DELPH Seismic Advanced Notes

Delph Seismic
Advanced Notes

Delph Seismic – Advanced Notes

Copyright
© 2008, IXSEA, France. All rights reserved. No part of this manual may be
reproduced or transmitted, in any form or by any means, whether electronic, printed
manual or otherwise, including but not limited to photocopying, recording or
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permission of IXSEA.

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not limited to implied warranties of merchantability and fitness for a particular
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arising out of the use of this product.

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trademark of Intel Corporation.

MU-DSAN-AN-001-Ed A – July 2008 i


Overview of the Delph Seismic Advanced Notes

This document is the Delph Seismic Advanced Notes. It must be read and understood
prior to using the Delph Seismic system.
The manufacturer shall in no case be held liable for any application or use that does not
comply with the stipulations in this manual.
The Delph Seismic Advanced Notes document is divided into two parts:

• Part 1 – Seismic Imaging Principle: This first part contains a general presentation
of a seismic imagery system.
• Part 2 – Operating the Software: The second part describes the step by step
procedure to operate the Delph Seismic software.

A Table of Contents is available in the following pages to allow quick access to dedicated
information.

MU-DSAN-AN-001-Ed A – July 2008 ii


Table of Contents
I SEISMIC IMAGING PRINCIPLE ............................................................................................................1
I.1 Seismic Imagery System Presentation..................................................................................1
I.2 Seismic Imaging Principle ......................................................................................................2
I.2.1 Wave Propagation Ray Model ..............................................................................................4
I.2.1.1 Wave Propagation 4
I.2.1.2 Reflection and Refraction 5
I.2.1.3 Absorption 6
I.2.2 Seismic Sources ...................................................................................................................6
I.2.3 Seismic Receiver ..................................................................................................................8
I.2.4 Vertical and Horizontal Resolution........................................................................................8
I.2.5 Interpreting a Seismic Profile................................................................................................9
I.2.5.1 Diffraction Point 10
I.2.5.2 Reflection on a Nearly Flat Interface 11
I.2.5.3 Sloping Interface 12
I.2.5.4 Multiple Layers 12
I.2.5.5 Swell Effect 13
I.2.5.6 Multiple Reflection 15
I.3 Seismic Processing .............................................................................................................. 17
I.3.1 Processing Flow Chart....................................................................................................... 17
I.3.2 Frequency Filtering ............................................................................................................ 18
I.3.3 Chirp Processing................................................................................................................ 19
I.3.4 Automatic Gain Control...................................................................................................... 20
I.3.4.1 Linear Time Varying Gain 21
I.3.4.2 Decremental AGC 21
I.3.4.3 Linear AGC 22
I.3.4.4 Exponential AGC 22
I.3.4.5 Normalization (AGC power) 23
I.3.5 Seabed and Reflector Tracking ......................................................................................... 23
I.3.6 Stacking ............................................................................................................................. 23
I.3.7 Bottom Correction .............................................................................................................. 23
I.3.7.1 Swell Filter 24
I.3.7.2 Heave Correction 25
I.3.7.3 Topo and Tide Correction 26
I.3.8 Signature Deconvolution.................................................................................................... 26
I.3.9 Multiple Removal ............................................................................................................... 27
I.3.10 Surface Horizons Generation ............................................................................................ 28

II OPERATING THE SOFTWARE .......................................................................................................... 29
II.1 Software Architecture........................................................................................................... 29
II.2 Data Acquisition and Storage.............................................................................................. 29
II.2.1 Seismic Acquisition Parameters ........................................................................................ 31
II.2.1.1 Standard Analog Acquisition 31

MU-DSAN-AN-001-Ed A – July 2008 iii


II.2.1.2 Chirp Acquisition 34
II.2.1.3 FSSB Digital Acquisition 37
II.2.2 Auxiliary Data Acquisition .................................................................................................. 37
II.2.3 System Geometry .............................................................................................................. 38

II.3 Data Interpretation and Processing .................................................................................... 39
II.3.1 Software General Presentation.......................................................................................... 39
II.3.2 Processing ......................................................................................................................... 41
II.3.2.1 Temporal Processing 42
II.3.2.2 Spatial Processing 45
II.3.2.3 Detection Processing 46
II.3.2.4 Generation of Geosections and Surface Horizons 47

MU-DSAN-AN-001-Ed A – July 2008 iv


I SEISMIC IMAGING PRINCIPLE

I.1 Seismic Imagery System Presentation

Figure 1 – Seismic Imaging Flowchart

The various steps in the operation of a seismic system are shown on Figure 1:
• Step 1 - An acoustic source transmits a sound wave in the water
• Step 2 – The sound wave propagates through the water column
• Step 3 – The sound wave is reflected on the seafloor and the layer interfaces below
• Step 4 – The reflected sound wave is captured by the receivers
• Step 5 – The acquired data are visualized using the acquisition software
• Step 6 – The data are digitized and input into the interpretation software
• Step 7 – The user processes the seismic data before interpretation

The seismic imaging system produces an acoustic image of the reflector below the sea
bottom. It collects data in parallel survey lines. These raw acoustic signals are recorded
simultaneously with positioning data (GPS, USBL) using a dedicated acquisition software
program. Following this, using the tools provided by the processing and interpretation
software, it is possible to analyze the seismic profiles for classification and reporting
purposes. The processed data (geosections, reflector, annotations, and measurement)
can be exported to any cartographic GIS software to arrive at a full interpretation of the
survey area. In the GIS data fusion can be achieved with other kinds of data (magnetic,
side-scan sonar, bathymetry, etc.).

MU-DSAN-AN-001-Ed A – July 2008 1


I.2 Seismic Imaging Principle
Principle The basic principle in seismic imaging is to emit an acoustic wave that travels through the
sea bottom and to record the acoustic signals reflected by the geological layer interfaces.
The system is comprises:
• A seismic source that emits a series of acoustic pulses,
• A receiver that records the returned acoustic signal.
The seismic source is usually separate from the receiver. The receiver is a set of
hydrophones called a “streamer”. At the output, the system delivers one analog signal
called a seismic trace.

Multi-trace If the receiver is composed of multiple separate hydrophones or streamers, for each
emission, the system records multiple traces. This type of system is called a multi-trace
seismic acquisition system as opposed to a single or mono-trace system.

Chirp Chirp systems have been developed in order to provide complete monitoring of the
Systems emitted pulse. The system emits a chirp-modulated acoustic pulse but other modulations
in frequency and amplitude are also possible. In such a system, the source transducer is a
ceramic transducer and can also be used in reception. The operator can choose the
variations in frequencies and amplitudes of the chirp signal.

Survey The seismic source/receiver system is translated along a parallel path to survey a full
area. The reflected acoustic signals are stronger at the interface between two sediment
layers. The sediment can be modeled as a series of reflectors. Each reflector is defined by
its time and reflection coefficient. Mathematically, the trace signal is the convolution of the
acoustic wavelet (or acoustic signature) with the reflector series (see Figure 2). By
translating the emitter/receiver, a 2D seismic image is formed by the adjacent traces
arranged in columns. This image is called a seismic profile. The horizontal axis of the
trace is the along-track distance and the vertical axis is the two-way travel time (see
Figure 3).

Image The principle of imaging is to estimate from the recorded seismic traces, by inversion, the
true geophysical profiles, converting the two-way travel time to depth and retrieving the
main physical characteristics of each layer (density, absorption and propagation
velocities). The subject of this document is limited to 2D imaging, which means that the
seismic data is interpreted profile by profile. The 3D imaging process generates an image
of the volume composed of the combination of several seismic profiles.

Parameters The main important parameters that characterize a seismic system are penetrating depth
and vertical and horizontal resolution. The type of system of interest to us here is known
as high resolution seismic (HR). The vertical resolution is defined by the pulse width (or
bandwidth for modulated emissions). At higher frequencies, pulse width can be made
smaller (or bandwidth greater) increasing the resolution but at the price of decreasing
penetrating depth. Typically in the range 1 kHz to 10 kHz, the usual frequency range for



HR seismic, sound penetration may range from hundreds of meters under the sea floor to
just a few meters with resolution ranging from 1 cm to a few meters. The horizontal
resolution is the along-track distance between two emissions. This means that it will
degrade as water depth increases, although this parameter can be improved using certain
“multiping” techniques.

Figure 2 – Seismic Trace Model

Figure 3 – 1D Seismic Imaging



I.2.1 WAVE PROPAGATION RAY MODEL

I.2.1.1 Wave Propagation

Acoustic propagation in sediment is highly complex because the medium is in most cases
very heterogeneous. The seabed is then usually modeled as a succession of
homogeneous layers (the layer cake model in Figure 4). Each layer is characterized by its
thickness Δz and constant geophysical parameters. There are three main geophysical
parameters:
• Sound velocity c
• Density ρ
• Absorption coefficient α

Figure 4 – Sea Bottom Model (Layer Cake Model)

There are mainly two principal types of wave propagating in sediment:
• Compression waves (P wave) propagating in the direction of the pressure field
• Shear waves (S wave) propagating perpendicularly to the pressure field
These waves propagate at velocities dependent on numerous parameters such as
porosity, density, pressure, and so on. As a rule of thumb, it is possible to say that the
sound velocity will be higher in a hard sea floor such as rock or stone than in a soft floor
such as sand or mud. In Table 1 below, sound velocity values are given for different types
of medium. In the imaging process described later in this document, the effect of the shear
waves is left out of account. This simplification helps in understanding the basic principle
of imaging without fundamentally changing the interpretation.

Table 1 – Sound Velocity in Sediment

Medium Water Sand Hard bottom(rock)

Sound velocity(m/s) ≈ 1500 ≈ 2000 ≥ 3000



I.2.1.2 Reflection and Refraction

When an acoustic wave encounters an abrupt change between two geological layers, a
part of the energy is reflected back in the first layer and the other part is refracted (or
transmitted) in the second layer. The change in direction of propagation is governed by
Snell’s law. The propagation model used is the “geometric optic” model in which the
seismic wave is assumed to propagate along a ray. This model is valid insofar as the
wavelengths involved are smaller than the typical size of the homogeneities in the
sin (θ i )
medium. The Snell parameter p defined by p = is constant. θ i and ci are the
ci
incident angle and velocity. See Figure 5.

Figure 5 – Reflection and Refraction Laws at Sediment Interface

The reflection coefficient R is the ratio between the reflected and incident amplitude:
Z 2 − Z1 ρ i ci
• R= where Zi is the impedance of medium i defined by Z i =
Z 2 + Z1 cos(θ i )
where ρ i is the density, ci the sound velocity of the medium

• T the transmitted amplitude is such as 1 + R = T
For example, Table 2 gives the reflection coefficient at normal incidence for two interfaces:
a water/hard bottom interface and a sand/limestone interface.

Table 2 – Reflection coefficient

First medium Water ( ρ = 1.0, V = 1500 ) Sandstone ( ρ = 2.4, V = 2000 )

Second medium Hard Bottom ( ρ = 2.5, V = 3000 ) Limestone ( ρ = 2.4, V = 3000 )

Reflection coefficient 0.66 0.2



I.2.1.3 Absorption

The third main geophysical parameter characterizing sediment is the absorption
coefficient. This coefficient is highly dependent on acoustic frequency. At high frequencies
up to 10 kHz, penetration is less than a few meters in sand while sound can penetrate
several hundreds of meters at frequencies less than 1 kHz.

I.2.2 SEISMIC SOURCES

The earliest source was provided by explosives (TNT). These were then replaced by non-
explosive sources, involving the compression of gas or water:
• Air/Water guns
• Sparker and Boomer systems using electrical discharges (see Figure 6)
IXSEAprocessing chain is described in Figure 8 . For a chirp-modulated emission, the
1
temporal resolution is the inverse of the bandwidth τ = which can be further converted
B
c
as a vertical resolution δ= . Typically, a resolution of a few cm can be obtained with
2B
penetrating depths up to 200m. As an example, the Echoes 1500 works at a central
frequency of 1500Hz and its bandwidth is 300-3000Hz, providing 27cm resolution.

Table 3 – Seismic Sources

Seismic Sources Bandwidth

Water Gun 20-1500Hz

Air Gun 100-1500Hz

Sparker 50-4000Hz

Boomer 300-3Khz

Chirp 500Hz-200Khz



Figure 6 Boomer (left) and Sparker (right) Sources

Figure 7 Chirp Sub-Bottom Profiler (IXSEA Echoes 1500)

Figure 8 Chirp Sub-Bottom Profiler Processing Flowchart



I.2.3 SEISMIC RECEIVER

Streamer A streamer comprises a set of transducers electrically wired to act as a single receiving
system. The individual hydrophones are placed in a flexible tube filled with oil to ensure
acoustic coupling between the component elements and then sealed (see Figure 9). The
streamer is usually towed behind the source below the sea surface.

Figure 9 – Hydrophone streamer (from WHOI report 67-64, 1967)

Chirp System In a chirp sub-bottom profiler, the signal can be recorded on streamer but the emitting
transducer can also be used for reception. In this case, the beginning of reception of the
seismic signal occurs after the pulse-modulated signal has been emitted. This means that,
in shallow water, the selected pulse length needs to be sufficiently short.

I.2.4 VERTICAL AND HORIZONTAL RESOLUTION

For a chirp sub-bottom profiler the vertical resolution is given by the inverse of the
bandwidth. For an air/water gun or a sparker/boomer the vertical resolution is
approximately determined by the wavelet length and can be slightly improved by applying
signal processing techniques such as signature deconvolution. Figure 10 illustrates the
vertical resolution in each case: wavelet and chirp-modulated signal.

Figure 10 – Vertical Resolution for Chirp-Modulated and Wavelet Sources



The horizontal resolution is achieved after processing the data, after applying a migration
process either in 2D or 3D for instance. The resolution obtained is given by the along-
track distance between two successive emissions. This distance will depend on vessel’s
speed and the time interval between two emissions. The rate of repetition (also called the
shooting rate) is usually chosen for a desired penetrating depth. For deep water operation,
this could severely limit the horizontal resolution of the system.

Example In 6000 m of water depth, the two-way travel time of the acoustic pulse is 8 s. With a boat
speed of 4 knots (2 m/s), this gives a horizontal distance of 16m between individual shots.

Multiple One way to overcome this limitation is the “multiping” operating mode, which involves
Emissions sending multiple emissions into the water column at the same time. Theoretically, the
spatial sampling along the along-track should follow the Nyquist rule:
λ c
Δ< where λ= is the wavelength.
2 f
For a frequency of 1.5 kHz, the theoretical spatial resolution is then 0.75 m for a velocity of
1500 m/s. This acquisition mode is further detailed in section II.2.1.2.

I.2.5 INTERPRETING A SEISMIC PROFILE

The seismic profile is represented in 2D coordinates as the two-way acoustic travel time
versus along-track distance. See Figure 11.

Figure 11 – Example of a Sparker Profile

The principle of imaging is to make the link between this seismic profile and the
geophysics section represented as depth versus along-track distance. This relationship is
illustrated for the following basic cases:



• A diffraction point (see section I.2.5.1)
• A nearly flat seabed (see section I.2.5.2)
• A sloping seabed (see section I.2.5.3)
The following main effects are also illustrated:
• The multiple layer model (see section I.2.5.4)
• A swell distortion (see section I.2.5.5)
• A multiple reflection (see section I.2.5.6)
The system is assumed to be mono-trace with emission and reception collocated (zero-
offset imaging). The sea bottom is modeled as a homogeneous layer.

I.2.5.1 Diffraction Point

Where diffraction occurs (see Figure 12), the image in the seismic profile is a hyperbola
with its apex vertically above the diffraction point. The shape of the hyperbola is
dependent on the diffraction point depth d and the velocity c:

4( x − x0 )
2 2
4d
t ( x) −
2
2
= 20
c c

Figure 12 - Diffraction

Imaging The imaging process involves converting the seismic profile (time versus distance) into a
Process geophysical section (depth versus distance). This is accomplished by means of a process
called migration. A basic interpretation of this process is given here. As already indicated,
a single point generates a hyperbola. More generally, a seismic profile can be interpreted
as the sum of all hyperbolas generated by all the scatters in a profile. The reflection at an
interface can for example be modeled as the sum of all the hyperbolas generated by each
scatter along the interface. The principle of imaging is to reverse the propagation, with the
result that each hyperbola is collapsed into a point.
The principle is represented schematically in Figure 13. On trace xi, the reflection
occurring at time tj could have been generated by any scatter lying on the circle Cij. By
superimposing each circle for each trace xi and each reflection tj signal the hyperbola
collapses on the apex point and therefore images the source point. From another point of



view, the inversion process can be viewed as repropagating the wave backward in time.
For instance, at trace i, the event j is repropagated backward to time tj hence producing a
wave front similar to the circle Cij.

Figure 13 – Repropagation

I.2.5.2 Reflection on a Nearly Flat Interface

If we suppose a nearly flat seabed, as illustrated in Figure 14, and given a constant sound
velocity c through the water column, the imaging process converts the depth d 0 to a two-

2d 0
way travel time t 0 using the simple formula t 0 = . Thus the seismic profile simply
c
shows a near flat reflector.

Figure 14 – Imaging a Flat Surface



I.2.5.3 Sloping Interface

In the case of a sloping seabed or reflector (see Figure 15) the seismic image also shows
a sloping interface but the angle of the interface on the seismic profile differs from the true
one. Using a simple geometrical manipulation, the two angles are related by the formula:
tan (φ ) = tan (θ )cos(θ )

Figure 15 – Imaging a Sloping Interface

I.2.5.4 Multiple Layers

In practice the sea bottom is modeled as a series of homogeneous layers in which the
sound propagates at a constant velocity (“layer-cake” model). The interface between the
layers is not necessarily horizontal but it is usually assumed to be so. The model with
horizontal layers is valid for a small section (see Figure 16). The earth could also be
modeled as a constant velocity model by assuming a constant velocity V(z) up to depth z.
This value is chosen so that the difference between hyperbolas given by the layer cake
model and the constant velocity model is minimal. It can be shown that this velocity is the

RMS (Root Mean Square) velocity defined as Vrms ( z k ) =
1
tk
∑V k
2
Δt k .

Figure 16 – RMS Velocity and Constant Velocity Model



If a diffraction point at depth z is strong enough, the RMS velocity at that depth can be
estimated. If the RMS velocity can be obtained at two different depths, using from the
previous formula the internal velocity can then be obtained as
Vrms ( z k )t k − Vrms ( z k −1 )t k −1
Vk2 =
t k − t k −1

I.2.5.5 Swell Effect

If the sensor is moving up/down following the movement of the sea, the reflector will shift.
2d
In the absence of swell, an echo at a depth d appears at time t 0 = .
c
Where swell is present with an amplitude h (counted positive when the sensor is moving

2(d + h)
up) the echo appears at time t = (see Figure 17). This is illustrated on real data
c
in Figure 18.
2h
The corrected time t0 is obtained by t 0 = t − .
c
Swell amplitude can be determined in two ways:
• Swell amplitude is measured by a heave sensor rigidly fastened to the receiver and
the source. More precisely, the swell correction is in fact the sum of the measured
heave at the time of emission and the heave measured at the time of reception
• Swell amplitude is estimated on the data

The algorithm principle is as follows:
• The depth value is obtained by a bottom detection and tracking algorithm.
• The swell amplitude is then obtained by subtracting a low-pass filtered depth value.
The cutoff wavelength should be chosen according to the swell period observed.



Figure 17 – Swell Effect

Figure 18 - Swell on a Chirp Profile



I.2.5.6 Multiple Reflection

After a first reflection on the sea bottom, the acoustic wave may be reflected back by the
sea surface and the bottom again before being heard by the receiver. A second arrival
called a multiple is then superimposed on the seismic profile. Filtering techniques such as
predictive deconvolution have been developed to suppress or at least attenuate this
multiple reflection effect. On Figure 19, the multiple reflection effect is shown on a
synthetic slope seabed with angle θ . Two multiples are displayed: the sea surface
multiple and the bottom multiple. The emitter/receiver is at depth h. The sea surface

multiple is the primary reflector translated by 2h / c , the bottom reflector has a slope θ'
so that θ ' = 2 *θ (for small θ ).

Figure 19 – Multiple Reflection
When correcting the seismic profile for swell variation, the multiple is not fully corrected.
This is a way of identifying a multiple from the primary reflector (see Figure 20 and Figure
21).



Figure 20 – Swell Correction on Multiple

Figure 21 – Example of Swell Effect on Multiple



I.3 Seismic Processing
Before applying any interpretation or high-level imaging process for which multiple traces
or profiles must be combined, each raw trace signal should be previously filtered and
corrected for basic distortion such as electrical noise, signal attenuation and
source/receiver movement.

I.3.1 PROCESSING FLOW CHART

Low Level In the Delph Seismic Interpretation software, a full chain of low-level processing functions
is available either in real-time or in post-processing. The processing flow chart is shown
on Figure 22. This first processing segment (frequency filtering and automatic gain
control) is dedicated to improving signal-to-noise ratio and signal contrast.
The bottom detection and tracking functions are an essential part of the processing. It
outputs the time of the first return (the bottom echo) for each trace. This value is needed
for further processing such as swell filter multiple removal and signature deconvolution.

High Level Higher level processing functions such as multiple removal, signature deconvolution, are
available in post-processing.
When all the reflectors have been digitized on multiple profiles, surface horizons can then
be created.

Reflector Reflector digitization is one of the most important tasks in seismic interpretation and could
Digit be extremely tiresome with kilometers of survey line to process. An automatic tracking
algorithm is a key feature in this context. Error-free, fully automatic reflector tracking (and
sea bottom tracking) does not exist. For this reason, semi-automatic tracking is used in
practice.

Figure 22 – Processing Flowchart



I.3.2 FREQUENCY FILTERING

The acoustic pressure received on the hydrophones is converted to an analog electrical
signal voltage.

Process A high-pass filter is applied initially to cut the low frequency electrical signal often
generated by ground mass problem. The analog signal is then pre-amplified and digitized
using an analog/digital converter. The sampling frequency f s is adjusted according to the

Nyquist criteria: f s ≥ 2 f max where f max is the maximum frequency in the returned signal.

The f max is of the order of the maximum frequency in the source wavelet but the signal

spectrum is also dependent on sediment type. It is often desirable to be able to select the
high- or low-pass cut-off frequency. Signal frequency content and noise also change with
depth (time) and there are also advantages in varying the band-pass filter from the
beginning to the end of the trace. This filter is known as a Time Varying Filter (TVF).
Frequency filters are commonly and efficiently implemented as FIR (Finite Impulse
Response) or IIR (Infinite Impulse Response) filters. Of all the possible filters, the linear
phase filters, or better still a zero phase filter, are required in order not to avoid distortion
of the phase signal information (and time delay). Zero-phase filters are obtained by
applying the same linear filter in the forward and backward direction. An example of band-
pass filtering is shown in Figure 23.

Figure 23 – An Example of Band-Pass Filtering [100-3000Hz] (raw Up - processed Down)



I.3.3 CHIRP PROCESSING

Traditional seismic systems using explosive/implosive sources (boomers, sparker air
guns, etc.) are limited in resolution and frequency bandwidth. The resolution is given by
the wavelet length, which cannot be made arbitrarily short. One way to improve resolution
is to increase the bandwidth of the seismic source. A modern chirp seismic source emits a
FM linear pulse (chirp pulse) which can be given a large bandwidth (B > 10-20 kHz),
therefore providing high resolution. Increasing the pulse length T increases the signal-to-
noise ratio by a factor B x T with no degradation of resolution.
Upon reception, the signal is deconvolved by using the replica of the chirp source. Using
the phase and the quadrature signals, the instantaneous amplitude and phase are
computed. Usually, the envelope of the match-filtered signal is displayed (see Figure 24).

Figure 24 – Real part (in Phase) and Envelope of a Chirp Signal



I.3.4 AUTOMATIC GAIN CONTROL

The seismic signal is attenuated by the spreading of the acoustic wave and absorption in
the water while propagating to the seabed. It is therefore necessary to compensate for
these effects to recover a satisfactorily contrasted signal at greater depths. This is usually
done by multiplying the raw signal with a time varying gain curve. There are two
approaches to the computation of the gain curve:
• Adaptive: with the adaptive method, or Automatic Gain Control (AGC), the time
varying gain curve is computed from the signal itself and therefore changes from
one trace to another.
• Non-adaptive: with the non-adaptive method, each trace is multiplied by a fixed gain
curve.
In a traditional seismic system, the emitted wavelet amplitude/phase and shape may vary
from one ping to another, making automatic gain control preferable in such cases. A fixed
gain curve can be used for a chirp system, in which the emitted pulse is more stable.
Automatic gain control functions are also designed to avoid saturation (or clipping) of the
signal after amplification. The following sections contain a description of the most
commonly used time varying gain functions: linear varying gain, linear AGC, decremental
AGC, exponential AGC and first order normalization (called also AGC power). A typical
example of AGC correction is shown in Figure 25.

Figure 25 – Raw (top) and corrected profile (bottom) using an Automatic Gain Control function



I.3.4.1 Linear Time Varying Gain

In this case, the gain curve G(t) is a linear function of time with an initial and a final gain
(see Figure 26).

Figure 26 – Linear Time Varying Gain

I.3.4.2 Decremental AGC

For each trace, a decreasing envelope is obtained and the gain curve is computed as the
inverse (see Figure 27). Decremental AGC is very sensitive to noise: any spike in the
signal completely cause major distortion in the decrementing envelope.

Figure 27 –Decremental AGC



I.3.4.3 Linear AGC

In a first step, the signal is divided into intervals. For each interval i, the maximum of the
signal Mi is detected. A first gain value Gi is computed for each interval as the inverse of
the maximum (see Figure 28). These gain values are then filtered by limiting the gain
variation between successive intervals to a maximum variation Δg:
− Δg < G 'i +1 −G 'i < Δg
The corrected signal is never saturated and spikes in the signal are filtered. Selecting a
small window enables greater reinforcement of the finest signal details.

Figure 28 –Linear AGC
I.3.4.4 Exponential AGC

In a first step, the signal is divided into intervals. For each interval i, the maximum of the
signal Mi is detected. A first gain value Gi is computed for each interval as the inverse of
the maximum (see Figure 29). These gain values are then filtered by limiting the gain ratio
between successive intervals to a maximum variation Δg:
G 'i +1
− Δg < < Δg
G 'i
When using exponential rather than a linear AGC, greater variation between two
successive intervals is allowed, which reinforces the finer detail.

Figure 29 –Exponential AGC



I.3.4.5 Normalization (AGC power)

Normalization forces the signal to remain at an almost constant average value from
beginning to end of the trace. To do so, the trace is first filtered by a moving average
window to obtain the mean amplitude curve. The Gain curve is simply the inverse of the
filtered signal multiplied by a constant. This is illustrated in Figure 30. For a bipolar signal,
the function takes the absolute value of the signal.

Figure 30 – Normalization (AGC power)
I.3.5 SEABED AND REFLECTOR TRACKING

The basic principle of the seabed and reflector tracking function is to follow the strong
echo reflected by a sediment interface (or horizon) from trace to trace. Seabed detection
and reflector tracking are needed for additional interpretation and processing tasks. The
bottom reflector is assumed to be the strongest echo at the beginning of the signal. The
seabed tracking result can be replaced by any altimeter value that gives the water depth
but the conversion to two-way travel time needs a correct value for sound velocity. This
means that in practice detection of the first echo in the actual data is the best method.
Reflector tracking is usually very difficult: the reflector is not continuous and the signal-to-
noise ratio is low. For this reason, the automatic tracking functions are usually used
together with manual editing in order to arrive ultimately at a satisfactory result.

I.3.6 STACKING
Stacking is an operation used to improve the signal-to-noise ratio by simply adding
adjacent traces. Stacking is more effective if the trace has been corrected for vertical shift.
These corrections are explained in the next section. This operation is used where signal-
to-noise ratio is very poor because it also degrades horizontal resolution.

I.3.7 BOTTOM CORRECTION

The vertical time of the bottom reflector is shifted from its true position by vertical
movement of the sensor. The bottom correction function is used to estimate and correct
the signal for all such variations. The heave and swell filter functions are used to correct
the seismic profile for short-term variation. Longer-term effects may still be observed, for



example when multiple profiles cross the same geographical area. These longer-term
variations can be due to
• Depth Sensor Variations: since source and receiver are towed behind the vessel,
the depth sensor is moving up and down,
• Tide variations.
Depth sensor corrections are called topo(graphical) corrections.

I.3.7.1 Swell Filter

As explained in a previous section, the swell filter shifts the trace to correct from the swell
variation. Only the primary reflector is compensated (see Figure 31), multiple are not
compensated (see Figure 32).
2h
The correction is t
'
=t− where h is the swell amplitude counted positive upward.
c

Figure 31 – An Example of Swell Correction



Figure 32 – Swell Correction of Multiples
I.3.7.2 Heave Correction

The heave correction function uses the vertical motion measured by the heave sensor to
align the trace with the same reference altitude value. The reference altitude value for a
heave sensor is a local average of the altitudes detected by the heave filter. The
correction is effective if both source and receiver are rigidly mounted on the same body as
the heave sensor and if the mounting offset is known. The heave applied to the signal is
the average value for heave at emission and heave at reception. The correction is
hr + he
t' = t − where he, hr are the heave values at emission and reception.
c
Heave correction and swell filtering can be used together but as shown on the flow chart
in Figure 22 heave correction should be applied before tracking the seabed. The swell
filter can then correct for the residual vertical movement h.
hr + he 2h
The overall correction, heave and swell, is then given by t
'
=t− −
c c
This is illustrated in the sequence of figures (Figure 33, Figure 34, Figure 35 and Figure
36) based on IXSEA Echoes 3.5kHz data. Figure 33 is the raw seismic profile with no
vertical correction. The heave correction is applied first and the effect is clearly visible in
Figure 34, where most of the oscillations have disappeared, although some residual
artifacts are still visible. The swell filter is then applied using the bottom track value shown
in Figure 35 and final result is shown in Figure 36.



Figure 33 – Raw Seismic Profile Figure 34 – Heave-Corrected Seismic Profile

Figure 35 – Swell Detection on Corrected Profile Figure 36 - Filtering on Heave-Corrected Profile

I.3.7.3 Topo and Tide Correction
Following topo correction, seismic profiles are aligned on the actual sea depth. To be
more precise, the effective depth is usually assumed to be the average between the depth
at time of emission and the depth at time of reception.
The tide correction is then also applied and aligned to an absolute vertical reference value
such as the Mean Sea Level. The overall correction, topo plus tide, is then given by
Dr + De 2T
t' = t + − where Dr and De are respectively the depth measured at time of
c c
emission and reception and T is tide value.

I.3.8 SIGNATURE DECONVOLUTION
The seismic trace is usually modeled as a convolution between the source signatures
and the reflector model (see Figure 2). This model is valid insofar as the reflectors are well
defined and if it is possible to leave internal reflection and wavelet distortion out of
account. In that case, the application of a deconvolution process should enable
improvement of resolution and the signal-to-noise ratio on the reflector. The signature
shape needs to be known in order to perform deconvolution. If the signature is known,
such as a linear FM signal in chirp system, the theoretical signature wavelet can be used
to deconvolve the signal. Otherwise, the signature should be estimated from the signal
itself. If the seabed echo is a strong and isolated reflector, the signal around the seabed
echo will be a good replica of the emitted wavelet. When the signature has been obtained
(either theoretically or from the signal) the seismic trace can be deconvolved using familiar
techniques such as Wiener deconvolution.



I.3.9 MULTIPLE REMOVAL

As has already been seen in the case of a shallow-water survey, a replica of the sea
bottom reflector can be superimposed on the true signal and mask real features. Many
“multiple removal” techniques have been developed in order to mitigate the effect of
multiples in the signal. This is a difficult task and correction is never perfect. One of the
techniques is based on predictive deconvolution: the “multiple” signal is estimated as a
shifted and attenuated replica of the primary reflection. The shift is known to be
approximately twice the bottom time. For each trace a FIR filter is computed by cross-
correlation between the estimated replica and the signal. The estimated multiple is then
subtracted from the raw signal. This operation is applied to all the multiples in succession.
See Figure 37.

Figure 37 – An Example of Multiple Removal



I.3.10 SURFACE HORIZONS GENERATION

When a reflector interface has been digitized across multiple profiles, a 3D surface of the
reflector can be computed by interpolating between digitized points (see Figure 38 and
Figure 39). There are a number of approaches to interpolation, but a very efficient
technique known as Delaunay triangulation is often used: the surface is first constructed
as a mesh of facets, each facet being a triangle and being part of a triangular irregular
network (TIN) model. The TIN model is converted to a regular grid by 2D interpolation.

Figure 38 – Reflector Mapping

Figure 39 – Reflector Triangulation and Mapping



II OPERATING THE SOFTWARE

II.1 Software Architecture

Figure 40 – Delph Seismic Software

The Delph Seismic software (see Figure 40 and Figure 41) comprises two parts:
• Delph Seismic Acquisition software dedicated to the storage of seismic and
positioning data in XTF (eXtended Triton format file) or SEGY.
• Delph Seismic Interpretation software dedicated to real-time processing or post-
processing of the seismic profile.
The software runs on a standard PC platform using windows XP. Hardware and software
installation procedures are described in detail in the Delph Seismic User’s Manual.
One interesting feature is that acquisition and interpretation can run on two separate
workstations, with one PC dedicated to acquisition and interpretation running
simultaneously in real time on a remote platform.

II.2 Data Acquisition and Storage
The acquisition setup is clearly described in the Delph Seismic Acquisition User’s Manual,
allowing us to focus here solely on key features for acquisition.
The Delph Seismic Software interface is illustrated in Figure 42. The connection between
Delph and the hardware devices (seismic device, GPS, MRU, etc.) is realized through
dedicated independent servers:
• Serial Port and Ethernet Server dedicated to acquiring auxiliary data.
• Seismic Server for acquiring and controlling the seismic device (analog or digital)
Before starting any acquisition, the following three main sets of acquisition parameters
need to be configured with care:
• Seismic acquisition parameters
• Serial /Ethernet port configuration
• System Geometry



Figure 41 – Software Architecture

Figure 42 – Delph Seismic Acquisition



II.2.1 SEISMIC ACQUISITION PARAMETERS

There are three different acquisition systems, each configured using its own server:
• Standard Analog Acquisition
• Chirp Acquisition
• FSSB Acquisition

II.2.1.1 Standard Analog Acquisition

Synchronous In this configuration, the seismic analog data are digitized using an analog-to-digital board
Acquisition plugged into the PC. See the acquisition parameters in Figure 43. The signal is digitized to
24 bits with an input dynamic of +/- 10Volts. Acquisition synchronization can be either
master or slave. In master mode, a TTL board is also plugged into the PC to generate the
synchronization pulse. This TTL pulse is sent simultaneously to the seismic device and
the acquisition board. In this case, the trigger detection parameters (level and detection
edge) should be selected as 1.0V and “Rising Edge”. In slave mode, the trigger detection
parameters should be selected according to pulse level and shape.
Up to six channels can be recorded simultaneously.

Figure 43– Acquisition Parameters

Definition of acquisition parameters:
Shooting Rate (or Shooting Interval): This is the time interval between two successive
emissions. A better term for this would be “shooting interval” since it is expressed as a
time duration. This parameter can be adjusted in master mode to trigger the source. It
determines the along-track resolution as explained in section I.2.4
Sampling Frequency: This is the sampling frequency used by the A/D board to digitize
the analog signal. The value for this frequency is chosen to ensure that it is more than
twice the maximum frequency expected in the signal.



Recording Delay: This is the time interval between time of the emission and the
beginning of the acquisition. This parameter can be changed in real time and should be
smaller than the water depth. It is best set to 0 for shallow water survey and adjust it only
for deep water to save disk space.
Recording Length: This is the time duration of the acquisition. The number of acquired
samples is obtained by dividing the time duration with the sampling frequency. This
parameter should be adjusted according to the expected penetrating depth of the source.
Coupling Mode: The coupling mode can be set to AC or DC. When using AC, the signal
is high-pass filtered before digitization. This is required in seismic acquisition where the
signal should have a zero average value.
A review of all the definitions is given in Figure 44 below

Figure 44 Definitions of and relationships between the main acquisition parameters

As discussed above, the recording parameters follow the set of inequations defined
below:
• Recording Delay < 2 x WaterDepth / SoundSpeed
• Recording Length + Recording Delay < Shooting Interval
• Recording Length + Recording delay > 2 x (PenetratingDepth + WaterDepth) /
SoundSpeed
These relations define a validity domain illustrated in Figure 45.



Figure 45 - Validity Domain for Acquisition Parameters

Asynchronous In the asynchronous mode, two channels are recorded independently with two different
Acquisition sets of acquisition parameters, see Figure 46. One channel is usually called the “fast
channel”. This channel pings at a higher shooting rate than the other channel, the “slow
channel”. The fast channel is a high frequency source providing better resolution near the
bottom and the second is a low frequency channel offering greater penetrating depth. The
two sets of data are recorded in two different files.

Figure 46 – Asynchronous Acquisition



II.2.1.2 Chirp Acquisition

Design In chirp mode, the system emits a chirp pulse using a D/A board plugged inside the PC.
On its return, the signal is digitized using the same analog/digital board as in the standard
case (24 bits, +/-10 Volts dynamic). The chirp signal can be defined using the chirp editor
software (see Figure 47) . The following parameters can be adjusted:
• Minimum and Maximum Frequency: These frequencies need to be adjusted
according to the bandwidth specifications of the transducer.
• Chirp Length: The processing gain, which is the increase in the signal-to-noise
ratio after match filtering is BT where B is the bandwidth and T the chirp length.
A longer chirp increases the signal-to-noise ratio. But in practice, there are practical
limitations to this. The D/A card uses an internal buffer of limited size
( N max = 4096 samples) which also limits the chirp length. If f max is the maximum

frequency of the chirp, the sampling frequency Fe of the D/A board should
be f e ≥ 2 f max in order to meet the Nyquist criteria. This means that the minimum

number of samples for a chirp of length T and of maximum frequency f max is

N = 2Tf max and we should have N ≤ N max . The chirp length is also limited by the
water depth: during pulse emission, reception is saturated when using a streamer
or is stopped one if the same transducer is used for emission and reception. In
order to avoid disturbance to the signal, the pulse length T should be chosen
2d
according to T ≤ where d is the water depth and c the estimated sound
c
velocity.
• Frequency Modulation: One of four types of modulation can be selected:
Linear: the frequency increases (or decreases) linearly from beginning to end
of the pulse.
Triangle: two variation slopes can be selected: one at the beginning of the
pulse and the other at the end.
Logarithmic: an increasing or decreasing frequency variation can be selected
Power: the frequency variation is a polynomial variation (either increasing or
decreasing). The degree of the polynomial can be selected.
The frequency bandwidth should match the transducer bandwidth. For instance,
the bandwidth of the system Echoes1500 is 650 Hz - 2.5 kHz so the low frequency
should be greater than 650 Hz and the high frequency less than 2.5 kHz.
• Amplitude Modulation: The amplitude modulation function determines the
envelope of the chirp signal. There are four types of amplitude modulation
available:
No modulation
Gauss: The envelope is a Gaussian. The width and position of the maximum of
the Gaussian can be selected.



Cosbell: In the Cosbell modulation function, the gain increases as a cosine
variation from 0 to 1 during a time interval, then decreases from 1 to 0 at the
end of the signal. The time interval value is user-selectable.
Hamming: The modulation is a cosine function. There is no parameter.
Using an amplitude modulation function decreases the side lobe amplitude in the match-
filtered signal at the expense of degrading the resolution.

Figure 47 – Chirp Acquisition Interface (left) and Design tool box (right)

Multiping In the case of the standard system, two acquisition modes are available: master or slave.
Acquisition In master mode, the operator can also activate the multiping acquisition mode.
Mode
As explained in section I.2.4 , this pinging mode is used to improve the along-track
resolution where the water is very deep (typically hundreds of meters). The basic principle
involves sending multiple pings into the water column. A nominal shooting interval is
selected to provide the desired along-track resolution. This nominal shooting interval value
should be set at a higher level than the minimum shooting interval supported by the
seismic source. If the water depth is known, the system can then compute a shooting
interval as close as possible to the nominal value. If the water depth is measured using an
altimeter, you can select this entry to ensure that the system automatically computes the
shooting rate. Otherwise, it is possible to set the recording delay manually, which is taken
as the water depth value. In automatic mode, the water depth is converted to a two-way
travel time using the sound velocity value. The software does not continuously change the
shooting rate at every variation in water depth. The software requires recording delay to
be varied in steps. The “Recording Delay Step” parameter is the window size in which the
recording delay (like water depth) can vary. At each excursion of water depth outside this
window, the window is shifted to center on the new depth value and a new shooting rate
and recording delay is computed for the following traces. This is illustrated in Figure 48.



Figure 48 - Multiping Algorithm Principle

Parameters Where the standard acquisition mode is concerned, the operator selects a recording
Selection length which corresponds to the expected penetrating depth. However, in Chirp mode, in
order to get a correct match-filtered signal at the end of the trace, this value should be
increased with the chirp length.

Figure 49 - Relation between Acquisition Parameter in Chirp Mode

In multiping mode, the recording length should be increased along with the “recording
delay step” parameter. As is also explained in the Design section, during the time of the
chirp emission, the received signal cannot be exploited. This entails a need to increase
the nominal shooting rate set in multiping mode by the chirp length.



In Chirp mode, the recording parameters should therefore follow the set of inequations
defined below (see also in Figure 49):
• ChirpLength < 2 x WaterDepth / SoundSpeed
• RecordingDelay < 2 x WaterDepth / SoundSpeed
• RecordingLength + RecordingDelay < ShootingRate
• RecordingLength + RecordingDelay > 2 x (PenetratingDepth + WaterDepth) /
SoundSpeed + ChirpLength
In Multiping Mode we also have:
NominalShootingInterval> 2 x (PenetratingDepth + WaterDepth) / SoundSpeed + 2 x
ChirpLength

II.2.1.3 FSSB Digital Acquisition

The FSSB server is dedicated to the acquisition of all the Edgetech sub-bottom profiler
The FSSB device can be fully configured using the Ethernet interface. See Figure 50.

Figure 50 – FSSB Server

II.2.2 AUXILIARY DATA ACQUISITION

Auxiliary data are recorded through a serial or Ethernet interface using the dedicated
Serial server. The server is also responsible for the synchronization of the PC clock with
the GPS time: as soon as a GPS time is acquired, the server computes the time
difference between the PC clock and the GPS time. If the time difference is more than half
a second the PC clock is resynchronized. Serial data are then time-stamped inside the
server using the PC clock.
The main important sensors that can be acquired are:
• Any standard positioning system which sends NMEA strings,
• Heave sensors such as the IXSEA Octans,
• TSS motion sensors,
• Depth sensors providing a depth output in the form of a standard NMEA string.
The software interface of the Serial server is shown in Figure 51.



Figure 51 – Serial/Ethernet Server

II.2.3 SYSTEM GEOMETRY

Figure 52 – Set-UpGeometry

Before starting any acquisition, the system geometry needs to be correctly defined. This is
accomplished through the system geometry graphics tool show in Figure 52 above. Care
must be taken to enter the correct offset or some of the processing functions may not work
correctly (heave correction, mapping, etc.). All offsets are measured with respect to an
arbitrary point in a three-axis reference frame.



II.3 Data Interpretation and Processing

II.3.1 SOFTWARE GENERAL PRESENTATION

Figure 53 – Interpretation Software Architecture in Real Time

The Delph Seismic Interpretation software is a standalone software program for
processing individual seismic profiles either in real-time or in post-processing. In real time,
the Delph real-time monitor makes the connection between the acquisition and
interpretation software. The monitor looks for a newly acquired seismic file (XTF or SEGY)
and when a new file is created, it automatically runs the interpretation software. In post-
processing, the interpretation can also be executed from the Delph RoadMap software
(see Figure 53, Figure 54, Figure 55).



Figure 54 – How to Start

Figure 55 – Interpretation Software Architecture Post-processing

In the interpretation software, the seismic profile is displayed horizontally. The vertical axis
is the two-way travel time. The horizontal axis is the along-track distance in meters
computed from the beginning of the file as shown in Figure 56. All the processing
functions are gathered in the processing panel. The interpretation tools such as
digitization are located in the interpretation panel.



Figure 56 – Interpretation Software Interface

II.3.2 PROCESSING

The general processing flowchart shown in Figure 22 summarizes the processing
functions briefly described in I.3.
This section is intended to provide more insight into how this processing is implemented in
Delph Seismic Interpretation and also to explain the meaning of all the parameters. This
ensures better understanding of how and why to adjust them.
In Delph Seismic Interpretation, the processing functions are divided into three groups as
shown in Figure 57.

Figure 57 - Delph Seismic Interpretation Processing Functions

The surface horizon and geosection generation functions, which are described later, are
not included in this panel but are accessible in post-processing through the replay loader
tools or directly in Delph RoadMap.



II.3.2.1 Temporal Processing

• Filter
Available filters are Low-Pass, High-Pass and Time Varying Filter, see Figure 58.
High-pass and low-pass filters are zero-phase IIR filters. Low-cut frequency can be
selected in the range 1% to 30% of the sampling frequency, and the high-cut frequency in
the range 15% to 40% of the sampling frequency. As shown in the processing flow chart,
the high-pass filtering is applied first and the low-pass filtering is applied after the AGC
function. Low-pass filtering is useful to attenuate high-frequency noise levels appearing in
the signal after applying AGC functions.
For the Time Varying Filter (TVF), two bandwidths must be selected:
one for the beginning of the trace,
and the other for application at a user-defined time (end of variation parameter).
When using the Time Varying Filter, the trace signal is filtered twice using each band-pass
filter and the final trace output is simply a linear combination of the two band-pass filtered
signals. The band-pass filter is obtained by successively applying a high-pass and a low-
pass filter. The TVF function is applied before any AGC functions.

Figure 58 – Frequency Filtering Parameters



• Gain Control
In Delph Seismic Interpretation, five different gain controls are available (see Figure 59).

TVG The first, TVG, applies a fixed gain to the signal. All that is needed is to select the gain for
the beginning (start gain) and the end of the trace (end gain). The gain values are in the
range [0-100]. If for example a “Start Gain” of 2 is selected, and an “End Gain” of 10 this
will mean that mean that the value of the first sample is multiplied by 2 and the value of
the last sample by 10. In between, the gain value will be varied linearly.

The other four gain functions described below are all adaptive gain methods. These
principles have been explained in section I. The strength parameters for linear and
exponential AGC correspond respectively to the maximum increment or ratio ( Δ g ). The

AGC power is the normalization gain.

AGC In the case of AGC (decremental, linear and exponential), decreasing the window size
increases the resolution, enhancing the finer details. Gain increases with increasing
strength.

AGC Power Where AGC power is concerned, the window size is the size of the moving average
window and the strength is the reference amplitude value expressed as a percentage of
the maximum level. Decreasing the window size increases the normalization effect and
small detail disappears. Gain value increases with strength.

Figure 59 – Selection of AGC parameters



• Signature deconvolution
Signature deconvolution can be used to improve temporal resolution and signal-to-noise
ratio. The bottom return must have been detected previously using the bottom detection
function. The signature template is extracted from the signal itself. The process is
governed by three parameters (see Figure 60). The signature to seabed parameter value
indicates the beginning of the template relative to the sea bottom and the signature length
parameter indicates the estimated signature length. The “Noise Level” is the Wiener
parameter relative to the maximum of the spectrum. The admissible range is [0-100%].
The Wiener parameter should be increased if the signal is noisy. In the time domain, the
seismic trace s(t) can be expressed as a convolution of the reflectivity function r(t) with the
signature signal s (t ) = r (t ) ⊗ h(t ) : The filtered reflectivity spectrum is obtained in the
Fourier domain using the Wiener filter expressed as follows:

S (ν )H * (ν )
R(ν ) =
( H (ν ) 2
(
+ α max H (ν )
2
))
where α is the Wiener parameter.

Figure 60 - Definitions of Signature Deconvolution Parameters

• Multiple removal
The multiple removal function is implemented as a predictive deconvolution filter. As has
already been explained in I.3.9, the multiple signal is estimated from the primary reflector
and then subtracted from the raw signal. In Delph Seismic Interpretation, only multiples
from the primary bottom reflector are filtered. This reflector should have been detected
previously using the bottom tracking function. Multiples are assumed to be shifted and to
be scaled versions of the direct return. In a first step, the algorithm searches for the time
of the first multiple in a window centered at twice the time of the direct. The operator can
adjust four parameters to adjust processing. See Figure 61. The Signature to Seabed
and Signature Length are the parameters used to extract the direct signal (or signature)
from the seismic trace. They have the same meaning as for the signature deconvolution
function. The search window length is the length of the correlation window while the filter
order is the order of the correlation.



Figure 61 - Multiple removal parameters

II.3.2.2 Spatial Processing

Two types of spatial processing can be applied to a seismic trace: horizontal stacking and
vertical shifting (see Figure 63). Horizontal stacking is simply a moving average for
successive emissions. This method provides a way to increase the signal-to-noise ratio
but it also decreases resolution.
Three vertical shift corrections can be used
• Heave Correction compensates the trace for measured swell
• Topo Correction shifts the trace according to a known sensor depth
• The Swell Filter filters the tracked seabed for any residual swell and the trace is
shifted accordingly

Figure 62 - Spatial processing parameters

Stacking The ping average is deduced from the Stack Depth parameter. The Stack Depth
parameter in meters is converted into a number N of pings to stack knowing the shooting
rate and average speed of the sensor as follows:
StackDepth
N stack =
Speed .ShootingRate
Swell Filter The swell filter function is a two-stage process:
• First a low-pass filtered bottom track is computed and then the trace signal is
shifted according to the difference between the filtered and raw bottom track.
• Following this, the profile data are aligned on a smooth bottom



The swell filter parameter is a period expressed in meters. It is the high-cutoff spatial
wavelength of the filter. This means that any swell period lower than the specified period
is attenuated. This period is converted into a number of pings N swell defined as follows:

SwellPeriod
N swell =
Speed .ShootingRate
Heave The sign convention for heave value varies from manufacturer to manufacturer. When the
Correction Invert Heave Data parameter is set to Yes the sign of the heave sensor value is changed
before being applied.

II.3.2.3 Detection Processing

Detection processing comprises a set of automatic detection and tracking functions for
bottom and reflector. There are two possible methods for either bottom or reflector
tracking (see Figure 63).

Figure 63 - Detection of Processing Methods and Parameters

In the first method, called the “Image Method”, the detection and tracking algorithm works
on a 2D image extracted around the latest tracking point (see Figure 64). In that image the
algorithm estimates the bottom/reflector by fitting a straight line through the strongest
echo. The best line is estimated by using an image processing technique known as a
Hough Transform. The size of the image can be adjusted by means of the two parameters
Vertical Detection Window and Horizontal Detection Window. For a steep reflector the
Vertical Detection Window value should be increased. The last parameter, the
Threshold Level, is used to segment the image before detection
In the second method, the algorithm estimates the bottom/reflector as a local maximum in
the signal amplitude (see Figure 65). This local maximum is searched inside a window
centered on the latest detected point whose length is defined by the parameter Vertical
Detection Window. The search window size should be increased for a steeper reflector.



Figure 64 – Definition of Image Method Parameters

Figure 65 – Definitions of Amplitude Method Parameters

II.3.2.4 Generation of Geosections and Surface Horizons

Seismic profile data and reflectors (or horizons) can be further processed to export them
to a 3D geographical environment.

Surface Reflectors that have been digitized on multiple reflectors can be converted to a 3D surface
horizons called a surface horizon (see Figure 66). The surface horizon is created as a geographical
generation
projected raster image in a GeoTiff format. The geodesy parameters should be specified
initially. The resolution parameter is the grid spacing or pixel size of the raster image. A
typical value is 1/3rd – 1/5th the interline distance spacing. If the automatic gap detection
option is enabled, interior contours on the surface will be detected automatically.

Figure 66 - Surface horizons processing parameters



Geosection A geosection is a seismic profile represented as a 3D geo-referenced vertical profile. In
the vertical direction, the scale is in milliseconds (see Figure 67). As in the case of the
surface horizon, the geodesy parameters for the data and chart should be specified at the
outset.
The horizontal track is approximated by a segmented line using a decimation algorithm.
The decimation strength is tuned using “navigation precision”. When setting a higher
value, the track is approximated by a longer segment. This parameter should be of the
same order as the horizontal resolution which is the horizontal distance between two
vertical columns in the geosection image. The last parameter is the vertical resolution in
milliseconds which should be of the same order as the sampling interval at which the
1
seismic trace has been digitized ( Δ = where f e is the sampling frequency).
fe

Figure 67 - Geosection Processing Parameters



Customer Support

Customer technical support for this product is available:
• by e-mail: support@ixsea.com
• by phone through IXSEA 24/7 hot-line:
+33 (0)1 30 08 98 98 for EMEA
+1 888 660 8836 (toll free) for US
+65 6747 7027 for Asia
Contact IXSEA support for any request on technical matters related to this product.
IXSEA Customer Support is committed to providing a rapid response to your query.



Contact

To obtain information on any IXSEA product, a general mailbox is available with the
following address: info@ixsea.com. You can also contact IXSEA headquarters in France,
or one of its representatives around the world:

Contact Phone Fax

IXSEA SAS +33 (0) 1 30 08 98 88 +33 (0) 1 30 08 88 01
FRANCE
IXSEA BV +31 (0) 23 750 5110 +31 (0) 23 750 51 11
THE NETHERLANDS
IXSEA GmbH +49 69 247 06953 +49 69 707 68615
GERMANY
IXSEA Ltd
Main Office + 44 (0) 2392 658252 + 44 (0) 2392 658253

Aberdeen Office + 44 (0) 1224 355 160

IXSEA Inc +1 (781) 937 8800 +1 (781) 937 8806
USA
Support:

+1 888 660 8836 (toll free)

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SINGAPORE
Support: +65 6747 7027

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CHINA
Support: +65 6747 7027

A detailed description of our products and a list of our representatives are available on our
website: www.ixsea.com


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