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Seismic data acquisition equipment
Collecting seismic data requires an energy source to generate waves and sensors to receive those waves. The appropriate energy source and receiver depend on the location and the application. This article describes different types of equipment used for seismic data acquisition.
- 1 Impulsive sources
- 2 Vibrators
- 3 Shear wave sources
- 4 Marine air guns
- 5 Seismic sensors
- 6 References
- 7 Noteworthy papers in OnePetro
- 8 External links
- 9 See also
- 10 Category
A variety of seismic sources exist that can apply vertical impulse forces to the surface of the ground. These devices are viable energy sources for onshore seismic work. Included in this source category are gravity-driven weight droppers and other devices that use explosive gases or compressed air to drive a heavy pad vertically downward. Dobrin and others    describe these types of sources.
Chemical-explosive energy sources are popular for onshore seismic surveys but are prohibited at some sites because of environmental conditions, cultural restrictions, or federal and state regulations. Chemical explosives are no longer used as marine energy sources for environmental and ecological reasons.
Field tests should always be made before an extensive seismic program is implemented. First, it should be determined whether the selected impulsive source creates adequate energy input to provide data with an appropriate signal-to-noise ratio and a satisfactory signal bandwidth at appropriate offset distances. Second, it is important to determine whether an impulsive source causes unwanted reverberations in shallow strata.
Vibroseis™ energy sources are some of the more popular seismic source options for onshore hydrocarbon exploration. The generic term vibrator refers to these types of seismic sources. Vibrators have several features that make them attractive for seismic data acquisition. They are quite mobile and allow efficient and expeditious illumination of subsurface targets from many different shotpoint locations. Also, the frequency content of a vibrator signal often can be adjusted to better meet resolution requirements needed for a particular target. In addition, the magnitude of the energy input into the Earth can be tailored for optimal signal-to-noise conditions by varying the size and number of vibrators or by altering the output drive of individual vibrators. For these reasons, vibrators are one of the most versatile onshore seismic energy sources.
Vibrators work on the principle of introducing a user-specified band of frequencies, known as the sweep, into the Earth and then crosscorrelating that sweep function with the recorded data to define reflection events. The parameters of a vibrator sweep are:
- Start frequency
- Stop frequency
- Sweep rate
- Sweep length
Start and stop frequency
A vibrator can do an upsweep that starts with a frequency as low as 8 to 10 Hz and stops at a high value of 80, 100, or 120 Hz. Alternatively, vibrators can do a downsweep that starts with a high frequency and finishes with a low frequency. Most Vibroseis data are generated with upsweeps.
Sweep rate can be linear or nonlinear. A linear rate causes the vibrator to dwell for the same length of time at each frequency component. Nonlinear sweeps are used to emphasize higher frequencies because the vibrator dwells longer at higher frequencies than it does at lower frequencies.
Sweep length defines the amount of time required for the vibrator to transverse the frequency range between the start and stop frequencies. As sweep length is increased, more energy is put into the Earth because the vibrator dwells longer at each frequency component. Sweep length is usually in the range of 8 to 14 seconds.
If a vibrator sweep is 12 seconds long, then each reflection event also spans 12 seconds in the raw, uncorrelated data. It is not possible to interpret uncorrelated Vibroseis data because all reflection events overlay each other and individual reflections cannot be recognized. The data are reduced to an interpretable form by a crosscorrelation of the known input sweep with the raw data recorded at the receiver stations. Each time the correlation process finds a replication of the input sweep, it produces a compact symmetrical correlation wavelet centered on the long reflection event. In this correlated form, Vibroseis data exhibit a high signal-to-noise ratio, and reflection events are robust wavelets spanning only a few tens of milliseconds.
Signal noise ratio optimization
As a general observation, if an area is plagued by random noise, vibrators are an excellent energy source because the correlation process used to reduce the vibrator sweep to an interpretable form discriminates against noise frequencies that are outside the source sweep range. If several sweeps are summed, unorganized noise within the sweep range is attenuated. However, if coherent noise with frequencies within the vibrator sweep frequency range is present, then the correlation process may accentuate these noise modes. References:           describes the operating characteristics of vibrators and their ability to optimize signal-to-noise ratios.
Ground force phase locking technology
Probably the most important improvement in vibrator operations has been the development of ground-force phase-locking technology. Application of this technology results in the same ground-force function (i.e., the same basic seismic wavelet) being generated during hundreds of successive sweeps by vibrators positioned over a wide range of ground-surface and soil conditions and by all vibrators in a multivibrator array. All aspects of seismic data processing benefit when a source generates consistent output wavelets throughout a seismic survey, hence the appeal of vibrators as the source of choice for most onshore surveys.
Shear wave sources
All seismic energy sources generate compressional (P) and shear (S) body waves. To study the physics and exploration applications of S-waves, it is often necessary to increase the amount of S-wave energy in the downgoing wavefield and to produce a shear wavefield that has a known vector polarization. These objectives can be accomplished with sources that apply horizontally directed impulses to the Earth or by vibrators that oscillate their baseplates horizontally rather than vertically. In either case, a heavy metal pad is used to impart horizontal movement to the Earth by means of cleats on the bottom side of the pad that project into the Earth. A specific design for a horizontal shear-wave vibrator can be found in a patent issued to Fair.
Horizontal vibrators have also been improved with the introduction of ground-force phase-locking technology that results in more consistent shear wavelets from sweep to sweep as horizontal vibrators move across a prospect. Surface damage has been minimized by reducing the size of the cleats underneath the baseplate so that they make only shallow ground depressions.
Marine air guns
Air guns are now the primary energy sources used in offshore seismic profiling. Chemical explosives are no longer used for safety reasons and because of their adverse effects on marine biology. Modern seismic vessels tow multiple arrays of air guns, and each array sometimes has 10 or more air guns. The size and position of each air gun in the array are engineered so that the output wavelet has:
- Minimal bubble oscillations
- Optimal peak-to-peak amplitude
Fig. 1 shows map and section views of the deployment of air guns from a seismic vessel. The air guns and hydrophone cable are positioned at proper lateral offsets from each other by steering vanes. Combinations of depth-control vanes and surface buoys keep the air guns and hydrophones at a constant depth as they are towed across a survey area.
The air gun arrays are powered by large onboard compressors that allow the guns to fire and repressure (to approximately 2,000 psi) at intervals of 8 to 10 seconds as the vessel steams along a prescribed course at constant speed. These high-repetition firing rates create shotpoints at regular spacings of 20 to 100 m, depending on boat speed, along the length of the source line. In wide-line profiling, a vessel tows several air-gun arrays spaced 50 to 100 m apart laterally to create parallel source lines in one traverse of the vessel across a prospect area (Fig. 1).
Fig. 2 shows the raypaths involved in air gun illumination of a geologic target. The seismic energy produced by an air-gun shot propagates up and down from the source array. The downgoing raypath creates the primary arrival. The upgoing raypath reflects from the water surface (where the reflection coefficient is –1 for an upgoing pressure wave) and travels downward as a time-delayed ghost event. Reduced-amplitude versions of the primary and ghost events follow at later times as the air bubble created by the shot oscillates and decays. These three components combine to form the air-gun source wavelet:
- Primary arrival
- Ghost arrival
- Bubble oscillations
Fig. 2 – Seismic raypaths involved in air-gun illumination of geologic targets.
The effectiveness of air gun array parameters is tested in deepwater environments in which a hydrophone can be positioned at a deep, far-field station to record the source output wavelet, as shown in Fig. 2. The term far field refers to that part of wavefield propagation space that is several seismic wavelengths away from the source. This far-field requirement means that the hydrophone depth, D, shown in Fig. 2 is several hundreds of meters.
Air gun arrays are designed to create source wavelets that are as compact in time as possible and that have minimal bubble oscillations. Compact wavelets are desired because such wavelets have wide signal-frequency spectra; minimal bubble oscillations are desired so that the signal spectrum will be as smooth as possible.
Fig. 3 shows an ideal source wavelet. The vertical dash line marks the arrival time of the bulk of the energy that travels the primary raypath (Fig. 2). The energy that travels the ghost raypath (Fig. 2) arrives at a time delay, 2d/v, where v is the velocity of the pressure pulse in seawater and d is the depth of the air-gun array
Fig. 3 – Key features of an air-gun wavelet.
The ghost event has a polarity opposite that of the primary arrival because the reflection coefficient for an upgoing pressure wave at the air/water interface is –1. The primary and ghost arrivals define the peak-to-peak amplitude of the source wavelet. Small-amplitude events occur at later times in the source wavelet because the air bubble produced by the air-gun discharge oscillates as it decays (Fig. 3). The number, sizes, and relative separations of the guns in the array control the amplitude of these residual bubble oscillations.
The two wavelet properties of greatest interest are its:
- Peak-to-peak strength (PTP)
- Primary-to-bubble ratio (PBR)
The objectives of air gun array design are to maximize the PTP property of an air gun wavelet, which is the difference, A–B, in Fig. 4, and to minimize the PBR parameter, which is the ratio (A–B)/(C–D).
Fig. 4 – Two important properties of an air-gun wavelet: peak-to-peak strength (A to B) and primary-to-bubble ratio [(A-B)/(C-D)].
Many factors, such as the number of guns in the array, the volume of the guns, and the depth of the guns, affect the amplitude, phase, and frequency character of an air gun array wavelet. Table 1 summarizes Dragoset’s analysis of air gun array parameters and their effects on the fundamental PTP and PBR properties of air gun wavelets. A key point in this table is that the number of guns in an array has a greater impact on the peak-to-peak amplitude (or wavelet energy) than does the volume of the guns.
Two classes of seismic sensors are used to acquire seismic data:
- Scalar sensors
- Vector sensors
A scalar sensor measures the magnitude of Earth motion created by a seismic disturbance but does not indicate the direction of that motion. A hydrophone is an example of a popular scalar sensor used throughout the seismic industry. Hydrophones measure pressure variations (scalar quantities) associated with a seismic disturbance. A hydrophone cannot distinguish a pressure variation caused by a downgoing wavefield from a pressure change created by an upgoing wavefield. Hydrophones provide no directional (vector) information about a propagating seismic event.
A vector sensor indicates the direction that a seismic event causes the Earth to move. The classic example of a vector sensor is the moving-coil geophone that has been used for decades to record onshore seismic data. The principal of a moving-coil geophone is that a lightweight coil, with several hundred turns of thin copper wire, is suspended by springs that are, in turn, attached to the case of the geophone. The springs are designed to allow the geophone case and the lightweight coil to move independently of each other over a frequency band of interest. Permanent magnets are attached to the geophone case to create a strong internal magnetic field. When the case is moved by a seismic disturbance, an electrical voltage is created as the coils cut the magnetic lines of force. The magnitude of the voltage output is proportional to the number of magnetic lines of force cut per unit time; thus, geophone response indicates the velocity of the geophone case, which, in turn, is proportional to Earth particle velocity at the geophone station.
The polarity of the geophone output voltage depends on the direction that the electrical conductors are moving as they cut across the magnetic lines of force. If an upward movement creates a positive voltage, a downward movement produces a negative voltage. Thus, a geophone is a vector sensor that defines not only the magnitude of Earth motion, but also the direction of that motion.
Because geophones are directional sensors and can distinguish between vertical and horizontal Earth motions, they are used to record multicomponent seismic data. Three-component (3C) geophones are used to record compressional and shear seismic data onshore. Shear waves do not propagate in fluids. In marine environments, geophones have to be placed in direct contact with the Earth sediment on the seafloor, with data-recording cables connected to surface-positioned ships or telemetry buoys. Four-component (4C) sensors used for this service are encased in large, robust, watertight enclosures that include a hydrophone and a 3C geophone. Fig. 5 illustrates a segment of an ocean-bottom cable (OBC) used for deploying 4C marine seismic sensors. In this cable design, a 4C sensor station is positioned at intervals of 50 m along the 150-m cable segment. A large number of these segments, each containing three receiver stations, are connected end to end to make a continuous OBC receiver line several kilometers long. The exact length of the receiver line is determined by the depth of the target that is to be imaged.
Fig. 6 shows an OBC line deployed on the seafloor and connected to a stationary data-recording vessel. A second boat towing an air-gun array traverses predesigned source lines either parallel to, or orthogonal to, the OBC cable. The 4C sensors remain motionless on the seafloor as data are recorded, just as onshore geophones do when onshore seismic data are acquired. Seafloor sensors are not towed as are the conventional marine hydrophone cables shown in Fig. 1.
- Dobrin, M.B. 1976. Introduction to Geophysical Prospecting, 630. New York City: McGraw-Hill Book Co.
- Telford, W.M. et al. 1976. Applied Geophysics, 860. Cambridge, UK: Cambridge University Press.
- Cholet, J. and Pauc, A. 1980. Device for Generating Seismic Waves by Striking a Mass Against a Target Member. U.S. Patent No. 4,205,731.
- Crawford, J.M., Doty, W.E.N., and Lee, M.R. 1960. Continuous Signal Seismograph. Geophysics 25 (1): 95-105. http://dx.doi.org/10.1190/1.1438707
- Geyer, R.L. 1971. Vibroseis parameter Optimization. Oil & Gas J. 68, (15): 116; and 68 (17): 114.
- Geyer, R.L. 1970. The Vibroseis System of Seismic Mapping. Canadian J. of Exploration Geophysics 6 (1): 39.
- Seriff, A.J. and Kim, W.H. 1970. The Effect of Harmonic Distortion in the Use of Vibratory Surface Sources. Geophysics 35 (2): 234-246. http://dx.doi.org/10.1190/1.1440087
- Goupillaud, P.L. 1976. Signal Design in the Vibroseis Technique. Geophysics 41 (6): 1291-1304. http://dx.doi.org/10.1190/1.1440680
- Bernhardt, T. and Peacock, J.H.: "Encoding Techniques for the Vibroseis System," Geophysical Prospecting (1978) 26, 184.
- Waters, K.H. 1978. Reflection Seismology—A Tool for Energy Resource Exploration. New York City: John Wiley & Sons.
- Cunningham, A.B. 1979. Some Alternate Vibrator Signals. Geophysics 44 (12): 1901-1921. http://dx.doi.org/10.1190/1.1440947
- Edelmann, H.A.K., and Werner, H. 1982. The Encoded Sweep Technique for Vibroseis. Geophysics 47 (5): 809-818. http://dx.doi.org/10.1190/1.1441348
- Sallas, J.J. 1984. Seismic Vibrator Control and the Downgoing P-Wave. Geophysics 49 (6): 732-741. http://dx.doi.org/10.1190/1.1441701
- Fair, D.W. 1964. Shear Wave Transducer. US Patent No. 3,159,232.
- Dragoset, W.H. 1990. Air-Gun Array Specs—A Tutorial. The Leading Edge 9 (1): 24-32. http://dx.doi.org/10.1190/1.1439671
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