DELPH Seismic Advanced Notes

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Information about DELPH Seismic Advanced Notes
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Published on October 9, 2009

Author: IxseaDelph

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This documents presents DELPH Seismic workflow from sub-bottom/seismic data acquisiton to processing and interpretation

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 information storage and retrieval systems, for any purpose without prior written permission of IXSEA. Disclaimer IXSEA specifically disclaims all warranties, either express or implied, included but not limited to implied warranties of merchantability and fitness for a particular purpose with respect to this product and documentation. IXSEA reserves the right to revise or make changes or improvements to this product or documentation at any time without notify any person of such revision or improvements. In no event shall IXSEA be liable for any consequential or incidental damages, including but not limited to loss of business profits or any commercial damages, arising out of the use of this product. Trademarks Microsoft, MS-DOS and Windows are registered trademarks of Microsoft Corporation. Intel and Pentium are registered trademarks and Celeron is a trademark of Intel Corporation. MU-DSAN-AN-001-Ed A – July 2008 i

Delph Seismic – Advanced Notes 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

Delph Seismic – Advanced Notes 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

Delph Seismic – Advanced Notes 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

Delph Seismic – Advanced Notes 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

Delph Seismic – Advanced Notes 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 MU-DSAN-AN-001-Ed A – July 2008 2

Delph Seismic – Advanced Notes 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 MU-DSAN-AN-001-Ed A – July 2008 3

Delph Seismic – Advanced Notes 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 MU-DSAN-AN-001-Ed A – July 2008 4

Delph Seismic – Advanced Notes 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 MU-DSAN-AN-001-Ed A – July 2008 5

Delph Seismic – Advanced Notes 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 MU-DSAN-AN-001-Ed A – July 2008 6

Delph Seismic – Advanced Notes 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 MU-DSAN-AN-001-Ed A – July 2008 7

Delph Seismic – Advanced Notes 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 MU-DSAN-AN-001-Ed A – July 2008 8

Delph Seismic – Advanced Notes 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: MU-DSAN-AN-001-Ed A – July 2008 9

Delph Seismic – Advanced Notes • 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 MU-DSAN-AN-001-Ed A – July 2008 10

Delph Seismic – Advanced Notes 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 MU-DSAN-AN-001-Ed A – July 2008 11

Delph Seismic – Advanced Notes 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 MU-DSAN-AN-001-Ed A – July 2008 12

Delph Seismic – Advanced Notes 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. MU-DSAN-AN-001-Ed A – July 2008 13

Delph Seismic – Advanced Notes Figure 17 – Swell Effect Figure 18 - Swell on a Chirp Profile MU-DSAN-AN-001-Ed A – July 2008 14

Delph Seismic – Advanced Notes 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). MU-DSAN-AN-001-Ed A – July 2008 15

Delph Seismic – Advanced Notes Figure 20 – Swell Correction on Multiple Figure 21 – Example of Swell Effect on Multiple MU-DSAN-AN-001-Ed A – July 2008 16

Delph Seismic – Advanced Notes 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 MU-DSAN-AN-001-Ed A – July 2008 17

Delph Seismic – Advanced Notes 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) MU-DSAN-AN-001-Ed A – July 2008 18

Delph Seismic – Advanced Notes 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 MU-DSAN-AN-001-Ed A – July 2008 19

Delph Seismic – Advanced Notes 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 MU-DSAN-AN-001-Ed A – July 2008 20

Delph Seismic – Advanced Notes 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 MU-DSAN-AN-001-Ed A – July 2008 21

Delph Seismic – Advanced Notes 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 MU-DSAN-AN-001-Ed A – July 2008 22

Delph Seismic – Advanced Notes 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 MU-DSAN-AN-001-Ed A – July 2008 23

Delph Seismic – Advanced Notes 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 MU-DSAN-AN-001-Ed A – July 2008 24

Delph Seismic – Advanced Notes 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. MU-DSAN-AN-001-Ed A – July 2008 25

Delph Seismic – Advanced Notes 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. MU-DSAN-AN-001-Ed A – July 2008 26

Delph Seismic – Advanced Notes 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 MU-DSAN-AN-001-Ed A – July 2008 27

Delph Seismic – Advanced Notes 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 MU-DSAN-AN-001-Ed A – July 2008 28

Delph Seismic – Advanced Notes 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 MU-DSAN-AN-001-Ed A – July 2008 29

Delph Seismic – Advanced Notes Figure 41 – Software Architecture Figure 42 – Delph Seismic Acquisition MU-DSAN-AN-001-Ed A – July 2008 30

Delph Seismic – Advanced Notes 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. MU-DSAN-AN-001-Ed A – July 2008 31

Delph Seismic – Advanced Notes 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. MU-DSAN-AN-001-Ed A – July 2008 32

Delph Seismic – Advanced Notes 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

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