reservoir geophysics
DESCRIPTION
TRANSCRIPT
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Reservoir Geophysics and
Geology
Arthur Godfrey, Dr. BATTE
1
2
• The technical journals, especially The Leading Edge, are the best sources of material.
• Kearey, P., Brooks, M., and Hill, I., 2002, An introduction to geophysical exploration. 3rd
edition, Blackwell Publishing, 262p.
• Gluyas, J., and Swarbrick, R, 2004, Petroleum geoscience, Blackwell, 359p.
• Sheriff, R E, and Geldart, L P, 1995, Exploration seismology, 2nd edition, Cambridge
University Press.
• Brown, A R, 1996, Interpretation of three-dimensional seismic data.
• American Association of Petroleum Geologists, Memoir 42, 4th edn.
• Sheriff, R E, (ed), 1992, Reservoir geophysics, Society of Exploration Geophysicists,
Tulsa.
References
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LECTURE 1
Introduction to Geophysics
What Is Problem Number One?
In case you had not noticed, the basic problem is
that most rocks are opaque!
As a result, we have several alternatives to finding
out what is lurking below the surface.
We can use guesswork.
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We do that with most domestic applications, such
as house foundations or installing a swimming pool.
We can dig or drill a hole.
BUT HOW DO WE KNOW WE ARE DIGGING OR
DRILLING IN THE RIGHT PLACE?
We can get the Big Picture first with
GEOPHYSICS.
5
What Is Geophysics?
Geophysics uses the methods of classical physics to obtain a
“geophysical image” of the subsurface.
For every standard physical property, there is a corresponding
geophysical technique.
For example:
• Density ↔ Gravity method
• Magnetic susceptibility ↔ Magnetic method
• Electrical conductivity ↔ Resistivity or EM methods
• Velocity & density ↔ Seismic method
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The geophysical image of the subsurface is
not always the same as the optical or
geological image.
Recall however that a standard suite of
geophysical logs generates an “image”
different to core photographs.
7
Natural and Induced Fields
Gravity and Magnetic methods measure the spatial
variations in the naturally occurring fields.
Radiometric methods can also be included within
this group.
These fields can vary slightly with time, but field
and processing techniques usually seek to remove
this aspect.
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The major advantage of using natural fields is
that there is no cost associated with
establishing or maintaining them.
There are also relatively few disturbances
which prevent their measurement.
9
Gravity and Magnetic methods have
traditionally been used to provide regional
perspectives of the geology by taking
measurements at relatively large station
separations.
However, station spacing has been
considerably reduced in recent times,
resulting in dramatic improvements in the
resolution of geological features. 10
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The figure shows a gravity
survey for detecting salt
structures. Survey results are
contoured on a map so that
patterns of gravity variation
indicative of these features
can be recognized.
In the above example, a pattern showing a small decrease in gravitational
attraction suggests the presence of a low-density salt dome.
Gravity surveys for salt domes
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A Magnetic Image of Geology
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Seismic and Electrical methods on the other
hand inject energy into the ground and
measure parameters related to the source
and energy propagation through the earth.
Induced fields normally produce a more
detailed image of the subsurface. However,
this is usually achieved at substantially
greater cost. 13
RESERVOIR ROCK
Source Receiver
Seismic Structure
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Application of Potential Field Methods
Potential field methods, namely Magnetics, Radiometrics,
and Gravity are used extensively in the mapping of fold
belts for mineral exploration.
Costs are very low, such as $10/km for Airborne
Magnetics and Radiometrics, and about $100/km for
Airborne Gravity.
Potential field methods essentially map lateral changes
in rock properties. 15
16
Note
Although depth-related, information can
usually be recovered, with its accuracy
considerably less than that achieved with
boreholes or Seismic methods, which
map vertical variations.
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In petroleum exploration, potential field
methods can be extremely valuable in
determining the regional geological and
structural setting.
Furthermore, potential field methods can
readily detect transform faulting, where
the movement is predominantly in the
horizontal direction. 17
18
Figure shows marine seismic recording. Ship-borne
recording instruments gathering seismic data. The
process is much faster than its land-bound
equivalent, but accurate navigation is vital.
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Frequently, there can be a close
correlation between faulting detected in
the sediments with seismic reflection
methods, with that in the basement
detected with magnetic surveys.
One often drives the other.
Magnetic data are also used to detect
igneous intrusions in sedimentary basins.
Benefits of Geophysical Methods
•Rapid coverage which is usually not restricted by
access.
• Uniformity of sampling.
• Substantial depths of investigation below the
surface.
• Data acquisition parameters can be varied to suit
the target parameters. 20
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• Geophysics can have a minimal
environmental impact.
• Geophysics provides quantitative, bulk, in-
situ measurements.
• Insensitive to vegetation.
• Can be recycled many times.
21
Implications of 3D Seismic Reflection Methods
The biggest cost in petroleum exploration is the dry hole.
Offshore, a borehole can cost ~$25M+.
A typical 3D seismic survey can cost ~$1M.
One large US based petroleum E&P company estimated
that in the 1990s, their cost of finding oil fell from
~$US9/barrel to ~$US1/barrel, due largely to the
reduction in dry holes with 3D seismic reflection methods.
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Basic Seismic Methods
• Seismic exploration using explosives
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• Geophysics marine acquisition seismic geology
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•Airguns and Marine acquisition
What Are the Major Benefits of 3D versus 2D?
The first major benefit is GEOPHYSICAL.
Essentially, the seismic signal is reflected from a large region
around the seismic traverse, known as the Fresnel zone, as
well as from below the traverse.
26
We can think of the Fresnel zone as a disc with the reflection point at its center.
Energy being reflected from inside the disk “adds up” to provide the recorded event
on the seismic trace
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Fresnel Zone Cont….
Reflections are radiated from a large disc, known as the
Fresnel zone, rather than from a point in the subsurface.
RECALL that we hear acoustic echoes from the sides of
large buildings, rather than from trees or narrow posts.
Migration or imaging collapses the disc
to either a dot with 3D data or to an
ellipse with 2D data, and re-positions
the reflections into their correct position
in a 3D (or 2D) sense.
Post-Migration Fresnel zone
Pre-Migration Fresnel zone
27
Other important benefits are GEOLOGICAL.
Geology is 3D! That is, there can be very many
significant changes in the geology between the
wide line spacing of 2D surveys.
Many comparisons demonstrate that 2D results
can produce an incorrect, rather than an
incomplete picture of the subsurface.
Read that sentence once more! 28
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What Is Problem Number Two?
The second important problem is that the
vertical resolution of seismic reflection images
is not as good as we would expect.
It is generally accepted that the limit of
resolution must be a quarter of a wavelength.
𝑊𝑎𝑣𝑒𝑙𝑒𝑛𝑔𝑡 = 𝑆𝑒𝑖𝑠𝑚𝑖𝑐 𝑤𝑎𝑣𝑒 𝑣𝑒𝑙𝑜𝑐𝑖𝑡𝑦
𝑓𝑟𝑒𝑞𝑢𝑒𝑛𝑐𝑦
29
For seismic velocities 2000 m/s to 4000 m/s
and seismic frequencies 10Hz to 80Hz, the
wavelengths range from ~20 m to 400 m.
These wavelengths are barely able to resolve
many reservoirs.
Other geophysical methods have either less
resolution or less penetration to the depths of
most reservoirs. 30
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The Seismic Objectives
• Make the image CLEAR, that is, improve signal-to-
noise ratios through stacking, filtering, etc.
• Improve the VERTICAL resolution through source
effort, deconvolution, etc.
• Improve the LATERAL resolution through smaller
station intervals, migration, etc.
• RESOLUTION is the only game in town!
31
Summary
• Geophysical methods provide a cost effective
method for imaging the subsurface.
• Better geophysical images → Better geological
models → More successful exploration &
production.
• 3D and 4D seismic reflection methods, developed
in the last few decades, have had a spectacular
impact on petroleum E & P. 32
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• Most geophysical methods have problems
with resolution and/or penetration i.e., with
signal-to-noise ratios.
There are ongoing comparisons with
boreholes.
• With seismic data acquisition, we must
increase bandwidth for maximum resolution,
and minimize noise. 33
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LECTURE 2
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Reservoir Management
The decision to develop a new field offshore, or a
deep play onshore, or a field in a remote location
requires accurate appraisals of oil and gas in
place, potential production rates, and ultimate
recovery.
If developed, economic pressures further require
that these high-cost fields be brought on stream
quicker and that RECOVERY BE INCREASED. 35
Reservoir management is maximizing the
economic value of a reservoir by optimizing
recovery of hydrocarbons while minimizing
capital investments (drilling, seismic surveys,
etc) and operating expenses (staff costs, taxes,
etc).
Reservoir management is an economic process of
raising the worth of a oil reservoir to its highest
possible value. 36
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Economic value generally increases when
more reserves are proved or when the
reservoir's producing rate increases.
Capital investments and operating expenses
must be incurred to find and develop
reserves.
These expenditures offset value.
37
Development Strategies Development strategies must meet five basic objectives:
1. Reduce the cost of field development, which often translates into
minimizing the number of wells.
2. Optimize total reserves.
3. Optimize production recovery.
4. Reduce operating costs of the developed field.
5. Enhance recovery if economically justified.
Expenditures which drain present worth of a field must be
balanced against the chance of increasing present worth by
adding reserves and/or increasing production.
38
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Maximizing the Net Present Value (NPV)
In essence, the aim of reservoir engineering is to
maximize the NPV.
In simple terms, 𝑁𝑃𝑉 = (𝑅𝑒𝑣𝑒𝑛𝑢𝑒−𝐶𝑜𝑠𝑡𝑠)
𝑇𝑖𝑚𝑒.
Geophysics can have an impact on the NPV, by
helping define a reservoir so that production can
be optimized, costs contained, all within a
minimum of time. 39
The Technical Challenges
Reservoir management must face the technical
challenges of:
1. The early and accurate characterization of the
reservoir in terms of volumetrics, fluid properties,
lithology, and continuity.
2. Improve reservoir surveillance techniques (to monitor
pressure changes and fluid movements) so that fields
under production may be accurately monitored and
efficiently managed. 40
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Conventional engineering data, such as; core analyses,
well logs, and production history for reservoir
characterization or surveillance CANNOT provide the
complete information required to meet these challenges.
The aim of this course for this reason is to illustrate that:
“a key to improved characterization and surveillance
is the use of high resolution geophysical
measurements integrated with conventional data
within a geological model of the reservoir”.
41
Geophysical methods can, therefore,
provide quantitative information to
enhance or constrain reservoir simulation
models.
42
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LECTURE 3
Propagation of Seismic Energy
Seismic energy propagates in wavefronts.
You can see wavefronts when you throw a
stone into a river.
Can you visualize a wavefront in 3D in the
ground?
For a constant seismic velocity, a
hemispherical wavefront will propagate away
from the shot. 44
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A wavefront is defined as the surface or the
boundary between the region where the seismic
energy is or has been, and the region where the
seismic energy has yet to reach.
45
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The wavefront represents a surface of
equal travel time from the seismic
source.
The passage of a wavefront is marked by
a rapid increase in amplitude and its
velocity is measured in the direction of
the normal to the wavefront.
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Raypaths-1
We can define raypaths as the path of a very
small interval of the wavefront.
Raypaths can be viewed as the seismic
equivalent of a laser beam.
While seismic raypaths DO NOT really exist,
nevertheless, they can be extremely useful
for visualizing many seismic phenomena. 47
Raypaths are generally equated with the
wavefront normal, but this is only the
case in isotropic rocks.
Anisotropy, which is the variation in
seismic velocities with angle, is common
in the earth.
48
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Raypaths-2
The raypath is the trajectory of a particular
package of energy. It contains the information
on the subsurface structure. 49
Seismic Waves
Seismic waves can be categorized into;
(i) body waves, which propagate throughout the
subsurface, and
(ii) surface waves, which usually propagate in the
weathered layer.
Body waves can be further categorized into P-waves,
and S-waves. Currently, the vast majority of seismic
surveys use only the P-wave energy. 50
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Relatively easy to generate.
The seismic velocity of P-waves is a function of
both the rock matrix and the fluids within.
VP is the compressional wave velocity, K is the bulk
modulus, μ is the shear modulus and ρ is the
density.
P-Waves
51
P-Wave Particle Motion
The particle motion with
P-waves is essentially
parallel to the direction of
propagation.
With anisotropy, the principal axes of particle
motion do not necessarily coincide with principal
axes of propagation. Therefore, the P-wave often
has a small amount of S-wave motion. 52
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S-Waves
Shear waves can be generated with either special S-
wave sources, or as a by product of P-wave sources.
Frequently, 60+% of the output of P-wave vibrators can
produce S-waves.
Since fluids cannot support shearing, the S-wave velocity
is only affected by the rock matrix and not the presence
of any fluids.
𝑉𝑠 = 𝜇
𝑝
53
S-Wave Particle Motion
The particle motion with S-waves is essentially
orthogonal to the direction of propagation. Can you
describe an S-wave-like activity at many sporting
events?
S-wave particle motion can have both horizontal
and vertical components, which are known as SH
and SV waves. 54
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Since the axis of symmetry
with most earth’s anisotropy is
generally vertical, the SH and
SV components can have
quite different seismic
velocities.
Traditionally, the SH wave has been preferred,
because it is reputedly less prone to mode
conversion. 55
P-Waves vs S-Waves
The measurement of both P- and S-wave
velocities provides a means of separating the
effects of the rock matrix (e.g. porosity) from the
fluids.
P-wave results can however be essentially
useless where there are “gas chimneys”, because
of the severe attenuation of the P-wave energy.
In such cases, S-wave surveys are used, because
S-waves are not affected. 56
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57
A gas chimney is a subsurface leakage of gas
from a poorly sealed hydrocarbon accumulation,
clearly visible in the center of the lower seismic
section P-P but not as apparent in the upper
seismic section P-S. Section P-P displays
conventional P-wave data.
Section P-S, however, includes S-wave energy,
which improves seismic imaging in areas where
the acoustic impedance contrast is small, such as
in a gas chimney, because the presence of gas
has little effect on S-wave propagation.
58
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Applications P-Waves and S-Waves
59
Reducing of strong P-wave multiples.
Fracture density and orientation.
Detection of gas seepages.
Direct hydrocarbon and lithology indication.
Investigations into quantitative saturation
and pressure changes.
Identifying drilling hazards.
Improved illumination.
60
Reducing of strong P-wave Multiples
The combination of the signals recorded by
the hydrophone and the Z-component
geophone (4C) can help to reduce water-
borne multiple contamination.
Multiples are internal reflections in a layer,
which occur when exceptionally large
reflection coefficients are present.
WILL DISCUSS THIS MORE LATER IN THE COURSE
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61
Multiples Multiples are seismic energy that reverberates within
a layer. The most important in marine seismic is the
water multiple.
This multiple is strong since the reflection coefficient
on the seafloor is generally large (R = 0.3) and the
reflection from the surface is close to total (R = -1)
Multiples can occur within layers.
The figure above shows an example
of a peg-leg multiple
62
Detection of Fracture Density and
Orientation
As a result of S-wave anisotropy, S-waves usually split
into two waves, a fast and a slow mode, these split S-
waves are very sensitive to fractures and can provide
information about fracture density (fracture porosity) and
orientation (directions of preferred permeability).
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Detection of Gas Seepages
P-wave reflections may be disturbed by gas trapped
in the subsurface.
S-waves can be used to help clarify the subsurface
image because they are unaffected by pore
fluids, an important attribute that can improve
seismic imaging and highlight information valuable
for reservoir characterization, reservoir monitoring,
and well planning. 63
Direct Hydrocarbon and Lithology
indication
S-waves can provide valuable insights into
the nature of subsurface lithologies and pore
saturating fluids, highlighting reservoirs not
previously visible using only P-waves.
64
WILL DISCUSS THIS MORE LATER IN THE COURSE
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65
Investigations into Saturation and
Pressure changes
S-waves can help monitor Time-lapse
variations.
During production or injection,
reservoir fluid saturation and pressure
can change dramatically. WILL DISCUSS THIS MORE LATER IN THE COURSE
66
Time-lapse or 4D seismic has opened
new horizons for monitoring reservoir
properties such as fluids, temperature,
saturation and pressure changes during
the productive life of a field.
It is based on the analysis of repeated 3D
seismic data.
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67
Detection of areas with significant changes or
with virtually unchanged hydrocarbon-
indicating attributes helps to determine new
drilling sites in an already existing production
field.
For this method, it is critical that the observed
seismic changes can be related to the fluid
flow.
Identifying Drilling Hazards
4D seismic can also be applied in
prediction of pore-pressure which can
highlight the presence of shallow gas.
68
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69
Improved illumination
Subsurface image is often improved through wide
azimuth illumination, multicomponent technology
offers a cost effective means of acquiring such
data in an offshore environment.
Swath design Patch design
70
In swath designs, the source lines are
parallel to receiver lines, while in patch
designs, source lines are perpendicular
to receiver lines.
WILL DISCUSS THIS MORE LATER IN THE COURSE
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Surface and Guided Waves
As the names imply, these waves are generated
either at a free surface, generally within the
weathered layer, where they are known as ground
roll (Rayleigh waves).
These waves can be viewed as being generated
by multiple reflections within a layer bounded
by other layers with strong contrasts in seismic
properties.
71
They are characterized by low frequencies,
low velocities, dispersive (the velocity
changes with the frequency) and frequently
very high amplitudes.
72
Accordingly, these waves are
usually treated as noise, and
where possible, efforts are
made to minimize the
recording of these signals in
routine data acquisition.
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Surface Waves
73
Rayleigh waves shake the ground both in the direction of propagation and
perpendicular (in a vertical plane) so that the motion is generally elliptical –
either prograde or retrograde.
Love waves shake the ground perpendicular to the direction of propagation
and generally parallel to the Earth’s surface.
Rayleigh waves Love waves
Ways of attenuating Surface Waves
1) The most effective method is to place the
source BELOW the base of the weathering.
This is not practical with surface seismic
sources, such as Vibroseis.
2) Alternatively it may be possible sometimes
to limit the amount of signal frequency
generated by the vibrator. 74
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3) Extended geophone arrays (Δx > 100m)
for each trace. This is the traditional
approach, but it usually results in a significant
loss in resolution.
4) Processing techniques, such as velocity
and frequency filtering.
5) STACKING! High fold stacking essentially
generates geophone arrays as long as the
spread! 75
First Arrival Refraction Signals
The near-surface weathered layers are important
because they generally exhibit major changes in
seismic or acoustic properties (reductions in
seismic velocities and densities).
With a reduction in seismic velocities, any
variations in the thicknesses of the weathered
layer results in significant increases in the travel
times through that layer.
76
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As a result, the seismic reflections are de-
focused, in much the same way that frosted
glass de-focuses the image through a window.
The first arrival refraction data provides one
source of information for defining and in turn,
for correcting for the effects of the weathered
layer.
These corrections are known as “statics”
corrections. 77
78
Static corrections – a bulk time shift applied to a
seismic trace, are typically used in seismic processing to
compensate for these differences in elevations of
sources and receivers and near-surface velocity
variations.
WILL DISCUSS THIS MORE LATER IN THE COURSE
Seismograms showing differences between events on adjacent seismograms due to the different elevations of shots and detectors and the presence of the weathered layer. The same seismograms after the application of elevation and weathering correction showing good alignment of the reflection events.
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79
Statics remove the irregularities in travel-times
caused by the variations in topography and
weathering, so that standard processing methods,
such as NMO, can be applied automatically.
Statics represent a major, if not THE
major single, limitation on the resolution
of land seismic reflection methods.
While P-wave statics are often a major
challenge, S wave statics are an even
greater challenge.
80
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Seismic Waves – Summary
• Seismic waves propagate in wavefronts.
• Raypaths are an alternative approach for
visualizing the propagation of seismic energy.
• Useful seismic energy include P and S
waves.
81
• S waves can generate additional useful images
of the earth.
• Surface waves are generally considered to be a
source of “noise” and various strategies are
employed to attenuate them.
• The near-surface weathered layers are a cause
of loss of resolution with seismic reflection data.
• Statics, the corrections for the near-surface
layers, are frequently computed from the first
arrival refraction data. 82
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83
LECTURE 4
Effects at Interfaces
1 – Snell’s law
2 – Zoeppritz equations
3 – Mode conversion (P↔S)
84
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Wavefronts at Interfaces
When a seismic wavefront encounters an
interface between rocks with different seismic
properties, three effects can occur.
1 – There can be a change in direction of the
wavefront. This effect is described with
Snell’s law.
85
2 – Part of the energy is reflected and most of the
energy is transmitted, or passes right through.
3 – Mode conversion between P and S also
occurs.
86
The relative proportions of the
reflected and transmitted
components are given by the
Zoeppritz equations (also known
as the Knott’s equations).
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Snell’s Law – 1
When a seismic wavefront encounters an interface
between rocks with different seismic velocities at
an angle, there can be a change in direction of the
wavefront.
Why? Because different parts of the wavefront are
traveling at different velocities.
In general, Snell’s law only applies where there are
plane interfaces. 87
Snell’s Law – 2
88
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Use velocities of 2000 m/s and 5000 m/s.
incident angle I, refracted angle r
• 0
• 10
• 15
• 20
• 23.578
• 25
• 30
Snell’s Law Calculations
89
Snell’s Law – 3
Snell’s law does not apply to diffractions
which occur with irregular interfaces. 90
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The Zoeppritz Equations
The Zoeppritz equations are quite
complicated, mainly because of the
need to accommodate the mode
conversion effects.
91
As a result, the most commonly
used form is the normal
incidence approximation.
92
The normal incidence approximations
are quite reasonable up to the critical
angle.
Beyond the critical angle, mode
conversion between P and SV
becomes more significant.
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Normal Incidence Zoeppritz Equations
V is velocity and ρ is density. Layer 1 is above layer 2.
93
The Zoeppritz Equations cont….
The normal incidence approximation
is reasonable, up to the critical angle.
Mode conversion from P to S waves
becomes more extensive beyond the
critical angle.
94
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Exercise – Reflection Coefficients
Sketch an anticlinal sand reservoir with a shale seal.
Shale: 8500 ft/s 2.5 tonnes/m3
Gas Sand: 6400 ft/s 2.16 tonnes/m3
Oil Sand: 10800 ft/s 2.29 tonnes/m3
Water Sand: 12100 ft/s 2.33 tonnes/m3
95
Compute reflection coefficients for:
Shale/gas
Gas/oil
Oil/water
Water/shale
Shale/oil
Shale/water 96
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Mode Conversion
There is more mode conversion beyond the critical
angle.
Mode conversion does not occur with SH waves in
isotropic media.
Mode conversion is used to generate S wave data
with P wave sources, such as with air-guns in the
marine environment.
97
Mode conversion is readily accommodated
with Snell’s law, where the appropriate P and
S wave velocities are used.
Mode conversion is readily accommodated
with the Zoeppritz equations.
98
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Mode Conversion – Raypaths
Mode conversion occurs at most interfaces.
99
Incident P
Reflected S
Reflected P
Refracted P
Refracted S
V1
V2 > V1
θ
Mode Conversion – Marine Sources
Mode conversion is employed in marine
operations to generate S waves with P wave
sources. 100
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Snell’s Law and Mode Conversion
Where the incident signal is a P wave and the
reflected signal is an S wave, then the angle of
reflection will not be the same as the angle of
incidence.
101
𝑆𝑖𝑛(𝑖𝑛𝑐𝑖𝑑𝑒𝑛𝑡 𝑃 𝑤𝑎𝑣𝑒 𝑎𝑛𝑔𝑙𝑒)
𝑉𝑖𝑛𝑐𝑖𝑑𝑒𝑛𝑡 𝑃 𝑤𝑎𝑣𝑒= 𝑆𝑖𝑛(𝑟𝑒𝑓𝑙𝑒𝑐𝑡𝑒𝑑 𝑜𝑟 𝑡𝑟𝑎𝑛𝑠𝑚𝑖𝑡𝑡𝑒𝑑 𝑃 𝑜𝑟 𝑆 𝑤𝑎𝑣𝑒 𝑎𝑛𝑔𝑙𝑒)
𝑉𝑟𝑒𝑓𝑙𝑒𝑐𝑡𝑒𝑑 𝑜𝑟 𝑡𝑟𝑎𝑛𝑠𝑚𝑖𝑡𝑡𝑒𝑑 𝑃 𝑜𝑟 𝑆 𝑤𝑎𝑣𝑒
Wavefronts at Interfaces – A Summary
When a seismic wavefront encounters an interface between
rocks with different seismic properties:
1 – There can be a change in direction of the wavefront. This
effect is described with Snell’s law.
2 – Part of the energy is reflected, and most of the energy is
transmitted, or passes right through. The relative proportions of
the reflected and transmitted components are given by the
Zoeppritz equations.
3 – Mode conversion between P and SV also occurs.
102
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103
LECTURE 5
Seismic Sources
1 – Dynamite.
2 – Vibroseis.
3 – Air-guns.
104
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Drill Rigs for Dynamite Sources
Dynamite sources are often employed where
Vibroseis vehicles cannot obtain access. In such
cases, portability of the shot hole drilling rig is an
important consideration. 105
Vibroseis Sources
Vibroseis sources are low
power units which achieve
high energy levels by
vibrating the ground over
several seconds.
106
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107
Vibroseis Sources
Vibroseis sources sweep a pad of approximately
1m2 through a range of frequencies, using an
hydraulic system. 108
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Air-guns – Introduction
These create a seismic signal through the rapid
discharge of compressed air at 2000 psi into the
water. It is an environmentally friendly alternative to
explosives.
Air-guns generate an oscillating bubble pulse in
addition to the primary pulse.
Arrays of many air-guns of various sizes are used
to cancel the bubble pulse and to improve signal-
to-noise ratios. 109
110
Marine seismic surveys use air-guns to send out
the seismic signal. An air-gun works by releasing
air under high pressure (140 bar) into the water.
Air-guns – Operation
The air-gun is towed, usually
in an array with other guns,
5-15m depth behind the ship.
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Each air-gun is armed with
high pressure > 2000 psi,
compressed air.
Each air-gun is discharged
by bleeding air under the
flange of the shuttle in the
upper chamber.
111
112
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113
114
The high pressured air is generated by a
compressor on the ship, and the timing
of the shot comes from the navigation
system via a gun controller.
The high-pressured air is stored in two
chambers inside the air-gun (see figure
above).
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115
The firing signal is sent as an electric signal to the
magnetic sensor on the air-gun. Air is released
under the upper piston causing the air in the
lowermost chamber to be released
instantaneously as an explosion.
When the shot has been fired, a signal is sent from
the magnetic sensor to the gun controller.
If the shot was not fired at exactly zero time, the
gun controller will adjust the shot-time for the next
shot.
Air-Gun Signatures
Air-guns are typically 10 to 20 cm in diameter and
from 10 in3 to 500 in3 in size. Usually, operating air
pressure is 2000 psi and guns are deployed at
depth of 5-15 m.
Signature consists of (1) direct arrival from air-gun
ports, (2) ghost or reflection from surface of the
water, and (3) the bubble pulses produced by the
expansion-collapse of the air bubble.
Signature is given by strength and bubble period. 116
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117
Although the initial energy burst is
reasonable, a complex pressure
interaction between the air bubble
and the water causes the bubble
to oscillate as it floats towards the
surface.
Output of air-guns
118
This effect produces the extraneous
bursts of energy following the initial
burst.
The period of the bubble oscillations
is given approximately by the modified
Rayleigh-Willis formula
𝑇 = 𝑘𝑃13 𝑉13
𝑃𝑎𝑡𝑚 + 𝜌𝑔𝐷56
Where P is the gun pressure, V is the gun volume, Patm is atmospheric pressure, ρ is the density of water g is gravitational acceleration and D is the depth of the gun, and k is a constant whose value depends on the units.
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119
From the bubble period of one gun of
known volume, pressure, depth and
bubble period, it is possible to determine
the constant k.
It follows directly from this formula that the
bigger the capacity of the gun fired, the
longer the period of oscillation.
Air-guns – Bubble Pulse Reduction
Each air-gun produces a
bubble, upon firing of the
gun. The bubble period is
proportional to the cube root
of pressure and the cube
root of gun volume.
120
The figures show a comparison of the source signatures: (a) a single air-gun (peak
pressure 4.6 bar metres) and (b) a seven gun array (peak pressure 39.9 bar metres) note
the effective suppression of the bubble pulse in the latter case.
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Air-Gun Arrays
The signature of a single air-gun is unsatisfactory,
because it is too weak to produce good signal-to-noise
ratios at large target depths, and because the bubble
pulses are difficult to remove with deconvolution.
Both problems can be overcome with tuned air-gun
arrays in which many guns of different carefully selected
volumes are fired simultaneously.
Arrays improve the primary-to-bubble ratio (PBR). Arrays
can have up to 100 air-guns, but 25-50 is more typical. 121
Signature Measurement
Sound pressure created by a single air-
gun is inversely proportional to the
distance.
If the source signature is measured close
to the array, the signal is found to be very
distorted. This is because the influence of
the individual airgun is too big. 122
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123
This is why the source signature is
measured in the far-field, which is the
region where the shape of the pulse
does not change with distance.
The far-field signature represents the
output of the total array.
124
It is obtained by towing a hydrophone
at a depth of >300m below the centre of the array.
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Strength of an Air-Gun Array
The SEG-approved unit for far-field
strength is the bar-m. A bar is a unit of
pressure equal to 14.5 psi or 1
atmosphere or 1011 μPa (micro-Pascal).
125
The bar-m is obtained by multiplying the
measured pressure expressed in bars by the
distance between the source and the sensor.
The advantage of the bar-m is that source
strength is characterized by a single number.
Average air-gun array signal is about 10-20
bar-m.
126
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Measuring Signal Levels
Sound levels are usually measured with the
decibel scale:
Air Water Comments
re 20 μPa re 1 μPa
0 62 Hearing threshold
60 122 Office environment
120 182 Feeling threshold
140 202 Pain threshold
160 222 Damage threshold 127
Marine Sound Sources
Large tanker 170 db re 1 μPa @ 1m
Fishing trawler 150 – 160 db
Air-gun arrays 210 – 250 db
1 kg explosives 270 db
Sperm whales 200 - 225 db 128
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CHABA specification for impulse noise versus
continuous noise on humans state “no
protection required” below 208 db in water
environment.
CHABA specifications indicate that if there are
fewer than 1000 impulses per day then the
sound level can be increased by another 20
db.
129
Sound and Marine Life
50 fish families have sound-producing species, while all
mammals are vocal underwater.
Signal levels exceeding 230 – 240 db are necessary to
cause damage to fish eggs and lavae.
Sound levels of 220 db caused fish to side skip.
Damage to marine life is considered low.
Major impact is considered to be on communication,
avoiding predators, catching prey, migration paths,
resting areas, etc., i.e. the ability to survive issues. 130
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Air-guns on Mammals
Air-gun design, underwater acoustics, animal
behavior, and marine mammal physiology are
complex subjects and interactions between them
are even more complex.
Can interpret the same data in quite different
ways, eg, whales breeching.
Escaping or enjoying?
131
Anecdotes of whales being attracted by air-
guns.
Mating whales have ignored seismic vessels
under survey.
With no clear consensus, many organizations
recommend mitigation practices.
132
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Marine Acquisition
Sources are air-gun arrays. Receivers are
usually multiple streamers. Hydrophones,
which are pressure sensitive, are the
receiving elements. 133
Arrays
1 – Receiver arrays
2 – Source arrays
134
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Receiver Arrays
In the days of analogue recording,
ground roll could often over-power
reflections.
Therefore, receiver arrays were
employed mainly to attenuate ground
roll. 135
Summing up a number of receivers in an
array can increase the strength of the
reflected signal.
However, arrays which effectively
attenuate ground roll, must be long,
usually >100m. This however reduces
resolution!
136
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Response of Receiver Arrays
The response of receiver arrays is a
function of the number of elements in the
array.
The greater separation between the
elements, the greater the improvement of
the attenuation of longer wavelengths is.
137
Receiver Arrays with Data
The receiver array, which is 140m long, has greatly
attenuated the ground roll.
138
Noise test to determine the appropriate
detector array for a seismic reflector
survey.
(a) Seismic record obtained with a
noise spread composed of
clustered geophones.
(b) Seismic record obtained over the
same ground with a spread
composed of 140m long geophone
arrays.
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Receiver Arrays – The Realities
Receiver arrays were developed to attenuate
ground roll when analogue recording systems
had limited dynamic range.
139
Ground roll is currently more
effectively attenuated in data
processing through high fold stacking.
The “stack array”, formed with the
CMP gather, is an array as long as the
receiver spread.
140
Below is an example of a CMP-gather. The
figure shows that increasing the shot-receiver
distance, increases the travel-time.
Processing – NMO
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141
The difference between (assumed)
vertical two-way travel-time and
observed travel-time is called normal-
move-out (NMO).
142
Processing stages of seismic traces
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Receiver arrays can minimize spatial aliasing,
which was a major concern with large trace
spacings.
143
However, arrays reduce
resolution, because of
differential moveout.
The current trend is towards reduced trace
spacings and ultimately, towards point
receivers.
Aliasing
Source Arrays
Source arrays achieve much the same as receiver
arrays.
Source arrays are common with Vibroseis
sources, in order to:
(i) increase signal into the ground and in turn,
signal-to-noise ratios and
(ii) attenuate ground roll. 144
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145
The new generation 90,000lbs
vibrators are reputedly as effective as
three 60,000lb units.
„It is extremely likely that source arrays
will become less common in the
future.
Arrays – A Summary
Arrays for sources and more commonly
receivers have seen extensive use as a
means of reducing ground roll, and
spatial aliasing.
Receiver arrays are most effective when
they are of a comparable length to the
wavelength of the ground roll. 146
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Long receiver arrays reduce resolution.
Ground roll is currently most effectively
attenuated in the processing stages with the
“stack array.”
Point receivers and point sources are seeing
greater use, and permit even better
attenuation of ground roll through digital group
forming. 147
148
LECTURE 6
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Common Midpoint Methods Common Midpoint (CMP) methods can be viewed as the
acoustic equivalent of the lens in optics.
By recording sufficient redundant data and then
processing it so that it focuses on the target, other
“extraneous” signals, such as multiples and ground roll,
are attenuated because they are out of focus.
An essential factor for the success of CMP methods is
sufficiently high fold, which has been facilitated with
sources such as air-guns in the marine environment and
Vibroseis on land. 149
CMP Data Acquisition
The essential feature of CMP data
acquisition is to obtain a multiplicity of
reflections from the same point(s) in the
subsurface, with a multiplicity of source
points.
150
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151
Therefore, source points
can be as regular as every
receiver interval.
The shot Gather Operation
The data are acquired as “shot gathers”,
i.e., each trace has the same shot point.
152
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153
The data are then reordered or sorted
into “CMP gathers”, that is, each trace
has the same midpoint.
Incidentally, the shot and CMP gathers
appear to be very similar.
Shot and CMP Gathers
Shot and CMP gathers appear very similar!
154
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A CMP Gather
The raypaths for a single CMP
gather cover a range of source-to-
receiver offsets.
Can you visualize a lens
equivalent?
155
Shot & CMP Gathers – Differences
There are TWO major differences
between shot and CMP gathers.
The first is that the interval of each
interface sampled is reduced from half
the spread length, to essentially a point.
156
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The second difference is that the reflection
hyperbolae are always symmetrical about the
midpoint, EVEN WITH DIPPING
INTERFACES.
Symmetrical hyperbolae facilitate automatic
processing, in particular, velocity analyses of
the data.
157
158
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Raypaths for Shot and CMP Gathers
159
CMP Methods – A Summary
CMP methods are the standard method for acquiring
seismic reflection data.
CMP methods acquire HIGHLY REDUNDANT data.
Redundancy is used to reinforce primary reflections and
to attenuate noise with stacking.
CMP gathers generate symmetric hyperbolae, which
have major conveniences in the processing of the data.
160
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161
LECTURE 7
Noise
1 – Coherent noise
2 – Random noise
162
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What Is Noise?
Noise is everything other than primary
reflections, also known as single bounce
reflections.
Noise can be coherent, such as multiple
reflections. Often multiples can be strong in
marine surveys with reverberations in the
water column. 163
164
Coherent noise is unwanted seismic energy that
shows consistent phase from one seismic trace to
another.
With land operations, ground roll or surface waves,
especially with surface energy sources are another
major source of coherent noise.
Here the waves travels through the top of the
surface layer, also known as the weathering layer.
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Multiple Reflections
Multiples can be generated
in many ways.
Multiples constitute one of
the principal sources of
“noise” with many seismic
operations.
165
166
This is energy trapped within a layer
which is another form of coherent energy.
Multiples are internal reflections in a
layer, which occur when exceptionally
large reflection coefficients are present.
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Random Noise
Noise can be random, such as wind noise, cultural
noise from infrastructure, vehicles, boats, etc.
Random noise such as wind noise, streamer noise
or sea noise is usually monitored during
acquisition.
When the noise levels rise above the contractually
agreed levels, acquisition is usually stopped. In
many cases, slashing or rolling the vegetation can
reduced the effects of wind. 167
Random noise is usually reduced in
processing by stacking.
168
Essentially, random noise is
reduced by the square root
of the number of traces in
the stack.
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Improving S/N Ratios with CMP Stacking
Stacking improves signal-to-noise ratios as the
square root of the number of traces in the CMP
stack.
Below are seismic sections showing how stacking
of seismic traces can improve the signal-to-noise
ratio. The horizontal scales are different.
169
170
A single-fold section obtained in 1965.
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171
A 4-fold stacked section obtained in 1967
172
A 12-fold stacked section obtained in 1981 along the same traverse.
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Scattered Noise
Scattered noise or diffractions are common in
rocks like carbonates.
Often, scattered noise is signal which belongs
somewhere else, rather than in the plane of
the seismic section.
When in doubt, filtering it out can be a
common approach. 173
174
Effect of f-k filtering of a seismic section. Left is a stacked section
showing steeply dipping coherent noise events, especially below
4.5s two-way reflection time. Right showing same section after
rejection of noise by f-k filtering
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Noise – A Summary
Noise is everything other than primary reflections, also
known as single bounce reflections.
Noise can be coherent, such as multiple reflections.
Often multiples can be as strong as primaries, as in
marine surveys with reverberations in the water column.
With land operations, ground roll or surface waves,
especially with surface energy sources are another major
source of coherent noise.
175
Noise can be random, such as wind noise, cultural
noise from infrastructure, vehicles, boats, etc.
Acquisition system noise is rarely an issue.
Noise is usually addressed in data processing.
176
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177
LECTURE 8
Amplitudes
All seismic systems currently in use have 24-
bit recording and therefore, they have
sufficient dynamic range to record every
seismic signal.
The limiting factor in data acquisition is
usually the dynamic range of the receivers.
178
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The processing of the seismic data utilizes the full
dynamic range of the recorded data.
The real limiting factor is the dynamic range of the
human eye, that is, the display of the data is the
issue. 179
MEMS (micro-electro-mechanical-system)
receivers have greater dynamic range
than the standard geophone.
Spherical Divergence
The major cause of the dramatic variations in
seismic amplitudes down the seismic record
is spherical divergence.
This results from the apparent loss of energy
from a wave as it spreads during travel.
Spherical divergence decreases energy with
the square of the distance 180
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181
Spherical divergence and attenuation of seismic waves causes a
Fresnel zone, shown in this 2D sketch as length A-A'. In 3D
seismic, the Fresnel zone is circular and has diameter A-A'.
The Fresnel zone is the area in the subsurface which contributes
to each reflection. The diameter of this zone, which can be quite
large, can be reduced through seismic migration.
182
The area of a hemisphere is proportional
to the square of the radius, that is, double
the radius, quadruple the surface area.
Therefore, the seismic amplitudes
systematically decrease with recording
time, simply because the energy is
spread over a larger area.
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As a result, the dynamic range of the seismic data
is greater than the human eye can accommodate.
The dynamic range of the human eye is about
42db to 48db.
Therefore, seismic data must be gained to
facilitate convenient examination by observers
during acquisition and geophysicists.
183
During processing, corrections for
spherical divergence is usually made.
These corrections are based more on
appearance of being true or real, than on
science.
184
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185
Before
After
Amplitudes – A Summary
Seismic amplitudes can exhibit very large dynamic
range, often > 96 db, largely because of geometric
spreading.
Current 24 bit acquisition systems with 144 db of
dynamic range are adequate to record most
seismic signals.
The human eye has a limited dynamic range of 42
db – 48 db. 186
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189
Datum Statics
In marine seismic, the sea surface
defines a datum for further processing.
Hence, only minor static corrections are
introduced to compensate for the source-
and streamer-depths.
190
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However, in land seismic static corrections play a
much more important role, since variations in
topography may cause severe distortions if not
corrected for.
191
192
Statics aim to replace the irregular
topography and weathered layer with a
flat surface at the datum.
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Statics – The Results
Statics remove the irregularities in travel-times
caused by the variations in topography and
weathering, so that standard processing
methods, such as NMO, can be applied
automatically.
193
Seismic Data Processing
1 – Velocity analysis
2 – Stacking
3 – Deconvolution
4 – Migration
194
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Data Processing – Objectives
The aims of data processing are to:
(i) Improve signal-to-noise ratios, mainly through
CMP stacking.
(ii) To improve vertical resolution, mainly through
deconvolution.
(iii) To improve lateral resolution, mainly through
migration a.k.a imaging. 195
Seismic data processing
CMP Gathers: The data are recorded in the field as files
for each shot. These are known as common shot
gathers.
196
The data are then re-arranged
within the processing computer
into common midpoint or CMP
gathers, i.e. all of the traces
from various shots with the
same mid point (i.e., with the
same station number on the
ground mid way between the
shot and the geophone) are
gathered together.
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Statics: Statics are the corrections for the
variable near surface weathered layer. They
are usually computed with the first arrival
refraction data, and they are one of the
important factors limiting the resolution of
seismic surveys.
Like NMO corrections, they are time shifts.
Statics and NMO are different sides of the
same coin, i.e. they are inter-related. 197
NMO Corrections: Each trace within a gather
is corrected in order to remove the NMO,
which is the difference between the travel-
time for an inclined raypath, over the travel-
time for a vertical raypath.
The amount of correction is a measure of the
average horizontal seismic velocity to that
reflector. 198
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Stacking: The NMO corrected traces are
added together to form a stacked trace. Not
only does this process improve signal-to-
noise ratios, but it also reduces the amount of
data.
Deconvolution: Deconvolution aims at
compressing the seismic wavelet, close to an
approximation of a spike as possible. 199
Deconvolution cont…
It also removes reverberations, Improves
bandwidth, sharpens wavelets and removes
multiples.
200
Left show figure without deconvolution and right shows figure
when deconvolved
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201
Removal of reverberations by predictive
deconvolution. The seismic record on the
left above is dominated by strong
reverberations. Below, same seismic
record after spiking deconvolution
Spiking deconvolution seeks to
whiten the signal, while gapped
deconvolution seeks to reduce the
number of cycles in a reflection
wavelet. The many cycles can be
caused by reverberations within the
shot point, by the ghost or reflection
from the earth's surface, or by
reverberations within reflectors.
Filtering: The spectrum of the traces is
filtered to reduce those frequencies where
noise predominates.
This process is usually so effective that small
faults are often removed!
202
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Migration: Signals from each point in the
subsurface are recorded over a large area on
the surface (fresnel zone). Seismic migration
is the process which collapses the reflection
energy back to the source. It sharpens all
structures, including faults.
203
Migration cont…
Migration is more correctly known as
imaging. We plot the reflectors below the
CMP. Migration moves the reflections up-
dip to their correct position.
204
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Migration - Application
Migration:
(i) repositions reflections to their correct place in the
subsurface.
(ii) unscrambles complex reflections.
Migration effectively collapses the Fresnel zone.
205
206
Migrated
CMP gather after muting Filtered
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Depth Migration
Migration in the time domain can be
ineffective, where there are large velocity
changes, such as where salt pillows
occur.
In such circumstances, migration in the
depth domain is required. 207
208
(a) CMP stack and (b) its
migration. Time migration
treats the top of the salt “T”
properly, while it fails to
image the salt base “B”
accurately. Depth migration
must be done to handle
this properly.
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Velocity Spectra – Theory
The normal moveout (NMO), is a function
of offset x, t0, and velocity. A range of
velocities is used and that which produces
the best stack is taken as the NMO
velocity.
209
210
A set of reflection events in a CDP gather using a range of
velocity values. The stacking velocity is that which
produces peak cross power from stacked events. i.e., the
velocity that most successfully removes the NMO. In this
case, V2 represents the stacking velocity.
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211
The NMO velocities are determined from
velocity spectra computed at regular
closely spaced intervals down the CMP
gather.
Velocity Spectra – Application
Muting for NMO Stretch
NMO corrections stretch
the seismic trace.
Shallow reflections are
corrected more than
deep reflections.
The stretched signals can degrade the stack, but
are surgically removed with muting, prior to
stacking. 212
NMO correction and muting of a stretched zone
on field data. (a) CMP gather, (b) NMO
correction and (c) mute
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The purpose of muting is to remove:
• Direct waves
• Refracted waves (i.e. mainly associated with the
waterbottom in marine seismics).
213
Too mild mute function applied
Examples of muting
Proper choice of mute function
Too strong mute function applied 214
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Summary
Seismic data processing aims to convert
to field data into an image of the
subsurface.
The volumes of data can be staggering,
and one aim of the processing stage is to
reduce the amount of data to manageable
and practical sizes. 215
The first step in the processing stream is to remove
the effects of spherical divergence.
The seismic traces are amplified using a gain
function which accommodates the loss of signal
strength with time and distance.
The next step is to re-arrange the data from the
common shot files or gathers, into common
midpoint gathers. This is very computer intensive.
216
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For land seismic surveys, the corrections for
variations in surface topography and
thickness of the weathered layer, known as
static corrections, are required to re-align the
reflections.
The reflection time is a hyperbolic function of
the source to receiver separation, the
reflector depth, and the average seismic
velocity to the reflector. 217
This curvature is known as Normal Move Out,
and its removal to obtain aligned reflections
also provides a measure of the average
seismic velocity.
The NMO corrected gathers are then added
or stacked
218
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Convolution and deconvolution filtering are
processes which effect the temporal spectrum of
each seismic trace.
They are used to improve resolution by sharpening
the seismic pulse and by removing reverberations.
Velocity filtering operates on sets of seismic traces,
in order to remove or enhance data with particular
apparent seismic velocities, such as ground roll. 219
Migration is the process of collapsing scattered
seismic signals data back to their source in the
subsurface.
The Fresnel zone is the area in the subsurface
which contributes to each reflection.
The diameter of this zone, which can be quite
large, can be reduced through seismic migration.
220
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Marine Systems
Known as ocean-bottom cables (OBC), uses
four component (4C) receivers – three
component velocity geophones and one
hydrophone. Often buried in the sea floor.
223
Use pop-up buoys at the end
of each line to interface with
recording equipment in shallow
waters (<1000 ft).
Permanent Seismic Monitoring
Permanent seismic monitoring is
becoming an important tool in the
reservoir management toolkit.
224
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It is a 4C fiber-optic advanced seismic acquisition
technology, that is installed permanently on the
seabed over a producing field.
Permanent installation of 4C cables
at the sea bottom over a producing
field.
It improves data quality by ensuring
more accurate receiver locations
within the repeated 3D surveys
over a period of time.
225
It reduces acquisition time and cost.
Permanent seismic monitoring helps to improve
data quality by employing more accurate survey
orientation and acquisition geometry (receiver
locations) within the repeated 3D seismic surveys
compared to conventional OBS 4D survey.
Such a method is important in monitoring a
reservoir injection process employed to enhance
recovery from a producing reservoir. 226
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Use fibre optic connection to platforms for
deep deployments.
Need to consider retrieval and repair
because of strong sea floor currents, etc.
Need to know precise location of
sensors.
227
OBC System
228
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The use of 4C OBS recording has
several advantages over conventional
towed streamer technology, which
includes:
• Dual-sensor summation (3C geophone
+ hydrophone) for the suppression of
receiver-side multiples.
229
• Utilizing P–S wave conversions for enhanced
imaging.
A comparison of seismic data
acquired by the towed
streamer (top) and OBS
(bottom) techniques.
The OBS survey significantly
improves the subsurface
image.
230
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• Attenuation of free surface multiples when combined
with towed streamer recording.
A comparison of the migrated P–S stack versus the P–P
stack is shown below.
Comparison of P–P stack of
conventional 3D streamer data
(top) and P–S stack of OBS
data (bottom).
Note how the OBS data
produces a much better deeper
image in the presence of gas
versus 3D streamer data.
231
The P–S stack is produced from OBS
converted wave data whereas the P–P
stack is produced from 3D towed
streamer P-wave data.
From this comparison it is clear that OBS
data can be used to successfully image
through a gas chimney.
232
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Passive Seismic Monitoring
This technique is quite common in mining operations.
Here, detectors are cemented into the borehole, between
the casing and rock. These measure the microseismic
activities associated with production and development.
• These can locate fractures using triangulation.
• Can often detect if fractures are opening or closing.
• Useful in monitoring hydraulic fracturing.
233
Direct Detection of Hydrocarbons DHI
Direct Hydrocarbon Indicators
234
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Flat Spots
The standard exploration approach seeks
to find structural or stratigraphic targets
which are favorable for hydrocarbon
accumulations.
However, it is possible to directly detect
hydrocarbons under certain conditions,
especially in younger sediments. 235
A key diagnostic for the presence of
hydrocarbons is a flat spot.
In this situation, the hydrocarbon-brine
contact produces a flat/horizontal
reflection, inconsistent with the lithological
reflections from the trap boundaries, and
over a limited area bounded by structural
contours. 236
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Where it can be reliably detected and
mapped, the flat spot can provide a
reasonably unambiguous indication and
areal extent of a reservoir and an
estimate of reservoir thickness.
237
A flat spot can indicate a gas-oil, gas-
water, or oil-water interface, with the
reflection coefficient for the last interface
being substantially lower than that of
each of the others.
238
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Flat Spot Examples
239
Bright Spots
The amplitudes of the reflected and
transmitted signals are described by the
Zoeppritz equations.
These equations are quite complex, but
simplify considerably at normal incidence.
240
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Under most circumstances, these approximations are
sufficiently valid up to the critical angle, where phase
shifts can occur.
In young sediments, the presence of gas in a reservoir
usually further reduces the specific acoustic impendence,
and therefore, increases the magnitude of the reflection
amplitude. These are known as bright spots.
However, there can be other effects, such as dim spots
and phase changes which depend upon the petrophysical
contrasts of the reservoir with the surrounding layers. 241
Effect of Gas on the Poisson’s Ratio
Poisson’s ratio, σ, is the ratio of the fractional
transverse contraction (transverse strain) to the
fractional longitudinal extension (longitudinal strain)
when a rod is stretched.
242
It varies between 0 and 0.5. It
has a value of 0.5 for fluids and
0.25 for a Poisson solid.
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Classical elasticity determines compressional
and shear wave velocities with the equations:
These equations can be combined to obtain the
ratio of the compressional and shear wave
velocities in terms of Poisson’s ratio:
243
𝑉𝑝 = 𝜆 + 2𝜇
𝜌=𝐾 +43𝜇
𝜌 𝑎𝑛𝑑 𝑉𝑠 =
𝜇
𝜌
𝑉𝑠𝑉𝑝= 0.5 − 𝜎
1 − 𝜎
The s-wave velocities largely depend on the
fluid content of rocks, whereas the p-wave
velocities are significantly affected. However,
there are significant inconveniences with
shear wave acquisition and processing.
Therefore, the measurement of the p-wave
velocity and Poisson’s ratio, provides an
alternative means of determining fluid
saturates in a reservoir. 244
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Amplitude Variation with Offset (AVO)
The Zoeppritz's equations are usually
adequate for large angles of incidence. Where
the angle of incidence is other than normal,
both P and S-waves are generated.
The reflection coefficient depends upon the
ratio of the P and S-wave velocities, or what is
equivalent to the Poisson's ratio.
245
The Shuey approximation of the reflection
coefficient for non-normal incidence is given
by:
If there is no contrast in Poisson's
ratio across an interface, the second
term is zero and the variation with
angle is simply the cosine factor,
which causes a decrease of
amplitude with increasing angle. 246
𝐴𝑟𝑒𝑓𝑙𝑒𝑐𝑡𝑒𝑑
𝐴𝑖𝑛𝑐𝑖𝑑𝑒𝑛𝑡= 𝜌2𝑉2 − 𝜌1 𝑉1𝜌2𝑉2 + 𝜌1 𝑉1
𝑐𝑜𝑠2𝜃 + 2.25 𝜎2 − 𝜎1 𝑠𝑖𝑛2𝜃
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If there is a significant contrast in the
Poisson's ratio, as normally occurs at the
boundary of gas sands, then the second term
becomes important and the amplitude
generally increases with increasing angle.
The increase of amplitude with increasing
angle of incidence, or recording offset, can be
used as a diagnostic in the identification of
gas reservoirs. 247
AVO – Case Study
Coal and gas sands both have low seismic
velocities and low densities, and therefore, they
generate strong reflection amplitudes.
248
How can they be differentiated?
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Chronostratigraphy and Lithostratigraphy
The Shuey approximation of the reflection
coefficient for non-normal incidence is given
by:
249
𝐴𝑟𝑒𝑓𝑙𝑒𝑐𝑡𝑒𝑑
𝐴𝑖𝑛𝑐𝑖𝑑𝑒𝑛𝑡= 𝜌2𝑉2 − 𝜌1 𝑉1𝜌2𝑉2 + 𝜌1 𝑉1
𝑐𝑜𝑠2𝜃 +𝜎2 − 𝜎1
1 − 0.5 𝜎2 + 𝜎1 2𝑠𝑖𝑛2𝜃
The normal incidence reflection coefficient is
the chronostratigraphic reflection coefficient.
The Poisson’s ratio reflection coefficient is the
lithostratigraphic reflection coefficient.
250
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AVO Cross- Plot
Poisson’s ratio provides a
means of differentiating
gas sands from wet sands
and shales.
251
DHI – A Summary
• Gas-liquid contacts can be recognized as flat spots.
• The large reductions in seismic velocities and densities
with gas sands can produce high amplitudes or bright
sands with young sediments.
• With older sediments, the occurrence of gas is detected
with AVO which is a measure of the change in Poisson’s
ratio.
• Most current methods of seismic inversion include the
AVO response and invert for P and S wave velocities and
density. 252
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253
LECTURE 11
254
Land Acquisition
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A complication in land acquisition is that,
unlike marine data, a seismic line is rarely
shot in a straight line because of the presence
of natural and man-made obstructions such
as lakes, buildings and roads.
255
The shot points and the receivers may be
arranged in many ways.
Many groups of geophones are commonly
used on a line with shot points at the end or
in the middle of the receiver array.
The shot points are gradually moved along a
line of geophones.
256
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The variations in ground elevation in land
acquisition causes sound waves to reach
the recording geophones with different
travel-time.
The Earth’s near-surface layer may also
vary greatly in composition, from soft
alluvial sediments to hard rocks. 257
This means that the velocity of sound waves
transmitted through this surface layer may be
highly variable.
258
Static corrections, just like in marine
seismic, involves applying a bulk time
shift to a seismic trace during seismic
processing to compensate for these
differences in elevations of sources
and receivers and near-surface velocity
variations.
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Vertical Seismic Profile (VSP)
VSP is a technique of seismic data
acquisition, whose data is used for correlation
with conventional seismic data (land or
marine seismic).
259
The defining characteristic of a VSP is that
either the energy source, or the receivers (or
sometimes both) are in a borehole.
VSPs include the zero-offset VSP, offset VSP,
walkaway VSP, walk-above VSP, salt-
proximity VSP, shear-wave VSP, and drill-
noise or seismic-while drilling VSP.
Read more about each VSP
260
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VSP involves a series of measurements in
which a seismic signal generated at the
surface is recorded by geophones secured to
the side of a borehole, at various depths.
The receiver interval is commonly 15m,
although a 7.5m interval has been employed
for greater resolution. VSP is a modernization
of the earlier “check shot” survey. 261
262
A check shot survey differs from a VSP in the
number and density of receiver depths
recorded.
Geophone positions may be widely and
irregularly located in the wellbore, whereas a
VSP usually has numerous geophones
positioned at closely and regularly spaced
intervals in the wellbore.
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Initially, only a single channel sonde was
used. However, Reservoir Seismic 2020 are
deploying up to 1200 channels within the
borehole.
The arrays can be deployed in horizontal
as well as vertical boreholes
263
264
Initially, VSPs were used to obtain an
accurate time-depth correlation, and to
separate upward travelling signal from
downward propagating signal, in order to
optimize deconvolution, recognize
multiples, etc.
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In the most common type of VSP, hydrophones, or
more often geophones in the borehole record
reflected seismic energy originating from a seismic
source at the surface.
Acquisition of VSP. The downhole
geophones record important structural
and stratigraphic data generated by a
surface energy source.
The VSPs vary in the well configuration,
the number and location of sources and
geophones, and how they are deployed. 265
VSP – Land Source 1
The most common land source is
Vibroseis.
However, air-guns, (both truck
mounted and mud pit located) have
been employed.
Dynamite provides good energy
levels.
266
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VSP – Land Source 2
267
Cross-well seismic
Detailed understanding of reservoir flow and
barrier architecture is crucial to optimizing
hydrocarbon recovery.
Cross-well seismic, that is using seismic sources in
a wellbore and recording the wave propagation in
another wellbore has the potential of giving high-
resolution images of features like faults,
unconformities, sequence porosity and fracturing. 268
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269
Cross-well data currently are expensive to
acquire and the technique is almost solely
employed onshore.
Use of cross-well seismic in marine
environments is difficult because of
the large distances between the
boreholes and the complicated
geometrical shape of the (deviated)
wells.
4D Seismic
The acquisition of 4D or time-lapse
seismic has opened new horizons for
monitoring reservoir properties such as
fluids, temperature, saturation and
pressure changes during the productive
life of a field. 270
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4D seismic is based on the analysis of repeated 3D
seismic data.
The differences in seismic
attributes over time are caused
by changes in pore fluid and
pore pressure associated with
the drainage of a reservoir
under production.
271
Detection of areas with significant changes or
with virtually unchanged hydrocarbon
indicating attributes helps to determine new
drilling sites in an already existing production
field.
For this method, it is critical that the observed
seismic changes can be related to the fluid
flow. 272
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Differences in data acquisition, survey
orientation, processing, and data quality
can introduce significant noise in a 4D
analysis.
Hence, such differences must be
corrected for as best as possible.
273
The known applications of 4D seismic can be
summarized as:
• Monitoring the spatial extent of steam injection used
for thermal recovery.
• Monitoring the spatial extent of the injected water
front used for secondary recovery.
• Imaging bypassed oil or gas.
• Determining the flow properties of sealing or leaking
faults.
• Detecting changes in oil-water contact. 274
Read more about 4D seismic
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275
Enhanced Oil Recovery (EOR)
Seismic Processing
Seismic technology has achieved amazing
achievements in exploration and production
activities in the past few decades.
What we record in the acquisition stage is
called raw seismic data, which contains real
signals, together with noise and multiples.
276
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This raw data must then be processed by
employing advanced methods within
signal processing and wave-theory to get
better images of the subsurface.
277
The prime objective in the processing stage is
to enhance the signal and suppress the
coherent and non-coherent noises and
multiples.
Raw seismic data with coherent
and non-coherent noise. 278
Noise attenuation image after
autocorrelation, deconvolution and
trace muting.
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Coherent noise is unwanted seismic energy
that shows consistent phase from one
seismic trace to another.
279
This may consist of waves that
travel through the air at very low
velocities such as airwaves or air
blast, and ground roll that travels
through the top of the surface
layer, also known as the
weathering layer.
The energy trapped within a layer known as
multiples is another form of coherent energy.
Multiples are internal reflections in a layer,
which occur when exceptionally large
reflection coefficients are present.
In marine seismic, the water-bottom multiples
normally dominate.
280
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Non-coherent energy is typically non-seismic-
generated noise, such as noise from wind,
moving vehicles, overhead power line or high-
voltage pickup, gas flares and water injection
plants.
281
It has been stated earlier that seismic
processing is the alteration of seismic data to
suppress noise, enhance signal and migrate
seismic events to the appropriate location in
space.
Seismic processing facilitates better
interpretation, because subsurface structures
and reflection geometries become more
apparent. 282
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The actual sequence of the seismic
processing will be determined by (a) the
purpose of the investigation, (b) extensive
testing on selected parts of the dataset and
(c) a trade-off between quality and cost.
The 2D seismic processing steps typically
include static corrections, deconvolution,
velocity analysis, normal and dip moveout,
stacking and migration. 283
Amplitude losses
Seismic amplitude losses are caused by
three major factors:
1. Geometrical spreading.
2. Intrinsic attenuation.
3. Transmission losses.
284
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Geometric spreading: Progressive diminution of
amplitude (proportional to the inverse of
propagation distance) caused by increase in
wavefront area.
285
Intrinsic attenuation: energy losses due
to internal friction.
286
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Transmission losses: reduction in
wave amplitude due to reflection at
interfaces.
287
Amplitude recovery
This stage attempts to correct for amplitude losses
that are unrelated to the reflection coefficient, such
as; wave attenuation and source variations.
Both: Deterministic and Statistical approaches are
used.
288
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Deterministic approach:
A popular deterministic model is the t-square model,
where the data is multiplied by 𝑡2 (t being the two-way
travel-time).
It is based on the following assumptions:
• Multiplication with t to compensate for geometrical
spreading.
• An attenuation model of the type where the total
losses are given as an integration over all frequencies.
289
Statistical approach:
Automatic gain control (AGC) is the most common class of
routines.
They are based on these principles:
Let 𝑋𝑖 denote the amplitude at time-sample number i (i.e.
corresponding to time 𝑡𝑖 = 𝑖∆𝑡) of a seismic trace.
Introduce a tie-window of length 2𝐿 + 1 and compute the
weighted amplitude value around this sample point.
𝑥𝑖 =1
2𝐿 + 1 𝑤𝑖𝑥𝑖+𝑙 , 𝑤𝑖 𝑤𝑒𝑖𝑔𝑡 − 𝑓𝑎𝑐𝑡𝑜𝑟𝑠
𝐿
𝑙=−𝐿
290
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Examples of amplitude recovery
Raw data to the left and amplitude recovered data to the right
employing AGC.
291
Raw data to the left and amplitude recovered data to the
right employing 𝑡2
Examples of amplitude recovery cont..
292
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Raw data to the left and amplitude recovered data
to the left employing both AGC and 𝑡2
Examples of amplitude recovery cont..
293
Still during the processing stage, bad
measurements are edited, datuming applied
and corrections of wave-energy decay
introduced.
294
The true amplitude recovery
is applied to increase the
amplitude at large travel
times.
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Correlation
Cross-correlation is a measure of the similarity or
linearity between two waveforms.
Cross-correlation involves:
(1) cross-multiplication of the individual waveforms, and
summation of the cross-multiplication products over
the common time interval.
(2) progressively sliding one waveform past the other
and, for each time shift of lag, summing the cross-
multiplication products. 295
296
(a) North-South, East-West particle
oscillation components and (b)
their particle motion
(c) North-South, East-West particle
oscillation components and (d) the
fastest wave polarization direction.
(e) North-South, East-West particle
oscillation components rotated into
Fast and slow waves (f) Cross
correlation between the fast and
slow wave.
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The cross-correlation function is the value of
the sum, the cross-multiplication products as
a function of the lag time.
The cross-correlation operation is similar to
convolution, but it does not involve folding or
reversing one of the waveforms.
297
298
It can be shown that the cross-correlation of
two functions in the time domain is
mathematically equivalent to the multiplication
of their amplitude spectra and the subtraction
of their phase spectra in the frequency
domain.
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For two similar waveforms, the correlation function
will peak at zero lag.
For two functions containing only random noise,
the cross-correlation function is zero for all lag
values. Cross-correlation is used to detect weak
signals embedded in noise.
299
300
The width ∆𝜔, is a measure of resolution and the ratio
between the side lobes and the main lobe is a measure
of the S/N-ratio.
An ideal time-window should have:
• Narrow and strong main lobe (delta).
• As small as possible side lobes
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The width ∆𝜔, is a measure of resolution and the
ratio between the side lobes and the main lobe is a
measure of the S/N-ratio.
An ideal time-window should have:
• Narrow and strong main lobe (delta).
• As small as possible side lobes
301
It is used to convert Vibroseis field records
into correlated shot records.
A special case is autocorrelation, which is
symmetrical about the zero lag position. It is
used to detect hidden periodicities (multiples)
in any given waveform such as ghosts and
other reverberations in seismic reflection
methods. 302
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Vibroseis Correlation
303
Cross correlation of the sweep signal with the
field recording generates an output similar to
an impulsive source, such as dynamite.
The correlated pulse is a symmetrical zero
phase Klauder wavelet.
304
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Correlation
305
Autocorrelation is applied to compress the wavelet and to
attenuate multiples.
Autocorrelation is the cross-correlation of a signal with
itself. Informally, it is the similarity between observations
as a function of the time lag between them. It is a
mathematical tool for finding repeating patterns, such as
the presence of a periodic signal obscured by noise.
It is often used in signal processing for analyzing
functions or series of values, such as time domain
signals. 306
Autocorrelation
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Autocorrelation Cont…
Autocorrelation is widely used to determine
periodicity (multiples) in seismic signals. 307
Convolution
Suppose we need to determine the response
of a system, such as a stereo system, to an
input, such as a track from an audio CD, the
input can be viewed as a series of impulses
which;
(i) are separated by the digitizing interval
and
(ii) are scaled by the amplitude of the signal. 308
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The output is the sum of the multiplicity of impulse
responses which:
(i) are time shifted to correspond with the time of
the input impulse.
(ii) are scaled or multiplied by the amplitude of the
input value.
Convolution is the mathematical process used to
derive the output y(t) from the input g(t) and the
impulse response f(t). 309
The symbolic notation for convolution is *, ie.,
y(t) = g(t) * f(t).
Convolution, which is correctly known as an
integral transform, is simply a series of
multiply and add operations.
There are two major applications of
convolution in seismic exploration. 310
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The first is its use for filtering and inverse
filtering (deconvolution) of seismic data. It is
also applied to spatial data, e.g., image
processing.
The second is the description of the seismic
reflection process with “The Convolutional
Model.”
311
312
Deconvolution
This is a technique that can compress the
source signature and eliminate multiples
is applied after sorting the data into CMP
gathers.
Deconvolution and Convolution are different sides
of the same coin.
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Earth’s reflectivity series and the convolutional
trace model
We assume a stratigraphic (e.g. horizontally layered) earth
model.
The earth’s reflectivity series is then
a time series of spikes, where each
spike represents the plane-wave
reflection coefficient for a given layer
positioned at the zero-offset (e.g.
coincident source and receiver) two-
way travel-time (TWT) (neglecting
transmission losses across each
interface). 313
The seismic trace x(t) can then be described as a linear
convolution between the source pulse s(t) and the Earth’s
reflectivity series r(t):
𝑥 𝑡 = 𝑠 𝑡 ∗ 𝑟 𝑡
314
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Pulse shaping and inverse filtering
Pulse shaping (or signature processing)
transforms the seismic pulse to a more
compressed signal that is more optimal for further
processing and interpretation.
If the source pulse is given by s(t), we want to
design a filter with impulse response f(t) that
transforms the original pulse into another known
pulse b(t). 315
We can describe the problem in terms of a linear
convolutional model:
𝑓 𝑡 ∗ 𝑥 𝑡 = 𝑓 𝑡 ∗ 𝑠 𝑡 ∗ 𝑟 𝑡 = 𝑏 𝑡 ∗ 𝑟 𝑡
Assume for a moment that the filter f(t) is known. In the
time-domain, the pulse shaping is carried out according
to the equation
Where, 𝑠 𝑡 ∗ 𝑓 𝑡 = 𝑏 𝑡
Since we assume sampled signals (and filters), we must
in practice employ discrete linear convolution. 316
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317
In processing, deconvolution is an algorithm-based
process used to reverse the effects of convolution
on recorded data. The concept of deconvolution is
widely used in the techniques of signal processing
and image processing.
In general, the object of deconvolution is to find the
solution of a convolution equation of the form:
𝑠 𝑡 ∗ 𝑓 𝑡 = 𝑏 𝑡
318
Usually, b(t) is some recorded signal, and s(t) is
some signal that we wish to recover, but has been
convolved with some other signal f(t) before we
recorded it. The function f(t) might represent the
transfer function of an instrument.
If we know f(t), then we can perform deterministic
deconvolution. However, if we do not know f(t) in
advance, then we need to estimate it. This is most
often done using methods of statistical estimation
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Trace muting is also applied to get rid of
unwanted energy. Contributions from the direct
waves and possible head waves are removed by
trace muting.
319
Too mild mute function applied
Examples of muting
Proper choice of mute function
Too strong mute function applied
Due to muting, only a few traces are
left at shallow travel-times in the
CMP-gather
320
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321
NMO correction and F-K filtering are
usually applied to attenuate multiples.
Linear coherent noises are also removed
by employing F-K filtering.
322
A CMP-gather before the F-K filtering:
the primaries dipping up and the
multiples dipping down in a time-
distance display.
The same CMP gather after F-K
filtering. The F-K filtering accepted
only primary energy (within polygon)
and filtered out multiples energy.
The F-K domain (top, right)
shows energy distributions of
both primary and multiples
energy, respectively.
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The NMO is the difference between the
travel-time for a certain offset (X) and the
vertical (zero-offset) travel-time T(0).
Normal move out is applied according to
the following formula:
323
𝑇 𝑋 = 𝑇2 0 +𝑋
𝑉
2
where T(X) is the two-way travel time for a seismic
event, X is the actual source-receiver offset
distance, V is the NMO or stacking velocity for this
reflection event and T(0) is the two-way travel time
for zero offset.
Once the correct velocity function has
been interpolated, the exact moveout at
each sample is computed based on the
actual source-to-receiver offset and
velocity at that time sample.
NMO stretch is a fundamental and long-
standing problem in seismic processing. 324
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After normal moveout correction, the early events are
stretched at the far offset. If we stack this unmuted gather,
the early events suffer a severe loss of high-frequency
energy, and thus resolution.
NMO corrected CDP gathers show NMO stretch.
325
This can appreciably reduce the
interpretability of the seismic
section.
There have been many attempts
to solve the NMO stretch problem.
The most universal is stretch
muting, where samples at the
beginning of a trace that have
suffered severe NMO stretch are
zeroed out.
326
Stretch muting at the far offsets. Muting to remove NMO
stretch may destroy far offsets information
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In the case of dipping beds, there is no
common depth point shared by multiple
sources and receivers, so dip-move-out
(DMO) processing becomes necessary to
reduce smearing or inappropriate mixing
of data.
327
328
Effect of reflector dip on the reflection point. When the reflector is flat (top) the CMP is a
common reflection point. When the reflector dips (bottom) there is no CMP. A dipping
reflector may require changes in survey parameters, because reflections may involve more
distant sources and receivers than reflection from a flat layer
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Stacking is an important step in seismic
processing. Stacking represents summation
of NMO-corrected traces in a CMP family.
The collection of stacked traces forms a
seismic section which gives an image (slice)
of the subsurface.
329 Stacked seismic section.
The stacking process has two major
advantages:
(a) it increases the signal-to-noise (S/N) ratio
and
(b) it amplifies primary energy relative to
multiple energy.
This second point depends on a good velocity
analysis. 330
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In the case of an accurate velocity model,
stacking is the most efficient multiple removal
method.
A velocity model. 331
332
Seismic migration is the process by which seismic
events are geometrically re-located in either space
or time to the location the event occurred in the
subsurface rather than the location that it was
recorded at the surface, thereby creating a more
accurate image of the subsurface.
This process is necessary to overcome the
limitations of geophysical methods imposed by
areas of complex geology, such as: faults, salt
bodies, folding, etc.
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In general, migration is the process that
reverses wave propagation effects to get
clear images of the subsurface.
The term migration came about because,
compared to stack sections, the echoes
“migrate” to their true subsurface position.
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Seismic waves are elastic waves that
propagate through the Earth with a finite
velocity, governed by the acoustic properties
of the rock in which they are travelling.
At an interface between two rock types, with
different acoustic impedances, the seismic
energy is either refracted, reflected back
towards the surface or attenuated by the
medium.
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The reflected energy arrives at the surface
and is recorded by geophones that are placed
at a known distance away from the source of
the waves.
When a geophysicist views the recorded
energy from the geophone, they know both
the travel time and the distance between the
source and the receiver, but NOT the distance
down to the reflector.
336
In the simplest geological setting, with a single
horizontal reflector, a constant velocity and a
source and receiver at the same location, the
geophysicist can determine the location of the
reflection event by using the relationship:
𝑑 = 𝑣𝑡
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In this case, the distance is halved because it
can be assumed that it only took one-half of
the total travel time to reach the reflector from
the source, then the other half to return to the
receiver.
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The situation is more complex in the case of a dipping
reflector, as the first reflection originates from further up
the direction of dip and therefore, the travel-time plot will
show a reduced dip that is defined the “migrator’s
equation” : tan 𝜉𝑎 = 𝑠𝑖𝑛𝜉 where ξa is the apparent dip and ξ is the true dip.
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Zero-offset data is important to a geophysicist
because the migration operation is much simpler,
and can be represented by spherical surfaces.
When data is acquired at non-zero offsets, the
sphere becomes an ellipsoid and is much more
complex to represent (both geometrically, as well
as computationally).
340
Three vertical sections through or adjacent to a salt dome before migration
(top) and after migration (bottom), showing the repositioning of several
reflections near the salt face.
Migration Puts Reflections in their Place!
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Migration is used for several reasons; the
most important one is to move reflectors
from seismic “apparent” position to their
geological “true” position.
Another reason for doing migration is to
collapse and focus diffractions.
341
Seismic migrations are of four types: Pre-stack time
and Pre-stack depth migration, Post-stack time and
Post-stack depth migration.
Comparison of time domain images from (a) Pre-stack time
migration and (b) Post-stack time migration. 342
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In time migration, the images are displayed in two-
way travel times, and wave-field extrapolation is
done in a time stepping way.
Pre-stack time migrated.
343
Post-stack depth migrated.
In depth migration, the wave-stepping is
done with respect to depth, and the
images can be represented in a true
vertical depth
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LECTURE 12
Seismic Resolution
Seismic resolution is the ability to distinguish
separate features, the minimum distance
between two features, so that the two can be
defined separately rather than as one.
The limit of seismic resolution usually makes
us wonder, how thin a bed can we see?
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Normally, we think of resolution in the
vertical sense, but there is also a limit to
the horizontal width of an object that we
can interpret from seismic data.
347
Horizontal Resolution
The horizontal dimension of seismic resolution is
described by the Fresnel zone.
348
The Fresnel zone is a frequency
and range dependent area of a
reflector from which, most of the
energy of a reflection is returned
and arrival times differ by less than
half a period from the first break.
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The size of the Fresnel zone helps to
determine the minimum size of the feature
that can be seen in a seismic section.
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A Fresnel zone in 3D seismic is circular
and has diameter A–A´ where S is the
source position, Z is the depth down to
the target and λ is the wavelength.
Waves with such arrival times will interfere
constructively and so be detected as a single
arrival. Subsurface features smaller than the
Fresnel zone usually cannot be detected
using seismic waves.
At spacing greater than one-quarter of the
wavelength, the event begins to be resolvable
as two separate events.
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Migration can improve lateral resolution by
reducing the size of the Fresnel zone.
For a plane reflecting interface and coincident
source and receiver, the Fresnel zone will be
circular with its radius Rf expressed as:
𝑅𝑓 = 𝜆𝑍
2
where λ is the dominant wavelength and Z
is the depth down to the target surface.
Horizontal resolution depends on the
frequency and velocity of seismic waves.
If we introduce the centre frequency fc of
the pulse (i.e. representing the most energetic part), we have λ ≈ V/fc, with V
being the wave velocity.
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353
Hence, we can rewrite the formula for the
Fresnel zone as:
𝑅𝑓 = 𝑉𝑍
2𝑓𝑐
Remember, λ ≈ V/fc,
Vertical Resolution
Vertical resolution is the ability to separate
two features that are close together. A
seismic wave can be considered as a
propagating energy pulse.
If such a wave is being reflected from the top
and the bottom of a bed, the result will
depend on the interaction of closely spaced
pulses. 354
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In order for two nearby reflective interfaces to
be distinguished well, they have to be about λ/4 in thickness which is called the tuning
thickness.
355
This is also the thickness where
interpretation criteria change. For
smaller thickness, the limit of
visibility is reached and positional
uncertainties are introduced.
The typical recorded seismic frequencies are
in the range of 5–100 Hz. High frequency and
short wavelengths provide better vertical and
lateral resolution.
One could argue that we could simply
increase the power of our source so that high
frequencies could travel further without being
attenuated.
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However, there is a practical limitation in
generating high frequencies that can
penetrate large depths.
The Earth acts as a natural filter removing the
higher frequencies more readily than the
lower frequencies (absorption effect).
357
This means the deeper the source of reflections,
the lower the frequencies we can receive from
those depths and therefore the lower resolution we
appear to have from great depths.
358
Filtered seismic data showing frequency content variation with
depth.
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Each panel has been filtered to allow a
different band of frequencies.
As the band-pass rises, the maximum depth
of penetration of seismic energy decreases.
Lower frequencies penetrate deeper. Higher
frequencies do not penetrate to deeper
levels.
359
The vertical resolution decreases with the
distance travelled (hence depth) by the ray
because attenuation preferentially robs the
signal of the higher frequency components.
Deconvolution can improve vertical resolution
by producing a broad bandwidth with high
frequencies and a relatively compressed
wavelet. 360
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361
As an example, if we introduce the centre
frequency fc of the energy pulse (disturbance), we
obtain the following simple relationship between
the dominant wavelength (λ), the wave velocity (V)
and the centre frequency (fc):
𝜆 ≅ 𝑉
𝑓𝑐
The typical values for the dominant
wavelength are then (a) λ = 40 m at shallow depth (upper 300–500 m
depth), where V = 2,000 m/s and f = 50 Hz,
(b) λ = 100 m at intermediate depths (about 3,500
m), where V = 3,500 m/s and f = 35 Hz
(c) and (c) λ = 250 m at depths (about 5,000 m),
where V = 5,000 m/s and f = 20 Hz. 362
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For thicknesses smaller than λ/4 we rely
on the amplitude to judge the bed
thickness.
For thicknesses larger than λ/4 we can
use the waveform.
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Seismic Interpretation
Seismic data are studied by geoscientists to
interpret the composition, fluid content, extent
and geometry of rocks in the subsurface.
Interpretation of seismic data will be based on
an integrated use of seismic inlines,
crosslines, time slices and horizon attributes.
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The seismic sections or images represent
slices through the geological model, which
can be input to advanced workstations where
the actual interpretation can take place.
365
Seismic data can be used in many ways such
as regional mapping, prospect mapping,
reservoir delineation, seismic modelling,
direct hydrocarbon detection and the
monitoring of producing reservoirs.
Based on the seismic interpretation, one will
decide if an area is a possible prospect for
hydrocarbon (oil or gas).
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If the answer is positive, an exploration well
will be drilled.
The ultimate goal will be the drilling of
production wells if the target area proves to
be a commercial reservoir.
Seismic data contain a mixture of signal and
noise.
367
It is therefore crucial to understand the
signature of the noise, whether it is
systematic or random, dipping or flat-lying,
planar or non-planar.
It is also necessary to investigate the origin of
the noise.
The challenge of seismic interpretation is then
to fully utilize all the information contained in
the seismic data. 368
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Systematic noise can be related to acquisition
procedures, processing artefacts, water-layer
multiples, faults, complex stratigraphy and
shallow gas.
Random noise includes natural noise (e.g.
wind and wave motion), incoherent seismic
interface and imperfect static corrections.
369
Without a sound understanding of these
factors as well as knowledge of the
limitation of seismic resolution, there is a
danger of misinterpreting noise as real
features.
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END