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SEISMIC ACQUISITION

version 1.0 released 29/1/99

INTRODUCTION

ZERO-OFFSET AND CMP METHODS

NORMAL MOVEOUTFORMING A CMP GATHER

TYPICAL ACQUISITION GEOMETRIES

GATHER TYPES AND DOMAINS

EFFECTS OF DIP AND STRUCTURE

SEISMIC ACQUISITION IN PRACTICE

OBSERVERS LOGS

NAVIGATION

RECORDING SYSTEMS

RECORDING POLARITY

SAMPLING AND ALIASING

TAPE FORMATS

ONBOARD PROCESSING

TYPICAL SHOT RECORDS

ADVANCED TOPICS

INTRODUCTION

In this section we introduce the concepts of seismic acquisition, starting with a simple ray-based concept and

ending with more practical details of the typical systems in use today. The contents of this chapter are

fundamental to seismic processing.

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ZERO-OFFSET AND CMP METHODS

The simplest type of acquisition would be to

use a single coincident source and receiver

pair and profile the earth along a line as shown

in the adjacent figure. Such an experiment

would be called azero-offsetexperimentbecause there is no offset distance between

source and receiver (both marked as a yellow

dot on the figure). The resulting seismic data

will besingle-foldbecause there will only be a

single trace per sub-surface position. The

zero-offset concept is an important one and

the method might be used in practise if noise

could be ignored. In order to overcome the

noise problem and additionally to estimate

earth velocity, the method of acquisition most

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commonly used is the Common-Mid-Point

(CMP)method. The same method is also

called Common-Depth-Point (CDP). Neither

of the two names exactly describes the

method, so while both are equally invalid, CMP is usually preferred.

The general idea of the method is to acquire a series of traces(gather) which reflect from the same common subsurface

mid-point. In the adjacent figure source points are shown in red

and receiver points in green. The traces are then summed

(stacked) so that superior signal-to-noise ratio to that of the

single-fold stack results. The fold of the stack is determined by

the number of traces in the CMP gather.

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The earlier figure showed rays and the previous figure shows traces resulting from a single six-fold CMP

gather depicting reflections from a single flat interface (these could be from any of the subsurface locations

from the zero-offset figure). The reflection from the flat interface produces a curved series of arrivals on the

seismic traces since it takes longer to travel to the far offsets than the near offsets. This hyperbolic curve

(shown in the dotted red line) is called the Normal Moveoutcurve or NMO and is related to travel time, offset

and velocity of the medium as shown by the equation in the figure. Before stacking the NMO curve must be

corrected such that the seismic event lines up on the gather. This is calledNormal Moveout Correctionand

the results are shown in the central portion of the figure. The moveout corrected traces are then stacked, to

produce the 6-fold stack trace, which simulates the zero-offset response but with increased signal-to-noise

ratio.

The CMP gather provides information about seismic velocity of propagation since this is the only unknown

variable in the NMO equation. If the velocity applied is too low, the NMO curve will be overcorrectedand if

the velocity is too high the curve will be undercorrected. Both under and overcorrection result in a smeared

stack which would be inferior to the perfect zero-offset trace.

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CMP ACQUISITION

While a CMP could be acquired using a single pair of source and

receiver pair this would be very expensive and time consuming way

to acquire several lines or a 3D cube of CMP gathers. In practise

CMP acquisition is accomplished by firing the source into many

receivers simultaneously as shown in adjacent figure (a) which

depicts ashot gatherwhere a single shot (red) is fired into sixreceivers (green). A receiver is also co-located with the shot to

produce a zero-offset trace. By moving the source position an

appropriate multiple of the receiver spacing CMP gathers can be

constructed by re-ordering the shot traces (this process is called

sorting). Figure (b) shows the original shot and second shot (traces in

red). In this case, the shot has moved up a distance equal to the

receiver spacing. The CMP spacing is equal to half the receiver

spacing. Figure 3c shows how the fold of the CMP gathers is starting

to build up after six shots have been fired. At the beginning of the

line the fold builds up to it's maximum of three. The fold stays at the

maximum until the end of the line is reached where the folddecreases.

Questions:

1. What happens to the CMP spacing if the receiver spacing is

doubled ?

2. What happens to the fold if the receiver spacing is doubled ?

3. What happens to the fold if the shot spacing is halved ?

4. What happens to the fold if the shot spacing is doubled ?

Typically the boat will travel around 4 knots (8 km/h) and the

shotpoint interval would be double the receiver group interval. A

speed of 4 knots is approximately 2m/s which means approximately

12s between shots for a 25m shotpoint interval. During this time the

compressors need to be able to recharge the airgun array before firing

again. If the boat travels too fast then the desired record length may not be acquired, too slow and control of

the streamer equipment control may be lost. A compromise is required depending on the geological target and

sea conditions.

As long as the shotpoint and receiver intervals are integer multiples of each other the CMP fold can becalculated by dividing half the cable length by the shotpoint interval. Non-integer increments can result in

some strange geometries such as variable CMP spacing and fold. The following table summarises typical

geometries. The fold calculation assumes a 3km cable and all units are in meters. Note that the table refers to

the fold and spacing as acquired in the field. These parameters can, and often are, changed during the seismic

processing flow. The maximum recording time is that practically established on modern vessels.

SHOTSPACING RECEIVER CMP FOLD MAXIMUM


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SPACING SPACING RECORDING

18.75 12.5 6.25 80 4.5s

25 12.5 6.25 60 8s

25 25 12.5 60 8s

50 25 12.5 30 20s

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GATHER TYPES

The adjacent figure shows

ray-paths for various types of

gather which can be constructed

by sorting traces from the CMP

acquisition technique. Data

sorting changes the domain of

the data for example from CMP

domain to common-offset

domain. Each trace will be

assigned a series of identifiers

during acquisition which will beused to sort the data. These

identifiers or trace headerswill

include things like shot number,

receiver number, trace number

within shot and source-receiver

offset. During processing the

data may be sorted many ways

using these headers - usually in

order to find a domain where

noise is separated from signal so

it can be suppressed. Whateverthe processing sequence, the sort

from shot to CMP gather must

always be applied before

stacking.

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EFFECT OF DIPPING HORIZONS

The previous figures and discussion have assumed that the reflecting strata are horizontal. Unfortunately the

introduction of dip introduces many complications as shown above. Figure (a) shows six-fold ray-paths for a

horizontal three reflector case and in (b) a case in which moderate dip is involved. The CMP method holds for

multiple layers and the data can be moved out and stacked to produce three reflections. Note that refraction

occurs at the velocity boundaries and velocity increases in each layer. Where dip is present it is clear that theCMP method is breaking down since the traces do not all reflect from the same mid-point location. Processing

techniques such as DMO and Migration are required to accurately process CMP data acquired from dipping

strata. For further discussion on velocity analysis for multi-layered or dipping data click here.

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MARINE ACQUISITION IN PRACTICE

Practical limitations limit the effectiveness with which we can acquire marine seismic data. For example themodern sleeve airgun source does not produce an exact impulse but is tuned to produce a broadband

spectrum in the typical seismic frequencies 5-100Hz.

The adjacent figure shows

details of a typical

acquisition system (either 2D

or 3D) in cross section mode.

A number of points are noted

with particular reference to


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seismic processing.

The antenna forms the major reference point for the rest of the equipment towed behind the vessel.

Navigation positions are measured from the antenna, however it is noted that the source to receiver

distance is what is required in processing.

1.

The source (shown in red) is towed at a fixed offset and depth from the back of the ship. Several arraysof airguns of different volumes are

tuned to obtain as impulse a source

as possible. The source signal is

affected by source ghost reflections

from the sea surface which

destructively interfere with the

signal at certain frequencies

depending on the source depth (see

adjacent figure). The calculation

assumes raypaths are vertical and

that the sea-surface reflection is -1.For a source depth of 7.5m

frequencies of 0, 100Hz and 200Hz would be completely cancelled.

2.

The receivers are mounted in a neutrally buoyant cable up to 9km long (3km in the diagram) which is

towed at a fixed depth and offset behind the vessel and behind the source. The hydrophones are towed

in groups (shown in blue) which are usually spaced 12.5m apart. The recorded signal is affected by

receiver ghost reflections from the sea surface which destructively interfere with the signal at certain

frequencies depending on the receiver depth (see previous discussion on source ghost).

3.

Particularly for 3D data a tailbuoy would be placed at the far end of the streamer to mark the end and

provide a navigational reference point.

4.

The following figure shows the acquisition system in plan view for a typical 3D vessel with two sources and

four streamers. In this mode eight subsurface CMP lines are acquired simultaneously. A 2D vessel would use

a single source and streamer towed behind each other to acquire a single subsurface line. It is noted that the

reality of acquisition is much more complicated than these diagrams indicate. The diagrams show details of

what is required for seismic processing.


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OBSERVERS LOGS

The recording and acquisition details for each line within a survey are described in the observers reports or

logs.These usually paper (but increasingly digital) reports are critical to the processing of seismic data.

Unfortunately they are often lost and are sometimes misleading and incorrect. However they are records

made in the field and may be the only place where deviations from the acquisition specifications, such asmissed shots, bad traces, noise files, changes in near-trace offset, level of interference etc are recorded. It is

difficult (but not impossible) to process seismic data from field tapes without the observers logs.

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NAVIGATION

A modern seismic acquisition system uses several navigation systems firstly to determine and control the

position of the vessel in the water and secondly to determine the position of the seismic equipment trailing thevessel. Modern systems almost exclusively rely on GPS (global positioning system) for the majority of

positioning. Small receivers mounted on the vessel, tailbuoys and gun-floats can detect signals almost

anywhere in the world from 3 or more satellites and determine position within 10m via triangulation. Acoustic

systems or pingers are also used in 3D vessels on the source system. Some 3D vessels additionally use laser

positioning on the source and tailbuoys. A vast amount of navigation data can be collected onboard a modern

multi-streamer seismic vessel. The navigation data requires onboard processing and checking to ensure that all

the measurements agree within error. This navigation data should be provided along with the seismic data for

data processing purposes where the seismic and navigation information are merged. This is especially

important for 3D processing. Following navigation merge the seismic trace headers contain the (x,y) positions


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of the source and receiver for that trace.

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POLARITY

As compresses air is expelled from the gun chamber it expands in the water to form a bubble (rarefraction)which then collapses (compression). An initial impulse is followed by the oscillitory bubble pulse. The Society

of Exploration Geophysicists (SEG) ambiguously defines polarity for seismic data recording, that a

rarefaction is a positive number and a compression a negative number on tape. An increase in acoustic

impedance or positive reflection coefficient is also represented by a trough i.e. a negative number on tape.

Once the data is recorded it can be displayed at any polarity. Data is usually recorded at SEG standard

polarity.

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RECORDING

In the marine case the seismic reflections are recorded by hydrophones(which detect pressure or acceleration

changes) and in the land or ocean-bottom seismic case bygeophones(which detect motion or velocity

changes). There is a 90 degree phase change between the two systems. The signal is usually recorded by

analogue instruments and must be digitised to be stored on computer tape. The process of digitising involves

forming a time series of the analogue signal by sampling it at a regular interval. A typical trace or record

length for exploration seismology would be 6 seconds although for deep crustal work 15 to 20 seconds is

common. Water-bottom acquisition systems often combine geophone and hydrophone measurements.

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SAMPLING AND ALIASING

The use of digital computer technology means that the analogue signal must be sampled at regular intervals in

time in order to be processed. On older systems this sampling was carried out at the recording system. On

modern digital systems the sampling is carried out within the streamer itself. Any signal would be perfectly

represented in the computer if an infinite number of samples were taken.

The adjacent figure shows a signal

sampled at two different intervals.

The top slide shows that a goodrepresentation of the 20Hz signal

can be made by samples taken

every 25ms (marked by the blue

stars). In the bottom slide samples

are taken every 75ms. An

insufficient number of samples are

taken and the higher frequency

information is "lost" or aliased.

The original 20Hz red curve


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appears as a 6.7Hz blue dotted

curve.

The highest frequencyfwhich

can be sampled by inteval dis

1/2d - this is called theNyquist

Frequency. Higher frequencies

than this are said to be temporally

aliasedbecause they will appearas if they are lower frequencies. Typical sampling intervals are 1, 2, 4, 8 milliseconds with aliasing occurring

above 500,250,125,62.5 Hz respectively. If data are sampled at an interval of 4ms then a frequency of 150Hz

would appear as if it were 100Hz i.e. it would corrupt the true 100Hz signal. Before the data are sampled the

higher frequencies which would be aliased by the chosen sampling interval must be removed by an analogue

filter in the recording system.

Sampling is equally as important in space as it is in time and is discussed in more detail here.

If either temporally or spatially aliaseddata are admitted into further processing stages then artifacts and

noise may well be introduced which could potentially be misleading. An understanding of sampling

(particularly spatial sampling) is an important part of survey design and can affect survey costs and quality. Itis obviously important to sample signal correctly, but it is equally vital to adequately sample noise if this is to

be removed by processing routines.

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TAPE FORMATS

Several tape formats defined by the SEG are currently in use. These standards are often treated quite liberally,

especially where 3D data is concerned. Most contractors also process data using their own internal formatswhich are generally more efficient than the SEG standards.

The two commonest formats are SEG-D (for field data) and SEG-Y for final or intermediate products. Theprevious figure shows the typical way in which a seismic trace is stored on tape for SEG-Y format. The use of

headers is particularly important since these headers are used in seismic processing to manipulate the seismic

data. Older multiplexed formats (data acquired in channel order) such as SEG-B would typically be

demultiplexed (in shot order) and transcribed to SEG-Y before processing. In SEG-Y format a 3200 byte

EBCDIC (Extended Binary Coded Decimal Interchange Code) "text" header arranged as forty 80 character

images is followed by a 400 byte binary header which contains general information about the data such as

number of samples per trace. This is followed by the 240 byte trace header (which contains important

information related to the trace such as shotpoint number, trace number) and the trace data itself stored as

IBM floating point numbers in 32 byte format. The trace, or a series of traces such as a shot gather, will be


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terminated by an EOF (End of File) marker. The tape is terminated by an EOM (End of Media) marker.

Several lines may be concatenated on tape separated by two EOF markers (double end of file). Separate lines

should have their own EBCIDC headers, although this may be stripped out (particularly for 3D archives) for

efficiency. Each trace must have it's own 240 byte trace header. Note there are considerable variations in the

details of the SEG-Y format. The AHC Houston documentationprovides more details.

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ONBOARD PROCESSING

Modern acquisition vessels can quality control and process 2D and 3D seismic data onboard depending on the

size of computer system and number of operators installed. A PROMAX system (or equivalent) and operator

are usually provided to QC the seismic data as it is acquired. Quality control would typically included shot

displays, FK analysis and brute stack displays. Full onboard processing is possible if required and provides the

ultimate QC tool - at a cost. Onboard processing is the fastest way to process data and works well in some

areas but should generally be avoided as a mechanism for providing a final data since there is too much to go

wrong.

The secret of successful onboard processing is to do your homework in advance and to know the processing

sequence ahead of time. Usually the contractor is given examples of existing velocity fields, sections and dataat least a month in advance of the survey. The contractor will then start to form a sequence on their system

and start to resource the hardware required - ideally involving the people onboard who will be doing the

work. Source signatures and other obvious things are often a sticking point at the last minute. The velocity

fields are critical if moveout based demultiple is to be attempted onboard.

Pre-processing onboard (e.g. designature, temporal/spatial trace reduction, navigation merge, trace edit/QC)

and regular helicopter drops can often achieve a similar turnaround, can cost less and produce better quality

than full onboard processing. Sometimes for speed the onboard pre-processed data is taken through a

fast-track sequence e.g. radon demultiple, 3D DMO stack and the data migrated onshore and loaded to a

workstation. This would typically take 4 weeks from the end of survey. In practise the interpreter prefers to

wait for the final volume since otherwise the interpretation is done twice. If the 3D is just being shot toconfirm a well location which is already pretty firm then onboard processing may be a viable route. Note the

data may have to be re-processed.

The contractor should ensure that someone senior onboard is responsible for the processing. It is important for

the oil company representatives (including interpreter) to attend the mobilisation meeting (maybe even ride

the boat for a few weeks) to make sure the targets are defined and that everyone knows who everyone is. As

ever with contractors you are in the hands of the people doing the job. Western Geophysical have a system

where the data is processed onboard remotely by a team based onshore. This hybrid method may be quite

attractive to some.

Most vessels can now ship off example sections or screendumps by email for decision making back at base(either contractor/oil company or both) and staff should be encouraged to do this if there is time. The ideal

processing situation is to shoot the first line and then go down for weather/technical downtime for a week !!

Velocity files can also be easily compressed and shipped if these are being picked onboard. For this reason it

may not be required to put a full-time QC onboard. The onboard seismic rep should in any case be pretty

knowledgeable about processing.

The contractors will often try and cut corners. For instance GECO used to process everything at 16 bit

onboard and stored intermediate data in their format on exabyte cartridge. The contract should specify that a

SEGY prestack archive (e.g. after RADON demultiple) should be produced onboard on 3590 cartridges. This

gives a good starting point when the re-processing inevitably has to take place. Contractors will also try and


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cheat on the number of parabolas used for RADON demultiple, often limiting to the fold or less. The fold +

20% (or some other number) should be specified in the contract.

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IDENTIFYING REFLECTIONS AND NOISE TYPES

The shot records in the previous figures are used to identify principal reflections of interest, including various

sources of noise. Click hereto obtain an enlarged display of a raw shot record and hereto display the shot

after t2gain correction with events identified. When data is recorded raw noise files are usually acquired at

the beginning and end of line. A noise file is created by recording a shot but not firing the source. The noise

file in the previous figures clearly shows noise generated by tug at the front end and far (from tailbuoy) end of

the streamer. This low frequency noise would typically be removed by a combination of bandpass filtering

and DMO. Noise files should be removed (by editing) before processing. Field data are also acquired with

several auxiliary traces which would be removed (by editing) prior to processing. The near channel is usually

numbered 240 but in this instance is numbered 1. In the figure the direct arrival does not arrive at time zero

because there is a recording delay built into the system which should be removed before processing begins.

Observers logsshould detail channel numbers, noise files, auxiliary traces and start of data delays. The second

figure identifies several events on the gain corrected shot. Yilmazcontains forty shot records from around the

world and indicates data and noise types.

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ADVANCED TOPICS

LAND ACQUISITION

SUBSEA or SEABOTTOM ACQUISITION

PLANNING A 2D SURVEY

PLANNING A 3D SURVEY

ARRAY DESIGN

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