beyond the shear-wave critical angle, all the incident energy is reflected back into the mud to form the guided waves. The Stoneley wave travels at approximately the velocity of compressional waves in the borehole fluid. Compressional and Stoneley arrivals are always present. In the absence of a refracted shear-wave arrival (i.e., in formations in which Vp < Vf), the Stoneley wave can be used to estimate formation shear-wave velocity when a formation bulk-density measurement is available, using certain assumptions. However, because of the uncertainty associated with these assumptions, dipole shear-wave measurements are recommended in slow formations. Stoneley-wave amplitude decreases (attenuates) significantly at high frequencies and modern tools use low-frequency transmitters (< 1 to 12 kHz) to ensure acquisition of the Stoneley arrival in slow formations.
The dipole transmitter exerts a differential pressure on one side of the transmitter element that creates a flexural wave in the borehole, much like the wave produced when a vertical rope is shaken from side to side. The flexural wave is dispersive, but at low frequencies this wave travels down the borehole at the formation shear velocity. Receivers, sensitive only to differential pressures, are used to detect this flexural wave. Because the receivers are not sensitive to axially symmetric pressure fields, both the compressional head wave and the Stoneley waves are suppressed. This is desirable because it simplifies data processing. The desired output is the velocity of the formation shear wave. If the wavelength of the flexural wave is at least three times the diameter of the borehole, the flexural wave travels at very nearly the formation bulk-shear velocity. However, because this is a dispersive mode, if the wavelength is shorter (because of higher frequency), this flexural mode will travel slower than the shear velocity and dispersion corrections are needed.
All types of well logs, both open- and cased-hole, should be accompanied by complete documentation to ensure good-quality logs and sound interpretation. It is important to remember that any acoustic analysis represents an interpretation of measured acoustic waves. The wellsite engineer or geologist must ensure that all data pertaining to a particular log run are recorded in the well-log header for future reference, including:
- Borehole information (bit and casing sizes and depths)
- Tool configuration
- Borehole fluid
- Formation parameters
- Tool centralization
Cased-hole logs should also contain information on cement composition, casing weight and thickness, if the log was run with pressure, and the amount of that pressure.
Evolution of acoustic-logging tools
The most commonly used acoustic-wave property acquired in borehole logging is the compressional-wave velocity. Modern velocity-logging tools measure the time, Δt, required for a compressional or shear wave to travel through a fixed distance of formation; it is recorded as a function of depth. This parameter, Δt, referred to as the interval transit time, transit time, travel time, or slowness, is the reciprocal of the velocity of the compressional waves, Δt = 1/ Vp. For the formations typically encountered in acoustic logging, travel times range from 40 to 250 μsec/ft, corresponding to velocities ranging from 25,000 to 4,000 ft/sec (Table 1).
The resolution of any acoustic method is a function of the signal wavelength; the lower limit is one-quarter of the propagating wavelength. Seismic-reflection exploration methods typically operate in the frequency range of 10 to 50 Hz. In typical petroleum reservoir rocks, the resolution of these methods is approximately 30 to 160 ft (10 to 50 m), depending on depth (signal strength). In contrast, conventional BHC logging tools operate within the frequency range of 10 to 40 kHz, while newer array devices operate at even lower frequencies, 1 to 12 kHz. Logging-tool resolution is also a function of both the array aperture and the methodology employed for the array processing. Consequently, acoustic-logging tools typically have resolutions on the order of 1.0 to 4.0 ft (0.3 to 1.2 m) (see the page on resolution enhancement for more detailed information).
Acoustic well logging developed out of the need for downhole velocity (time-depth) measurements to improve the accuracy (calibrate) of surface seismic measurements. Surface seismic maps out sub-surface structures referenced to time and borehole acoustic tools provide a bridge to understand how time is related to depth. Downhole geophones were introduced in the 1930s to provide acoustic travel times to the surface, and continuous-velocity-logging tools were introduced in the 1950s (Table 2). Soon after the introduction of the continuous-velocity log, it was recognized that these data also provided an excellent means for:
- Stratigraphic correlation
- Lithologic identification
- Evaluation of formation porosity
The first acoustic-logging tools used a single monopole transmitter and a single receiver. Tool designs rapidly evolved to:
- Improve the accuracy of the velocity measurement by minimizing or eliminating influences related to borehole effects, i.e., fluid, geometry, and tool position (tilt) within the borehole
- To measure additional acoustic-wave properties
These simple devices were soon replaced by two receiver designs that had the advantage of eliminating the need to correct for travel time in the drilling mud (for more on the historical development of acoustic logging, consult the literature). Modern borehole-compensated designs, introduced in the 1960s, use two transmitters and two receivers to compensate for variations in borehole diameter and tool position within the borehole (Fig. 3). Two separate values of two receiver (R1 and R2) and two transmitters (T1 and T2) interval-transit times are provided, and an average of the two effectively compensates for any problems (Eq. 1).
- t1 = travel time between T2 and R1
- t2 = travel time between T2 and R2
- t3 = travel time between T1 and R1
- t4 = travel time between T1 and R2
- X12 = distance between R1 and R2.
Fig. 3 illustrates travel paths that show that the averages of AA′, BB′, and CC′ are essentially equal.
The BHC tools’ velocity measurements may be affected by a variety of factors (Table 3) including:
- Borehole diameter
- Signal noise
- Cycle skipping
- Δt stretch
- Velocity inversion
- Gas effect
- Dip angle, with respect to the borehole
Modern digital-circuitry and array-tool designs reduce or eliminate many of these problems, but they may still be present on older logs.
Conventional BHC monopole-acoustic logs, with their short transmitter-to-receiver spacing, have shallow depths of investigation and they largely measure mud filtrate that fills the pore space in the invaded (flushed) zone around the borehole. Long-spaced and array devices can acquire measurements beyond the filtrate and altered zone.
Long-spaced acoustic tools
Typical BHC devices have a transmitter-to-receiver spacing (TR) of 3 to 5 ft. These work well in many circumstances; however, in cases which borehole enlargement prevents acquisition of reliable data, due to the increase of the critical spacing, or in which the drilling process damages or alters the shales surrounding the borehole, long-spacing tools (TR = 8 to 15 ft) may be necessary, or advised, to obtain accurate measurements. In contrast to conventional BHC devices, in which the transmitters and receivers are arranged symmetrically, long-spacing tools use an asymmetric arrangement with the receivers at varying distances from the monopole transmitter (Fig. 4). Consequently, these devices have deeper depths of investigation that make them less susceptible to borehole conditions such as:
- Shale alteration
These tools operate in both open and cased holes.
Because long-spaced and array tools use an asymmetric configuration of transmitters and receivers, borehole compensation is achieved through a process called depth-derived borehole compensation (DDBHC) (Fig. 4). The processing is accomplished downhole by either the tool’s electronics or in the surface recording system and uses a depth-based delay to create synthetic transmitter arrays from multiple tool positions. The compensated travel-time measurement, Δt, is determined through the following procedure:
- At position three (Fig. 4), the transmitter (T) is at the depth where the far receiver (R2) will be when the tool is moved to position one. The interval-transit time (A) between the transmitter (T) and near receiver (R1), which includes mud and formation signals, is recorded and delayed (memorized).
- At position two (Fig. 4), the transmitter (T) is at the same depth the near receiver (R1) will be when the tool moves to position one. The interval transit time or waveform (B) between T and R2 is recorded and delayed.
- When the tool reaches position one, the two interval transit times (A and B) are equal to the interval transit time that would result if a second transmitter were below the receivers. The correct compensated value of Δt is obtained by combining the two delayed values of transit time (recorded at positions two and three) with transit times C and D, recorded at position one. Compensated transit time (Δt) is then correctly represented by
where x = the distance between R1 and R2 .
Analog recording of full acoustic waveforms, called "amplitude" logging, was developed in the 1960s. However, it was not until digital technology, instrumentation, and signal-processing methods were introduced in the late 1970s that the recording of full-waveform data became routine. While these techniques enabled the extraction of shear-wave data from conventional BHC acoustic data, determination of shear arrivals using conventionally spaced BHC tools (TR = 3 to 5 ft) suffers from interference between late-arriving compressional waves and shear-wave arrivals. The use of long-spaced tools reduced this problem by allowing greater temporal separation between the different wave packets and provided accurate estimates of shear–wave slowness.
Monopole array devices
Modern array tools are a natural outgrowth of the long-spaced tool design. Additional receivers (4 to 13) were added to provide the statistical redundancy needed to enhance extraction of wave arrival times; some designs also include multiple transmitters. The monopole transmitters in these tools use lower frequencies (e.g., 1 to 12 kHz vs. 20 to 40 kHz) and have broader frequency ranges than earlier tools to permit acquisition of high-quality acoustic waveforms. These devices are typically comprised of several sections or subs that house the tool components:
- Receiver array
- Acoustic isolator
The acoustic isolator, placed between the transmitter and receiver sections, prevents or minimizes and delays direct sound transmission between transmitters and receivers. The electronics section provides timing and control for the transmitter and receiver sections, digitizes the received acoustic waves, analyzes the acquired waveforms, and transmits the data to the surface-data-acquisition system, all in real time.
Array tools can record full waveforms: compressional, shear, and Stoneley arrivals. These tools operate in either a single or a variety of combination-acquisition modes that include:
- Full waveform
- Compression Δ t
- Cement-bond logging
The number of modes that can be activated during a single log run is a function of the logging speed. Acquisition of full waveforms permits the use of waveform-correlation techniques for waveform amplitude, coherent slowness from the coherent-wave moveout, arrival-time processing, and most importantly, allows for detailed post-acquisition processing that improves the interpreted results. Because these techniques are insensitive to cycle skipping, they are particularly effective in boreholes that are:
Through-casing acoustic measurements
The extended transmitter-to-receiver offset (6 to 19 ft) provided by array instruments allows them to quantify formation-compressional and shear-wave energy through casing. Successful cased-hole operation requires a good cement bond to provide the necessary acoustic coupling to the formation and to minimize or eliminate the casing arrival. New processing techniques may allow valid acoustic evaluation even in cases of poor bonding.
Dipole and multipole array devices
In hard (fast) formations, monopole array tools can acquire a refracted shear wave but not in soft and unconsolidated (slow) formations. Before the introduction of dipole transmitters, processing techniques were developed to derive shear-wave transit time from Stoneley-wave data.
Tools using dipole transmitters were conceived as early as the 1960s, but were not actually developed until the 1980s. In contrast to monopole logging tools, dipole acoustic devices can excite a low-frequency flexural wave in the borehole at shear velocity. Low-frequency (< 1 kHz) dipole sources allow for shear-velocity determination that is much closer to seismic shear waves and permits acquisition of direct-shear velocities in slow and fast formations. However, increased noise (i.e., a lower signal-to-noise ratio) is one limitation of low-frequency operation. Noise has been reduced through improved acquisition electronics, the use of semi-rigid tool designs, and by choosing the operational mode of the dipole source. A semi-rigid tool body not only reduces the influence of the tool body on the measurement but also permits operation in deviated wells.
At high frequencies, or when the borehole diameter is large, flexural-mode propagation is slower and a dispersion correction is needed to obtain the shear velocity from the measured flexural velocity. This dispersion correction is a function of mud compressional velocity, formation compressional and shear velocities, the ratio of formation and mud densities, and the product of borehole diameter and processing frequency. Few, if any corrections are required if the flexural wavelength (velocity/frequency) is at least three times the borehole diameter, which is why low frequencies (< 1 kHz) are used. Where a correction is necessary, it is typically only a few percent, but can be higher under certain conditions.
The latest commercial tool designs are multipole array devices that operate in open and cased hole. These tools typically integrate multiple transmitters (monopole and dipole) and one or more arrays of monopole and dipole receivers. Multiple monopole transmitters, or a single "programmable" transmitter, provide the preferred frequency-range for optimal acquisition of conventional BHC and long-spaced compressional, shear, low-frequency Stoneley modes along with cement-bond logs. The dipole transmitter, more recently a variable-frequency (wide bandwidth) transmitter, provides the crossed-dipole mode. The receivers are positioned axially along the length of the tool, for short- and long-spaced measurements, and may be interlaced or independent. At each axial position a group of receivers (e.g., 4 or 8) is positioned azimuthally around the circumference of the sonde. The receivers are oriented with the transmitter to allow for alignment of directional (multimode) source excitation and data acquisition. This allows radial imaging of acoustic parameters and measured properties. The dipole receivers may be aligned inline with the dipole transmitters or orthogonal (crossed) to them for crossed-dipole analysis.
Multipole tools provide enhanced Stoneley-wave and crossed-dipole shear-wave data for analysis of formation permeability and anisotropy (e.g., stress and fractures).
Ultrasonic reflection (pulse/echo) acoustic devices
Reflection (pulse/echo) acoustic devices were introduced in 1967 with the borehole televiewer (BHTV). In contrast to conventional acoustic-logging devices, which record the transmission of acoustic waves through the formation, pulse/echo devices record the travel time, amplitude, and azimuth of ultrasonic acoustic pulses (echoes) that are reflected off the formation wall in openhole or off the casing or cement in cased hole (Fig. 5). The difference between the acoustic impedance of the borehole fluid and formation determines the magnitude (amplitude) of the transmitted ultrasound pulse that is reflected off the formation and back to the transducer. A portion of the transmitted signal is not reflected and continues to travel into the formation (openhole) or casing (cased hole) (Fig. 5).
Televiewer-type devices use a rotating transducer that acts as both transmitter and receiver, to acquire as many as 250 samples per revolution. Because the tool is moving uphole continuously, data are acquired as a helical scan along the borehole (Fig. 6). Magnetometers provide azimuthal information for each scan. Acoustic devices operate in both:
- Conductive (water-based) muds
- Nonconductive (oil-based) muds
Televiewer-type tools cannot operate in air- or gas-filled boreholes.
The ultrasonic pressure pulses transmitted from the front face of the transducer form a beam pattern that defines the resolution and detection capabilities of the tool. While image resolution is directly proportional to signal frequency, the operating frequency (200 to 650 kHz) is a compromise between the desire for high image resolution and the need to operate in high-density muds in which signal attenuation is directly related to the frequency. In openhole, in which high-resolution, focused transducers are used, resolution may be as fine as 0.2 in. Image resolution in cased hole, in which unfocused transducers may be used, is generally lower.
The peak amplitude of the reflected signal is used to generate a 360° image of the borehole wall and the travel-time measurements are used as a caliper to provide a measurement of borehole geometry or casing corrosion. The primary factors that contribute to the measured pulse/echo amplitude are:
- Borehole-fluid ultrasonic attenuation
- Borehole-fluid/formation reflection coefficient
- Physical features of the formation
- Transducer-beam angle of incidence on the formation
Loss in signal amplitude (image quality) results from conditions that either scatter, absorb, or spread the acoustic energy (Table 4), such as:
- Tool eccentering
- Irregularities in the borehole shape and surface
- High-density and some oil-based drilling muds
- Contrasts in acoustic impedance between the borehole fluid and borehole wall or casing
A separate transducer, commonly in the "mud-sub," continually measures the borehole-fluid velocity for the caliper measurement.
In openhole, amplitude images of the borehole wall are used for:
- Fracture analysis
- Stress analysis (borehole breakouts)
- Formation evaluation
Cased-hole applications include:
- Cement evaluation (distribution and quality)
- Casing evaluation (wear and damage)
- Perforation control
Smooth casing or borehole walls produce high-amplitude reflections (light), whereas openings (e.g., fractures or vugs) or imperfections (e.g., rugosity or pitting) in the borehole wall or casing result in low-amplitude reflections (dark). These images are displayed in the typical open-cylinder image presentation (Fig. 7).
|R1||=||receiver one in a two-receiver tool configuration|
|R2||=||receiver two in a two-receiver tool configuration|
|t1||=||travel time between T2 and R1|
|t2||=||travel time between T2 and R2|
|t3||=||travel time between T1 and R1|
|t4||=||travel time between T1 and R2|
|TR||=||transmitter-to-receiver spacing (ft)|
|T1||=||transmitter one in a two-transmitter tool (BHC) configuration|
|T2||=||transmitter two in a two-transmitter tool (BHC) configuration|
|x||=||distance between R1 and R2|
|X12||=||distance between R1 and R2|
|Δt||=||transit time, sec|
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