Geophysical Interpretation:
From Bits and Bytes to the Big Picture
Huw James
Mark Tellez
Houston, Texas, USA
Gabi Schaetzlein
Mexico City, Mexico
Tracy Stark
Exxon Production Research
Houston, Texas, USA
Workstations transport the seismic interpreter into a three-dimensional world, providing new ways to track and
visualize reservoir geophysical data. This article describes methods and tools that help interpreters make the most
of their time and data to create a likeness of the reservoir that can guide drilling and production decisions.
For help in preparation of this article, thanks to John
Boellstorf, Craig Jarchow, Susan Nissen and Gary Marny,
Amoco Production Company Research, Tulsa, Oklahoma, USA; Bobbie Ireland, Frank Marrone, Jorgen Rasmussen and Julie Rennie, GeoQuest, Houston, Texas,
USA; Joe Kelly and Rich Lozier, Geco-Prakla, Stavanger,
Norway; Paul Ware, Unocal, Houston, Texas; Robert
Withers, ARCO, Plano, Texas.
Charisma, CPS-3, DepthMap, GeoCube, GeoViz, IES
(Integrated Exploration System), IESX, RM (Reservoir
Modeling) and SurfaceSlice are marks of Schlumberger.
1. For a data processing review see: Boreham D,
Kingston J, Shaw P and van Zeelst J: “3D Marine Seismic Data Processing,” Oilfield Review 3 no. 1 (January 1991): 41-55.
2. SEG-Y is a digital tape format for data exchange specified by the Society of Exploration Geophysicists.
3. The IES and IESX interpretation systems store 32-,
16- or 8-bit format. The Charisma system stores 16- or
8-bit format.
July 1994
Well logs measure reservoir properties at
intervals of a few inches, providing a high
density of information mostly in the vertical
direction. But the volume of reservoir sampled by logs represents only one part in billions. Seismic data, on the other hand,
cover the overwhelming majority of reservoir volume but at lower vertical resolution.
A processed three-dimensional (3D) seismic
survey may contain a billion data points
sampling a couple of trillion m3, and some
surveys are 10 times bigger.1 The geophysical interpreter must handle this massive
amount of information quickly and produce
a clear 3D picture of the reservoir that can
guide reservoir management decisions.
In the overall seismic scheme, interpretation builds upon the preceding work of
acquisition and processing. Fast new ways
to simultaneously visualize and interpret in
three dimensions are changing how interpreters interact with geophysical data. Seismic interpretation packages band together a
collection of tools designed to simplify seismic interpretation and smooth the road from
input to output. GeoQuest’s seismic interpretation tools—Charisma, IES Integrated
Exploration System and IESX systems—offer
a variety of levels of user-friendliness and
sophistication. These packages complete the
process in roughly four steps—data loading,
interpretation, time-to-depth conversion,
and map output. This article takes a look at
how they help the geophysical interpreter
harness a seismic workstation filled with a
billion data points—and make it fun.
Getting Data in the Right Place
By the time 3D data arrive at the interpretation workstation, they have already undergone numerous quality control checks, and
are ready to be loaded. The objective in
data loading is to ensure that as much of the
available data as possible is loaded onto the
computer, and that these data points are
correctly positioned. Data loading continues
to be simplified by software advances.
Fitting all the data onto the computer has
been difficult because disk space has been
expensive. To work around the problem,
most data loading routines convert seismic
traces from SEG-Y format to a compressed
workstation format.2 This compression can
be perilous, because it reduces dynamic
range of the trace data. SEG-Y data are usually represented in 32-bit floating point format, which allows a range of +/_ 1037. Data
in 16-bit format have a range of +/_ 32,768,
while 8-bit format has a range of +/_ 128.3
Converting data from 32-bit to 8-bit reduces
computer storage requirements by a factor of
four, but also reduces dynamic range.
Reducing dynamic range may negate much
of the care and money that went into acquisition and processing of the seismic data.
Although the dynamic range of compressed
data is usually more than the human eye can
perceive, computer-driven interpretation can
23
SEG-Y trace, 32 bit
Amplitude
-10,000
-5000
0
Amplitude
5000
and the trace spacing (below ). From these
few numbers, geographic coordinates for
each of the thousands or millions of traces
can be computed.
If there are older 2D or 3D data, or offset
seismic profiles (OSPs) to be interpreted
with the currently loaded 3D survey, data
loading becomes more complicated.4 Trace
locations for each 2D line or OSP must be
accessed from separate navigation files or
from the trace headers themselves. Data of
different vintages, amplitudes and processing chains must also be reconciled. This is
not a trivial task, but is greatly eased with
today’s workstations.
Additional data that can be loaded
include well locations, well deviation surveys, log data, formation tops, stacking
velocities from seismic processing, timedepth data from well seismic surveys and
cultural or geographic data such as lease
boundaries or coastlines.
In 3D surveys, the seismic lines shot during the survey are called inline sections or
rows. Vertical slices perpendicular to these,
called crossline sections or columns, can be
generated from the inline data. In 3D land
surveys, the acquisition geometry can be
more complicated than marine surveys, but
Scaled workstation traces, 8 bit
10,000
-128
Amplitude
0
128
-128
0
128
Early
times
not loaded
Clipped
Time
Time
Time
Zone
of interest
nScaling to preserve critical information during compression from 32- to 8-bit format for
loading to a workstation. High-amplitude wiggles outside the zone of interest may saturate the amplitude scale, causing lower-amplitude wiggles to disappear (left). Highamplitude wiggles can be clipped during loading, allowing smaller-amplitude data in
the zone of interest to become visible (right). Limiting trace length ignores the large amplitudes, but this is risky (far right). Large-amplitude shallow reflections may overprint their
structure on deeper ones and lead to interpretation disaster if neglected.
24
N
Cro
Survey
azimuth
ssli
nes
es
Inlin
Lin
es
pa
g
cin
cin
g
ce
Tra
spa
Survey origin
Crossline
section
Time
be made to take advantage of 32-bit data.
Some specialists recommend that data never
be compressed, and since disk space is
becoming less expensive, that will eventually become a more widespread option.
When compression is necessary, workstations can help the interpreter do it intelligently through scaling ( above ). Scaling
ensures that data amplitudes are properly
sized so that the most important information
is preserved when trace values are converted from SEG-Y format to compressed
format. In the Charisma system, scaling
must be user-controlled and different scale
factors can be tested; this allows flexibility,
but usually requires practice. In the IES and
IESX systems, scaling is done automatically,
trace by trace. The scaling factor is stored in
the header of each trace. The factor is reapplied to the trace each time it is read from
the data base. This results in a reconstructed
32-bit seismic section, regardless of the
storage format.
Loading seismic data in the right place in
the computer involves assigning a geographic location to each trace. For 3D data
this is simpler than for 2D: inputs are the
spatial origin and orientation of the data volume, the order and spacing of the shot lines,
Time
slice
Inline
section
nLoading definition
of the 3D volume.
Charisma and IES
3D data-loading
routines require orientation information such as the
geographic coordinates of the origin
of the survey,
azimuth, order and
spacing of inlines,
and trace spacing.
In this marine seismic example, lines
that were shot during the survey are
called inline sections. Vertical slices
perpendicular to
these are called
crossline sections
and horizontal
slices cut at a constant time are
called time slices.
Oilfield Review
usually the inline direction is taken to be
along receiver lines. In both cases,
horizontal slices cut at a constant time are
called time slices.5
The way seismic data are stored by different systems affects the time required to generate new sections and display or perform
other poststack processing. In the Charisma
and IES systems, inline sections, crossline
sections and time slices are stored separately, so a single data value may be stored
up to three times. In the IESX system, every
inline trace is stored only once, decreasing
data storage volume. In such a volume there
is no need to generate crosslines because
arbitrary vertical sections may be cut in any
orientation in real time. Horizontal seismic
data are stored in a separate file.
Until recently, 3D data loading routines
were not user friendly, often requiring a
computer specialist. But new applications
are beginning to make this step more
straightforward, allowing interpreters to load
their data alone or with support over the
telephone. However, most companies still
employ dedicated data loaders, or use contract workers.
Tracking Continuities and
Discontinuities
Now we come to the real interpretation part
of the job—identifying the reservoir interval
and marking, either manually or automatically, important layer interfaces above,
within and below it. The interfaces, called
horizons, are reflections that signify boundaries between two materials of different
acoustic properties. Interpretation also
includes identifying faults, salt domes and
erosional surfaces that cut horizons.
Some interpreters first pick horizons as far
as possible horizontally on a set of vertical
sections, then outline faults. Other interpreters pick faults first, then pick horizons
up to their intersections with faults. The
choice depends on personal preference and
experience. Horizons shallower than the
reservoir should be interpreted because
they affect horizons below. Interpretation of
horizons outside the reservoir interval is
important if they correspond to regional
markers that can be picked from logs. Interpreting several horizons that bracket the target zone may also be used to enhance timeto-depth conversion and give clues to
geologic history.
July 1994
nCharisma workpanel for synthetic seismo-
grams (top) and seismic trace polarity conventions (inset). Synthetics help interpreters
understand correlations between seismic
traces and log interfaces by displaying
both on a time or depth scale. Here the first
and second tracks show a lithology column
(left) displayed with the sonic (black), density (blue) and porosity (yellow) logs. Next
come acoustic impedance (third track) and
its derivative, reflectivity, (fourth track, red).
A synthetic trace (third track from right) follows, next to the trace extracted along the
deviated well trajectory from the real seismic volume (second track from right) and a
seismic section near the well (right).
Amplitude
Negative
Positive
Maximum
Zero
crossing
Minimum
Local
minimum
Zero
Time
Knowing which horizons correspond to
the reservoir comes from previous experience in the area, such as earlier 2D seismic
lines. This is usually accomplished by tying
3D data to an existing 2D line or well. Tying
a seismic line to a well is done by comparing an expected seismic trace at the well
with real seismic data. This is achieved with
synthetic seismograms—synthetics—created
using logs that cover the target levels
(above ). To create a synthetic, the sonic and
density logs are converted to time, often by
using a check-shot survey.6 Next, the sonic
and density logs are combined to give an
acoustic impedance log—the product of
velocity and density. Then, through an oper-
4. An offset seismic profile (OSP) is similar to a vertical
seismic profile (VSP) except that the seismic source is
not vertically above the borehole receivers, but offset
at some horizontal distance, to produce a seismic section near the well.
5. Time slices were introduced in 1975. For background
see: Bone MR, Giles BF and Tegland ER: “Analysis of
Seismic Data Using Horizontal Cross-Sections,” Geophysics 48, no. 9 (September 1983): 1172-1178.
6. A check-shot survey measures the one-way seismic
travel time from a surface source to a borehole
receiver at known depth.
25
ation called convolution, a pulse trace that
mimics the seismic source is used to change
the acoustic impedance log into a synthetic
seismic trace.
Now it’s time to compare the synthetic
with the seismic data at the well. Geologic
boundaries, such as the top of the reservoir,
are identified in the original logs. The
boundaries are then correlated with the
time-converted logs, acoustic impedance
log and then the synthetic seismogram.
Waveform characteristics of the synthetic
are compared with the real seismic trace to
determine the seismic representation and
travel time to the geologic boundaries at
the well location. However, at seismic
wavelengths—50 to 300 ft [15 to 91 m]—
what appears to be one layer in the seismic
section will normally be several layers in
the logs. A main use, then, of tracking horizons in seismic data is not to distinguish
thin layers, but to provide information
about the continuity and geometry of
reflectors to guide mapping of layer properties between wells.
To track a horizon, trace characteristics
are followed horizontally across the whole
seismic survey. Common characteristics
used to track an event are the polarity or
change in polarity of the trace. At any time,
a trace will be of either negative or positive
polarity, or a zero crossing. A positive polarity reflection, or peak, indicates an increase
in acoustic impedance, while a negative
polarity reflection, or trough, indicates a
decrease in acoustic impedance.7 A zero
crossing is a point of no amplitude, usually
between a negative and positive portion of a
seismic trace. The amplitude of the peaks
and troughs is usually color coded. A wide
range of color schemes allows interpreters
to accent features to be tracked.
A horizon may be tracked in a variety of
ways. Points on the horizon may be manually picked by clicking with the mouse on a
visual display of a vertical section. If the seismic signal is sufficiently continuous, the
horizon may be tracked automatically using
a tool called an autotracker. Autotracking
26
Anticline
Conventional Slices
A
A
B
B
SurfaceSlice Slices
A
A
B
B
A
B
nConventional horizon interpretation (top) and SurfaceSlice analysis (bottom), a fast new
volume interpretation tool developed by Exxon Production Research and incorporated
into GeoQuest’s IESX system. Conventional interpretation tracks the top of a dome
through a series of vertical sections. SurfaceSlice interpretation allows interpreters to scan
the 3D-shape of the dome through horizontal slices that resemble a series of contour
maps. Interpretation can be automatically drawn onto the surface in swaths, increasing
interpretation speed and accuracy.
requires the interpreter to specify the signal
characteristics of the horizon to be tracked.
These include polarity, a range of amplitude
and a maximum time window in which to
look for such a signal. Given a few seed
points, or handpicked clues, autotrackers
can pick a horizon along a single seismic
line or through the entire data volume. In
faulted areas, autotrackers can usually be
used if seed points are picked in every fault
block. Horizons picked with autotrackers
must be quality checked manually and may
require editing by an interpreter. Still, the
time savings is huge compared to manually
picking thousands of lines.
If the horizon is difficult to follow, the
data can be manipulated using processing
applications available within most interpretation systems. The Charisma processing
toolbox, for example, includes a variety of
filters and other options to produce data that
are easier to interpret, without expensive
reprocessing. Dip filters suppress noise outside a specified dip range and highpass filters can reveal discontinuities. Other processes include deconvolution to extract an
ideal impulse response from real data, time
shifts to align traces, polarity reversals and
phase rotations to match data with different
processing histories, scaling to boost amplitudes of deep reflections, and time varying
filters to compensate for wave attenuation.
Some horizons defy reprocessing efforts,
and remain too complex to track with con-
ventional autotrackers. Three examples are:
(1) reflections that change polarity along the
horizon in response to a lateral change in
lithology or fluid content; (2) a local minimum that is positive or a local maximum
that is negative; and (3) horizons that are laterally discontinuous. SurfaceSlice volume
interpretation helps track these tricky horizons by displaying what might be thought of
as “thick” time slices (above ).8 The SurfaceSlice application was developed at
Exxon Production Research and has been
incorporated into GeoQuest’s IESX system.
The SurfaceSlice method can be thought
of as scanning the 3D cube to create a new
seismic volume that contains only samples
that meet some criteria set by the interpreter, such as local troughs with a given
amplitude range. Thick slices through the
volume are displayed in a chosen color
scheme. The slices contain only data on the
types of horizons of interest. SurfaceSlice
slices resemble a series of contour maps,
and are therefore convenient for geologists
to interpret. Slice thickness is interactively
controlled by the interpreter, and is usually
chosen to be less than the wavelength of
the reflection in order to stay on the chosen
7. These are polarity conventions by SEG standards.
8. Stark TJ: “Surface Slices: Interpretation Using Surface
Segments Instead of Line Segments,” presented at the
61st SEG Annual International Meeting and Exhibition, Houston, Texas, USA, November 10-14, 1991.
Oilfield Review
Slice 1500
Slice 1516
Slice 1532
Slice 1548
Slice 1564
Slice 1580
nA horizon (top) interpreted using the SurfaceSlice application. A series of six amplitude
SurfaceSlice slices (bottom) shows successive time cuts, each 16 msec thick, from 1500 to
1580 msec, that allow the horizon to be mapped from top to bottom. Up to 25 slices can
be viewed at a time.
horizon. Multiple windows show a series of
slices at increasing times in which the horizon can be rapidly tracked in areal swaths
rather than line by line (left ).
Once picked, either manually, by autotracking or by SurfaceSlice analysis, the
horizon serves multiple purposes. Shallow
horizons can be flattened to give a rendition
of the underlying volume at the time of their
deposition. A horizon, really a set of time
values draped on a grid of trace locations,
may be linked to a formation marker identified in well logs (below ). If the marker has
been picked in several wells, this serves as a
consistency check on the seismic interpretation. This link may be used later for timedepth conversion or for extending formation
properties away from wells (see “Integrated
Reservoir Interpretation,” page 50 ).
Faults and other discontinuities may be
picked manually with the mouse in two
ways. As in 2D interpretation, classic fault
interpretation is done on vertical sections—either inline, crossline or other sections retrieved at any desired azimuth. A
fault picked on one section can be projected onto nearby sections to give the interpreter an idea where to look for the next
fault pick. Thrust faults and high-angle structures such as salt domes require special
handling, because a given horizontal location may have multiple vertical values (next
page, left ). A new way of picking faults,
made possible by 3D workstations, allows
the interpreter to identify faults from discon-
nA seismic horizon (dashed yellow) linked to a formation marker identified in well logs
(white squares). Marker depths have been converted to time using a velocity model
obtained from a check-shot survey. Also shown are deviated wells and logs, all converted to time for display with the seismic section.
July 1994
27
a
Thrust Fault
a
Horizon
Horizon
Distance
Time
Salt Dome
Horizon
Distance
Time
nA thrust fault and a salt dome creating
multiple vertical values at the same horizontal locations. This can be accommodated by GeoQuest workstations.
tinuities in time slices, SurfaceSlice outputs,
or in the faulted horizon in plan view
(above, right ).
Another interpretation technique that
takes advantage of the 3D nature of data
storage is called attribute analysis. Every
seismic trace has characteristics, or
attributes, that can be quantified, mapped
and analyzed at the level of the horizon.
And though mapping a horizon is based
more or less on the continuity of the seismic
reflection, attributes can vary in many ways
along the horizon. Traditional trace
attributes include the amplitude of the
reflection, its polarity, phase and frequency.9
These trace attributes were introduced years
ago to highlight continuities and discontinuities in 2D seismic section. Now, with the
addition of high-speed 3D workstations,
interpreters have the freedom to explore
new types of attributes (right ). Attributes
such as the dip and azimuth of horizons can
instantly reveal discontinuities and faults
that could take weeks to interpret
manually. 10 Interpreters are also using
attributes to apply sequence stratigraphy to
3D data.11
nMapping faults. Traditionally, faults are picked (top, yellow lines) from a seismic section
and viewed on a horizon map. The Charisma system allows both section and map to be
viewed simultaneously, and also brings a new way to pick faults (yellow arrows, bottom)
in plan view—from breaks in continuity (black) in the faulted horizon.
nOne horizon, many attributes. This horizon is displayed in plan view with four of its
attributes. Similar to a structural map, two-way time to the horizon (top left) is color coded
with small (shallow) values in red grading to large (deep) values in blue. The horizon
amplitude (top right) with large negative values in green, is related to acoustic
impedance. Reflection heterogeneity (bottom left), a measure of the trace length within a
given time window, is a different measure of amplitude. Horizon dip (bottom right) gives a
detailed view of horizon structure.
28
Oilfield Review
An advantage of 3D workstations is their
speed compared to a pencil-and-paper job;
autotrackers lift some of the workload from
interpreters, letting them do more in less
time. Other advantages, such as time slices,
SurfaceSlice displays and attribute maps, are
techniques made possible because the data
reside in 3D on a workstation. But the seismic sections are still 2D representations of
3D information, and interpreters still perform quantitative interpretation in 2D.
This is changing as more interpreters use
the full 3D-visualization capabilities of new
workstations.12 The ability to see the data
volume, to zoom and change perspective,
gives interpreters new insight into the features they interpret on horizons. Proper illumination makes surfaces easier to understand. Changing the light source to a grazing
elevation can highlight subtle features such
as faults and fractures, for the same reason
that the best aerial photos of the earth’s surface are shot in early morning or late afternoon to maximize shadows. More advanced
workstations allow interpreters to illuminate
horizons with lights from different locations
and change the reflective properties of surfaces. Interpreters can spend less time figuring out what the structure is, and more time
understanding how it can affect development decisions. A rainbow-colored contour
map, once a marvel of the seismic screen,
pales next to a 3D rendering of the same
surface (right ).
Structures that appear obscure or disconnected when examined in 2D seismic views
may become clear or continuous in 3D. Or
just as importantly, features that appear connected in one perspective may be disjointed
in another. Seismic properties between two
July 1994
115.0
500
Two-way time, msec
The Reservoir Takes Shape
0
km
3
895.7
0
km
3
nA color-coded contour map of the Gulf of Mexico seafloor (top) and an IESX GeoViz view
of the same surface in 3D (bottom). The 3D GeoViz visualization conveys considerably
more information than the traditional contour map. Appropriate lighting reveals changes
in slope of the continental shelf edge—dark regions are steeper than lighter ones. The
cursor activates a report window, recording any desired location.
9. For an introduction to traditional trace attributes see:
Taner MT and Sheriff RE: “Application of Amplitude,
Frequency, and Other Attributes of Stratigraphic and
Hydrocarbon Determination,” in Payton CE (ed):
AAPG Memoir 26 Seismic Stratigraphy—Applications
to Hydrocarbon Exploration. Tulsa, Oklahoma, USA:
American Association of Petroleum Geologists (1977):
301-327.
For information on some new attributes see: Sonneland L, Barkved O, Olsen M and Snyder G: “Application of Seismic Wave Field Attributes in Reservoir
Characterization,” presented at the 59th SEG Annual
International Meeting and Exhibition, Dallas, Texas,
USA, October 29-November 2, 1989.
10. Mondt JC: “Use of Dip and Azimuth Horizon
Attributes in 3D Seismic Interpretation,” SPE Formation Evaluation 8 (December 1993): 253-257.
11. Risch DL, Donaldson BE and Taylor CK: “Seismic
Sequence Stratigraphy Technique on a 3D Workstation,” presented at the 25th Annual Offshore
Technology Conference, Houston, Texas, USA,
May 3-6, 1993.
12. Dewey AD and Boyd CN: “Methods for Transforming 3-D Visualization into a Productive Exploration
Tool,” presented at the SEG Summer Research Workshop on 3-D Seismology: Integrated Comprehension
of Large Data Volumes, Rancho Mirage, California,
USA, August 1-6, 1993.
Marrone FJ, James HE and Lupin SP: “Exploiting
Visualization Technology for Geophysical Interpretation,” presented at the SEG Summer Research Workshop on 3-D Seismology: Integrated Comprehension
of Large Data Volumes, Rancho Mirage, California,
USA, August 1-6, 1993.
29
deviated wells, either existing or proposed,
can be examined by extracting the seismic
image on the twisted plane between them
(below ). This gives reservoir planners a tool
for verifying reservoir connectivity, whether
for exploration purposes or for planning
improved recovery campaigns. Well logs,
interpreted horizons, faults and other structures can be viewed and moved, alone or
along with the seismic data (next page ).
Today, the most powerful 3D visualization
products provide real-time interaction with
the 3D image for lighting, shading, rotation
and transparency. However, interaction with
the image for creating and editing interpretation has typically been limited. For example, a feature edited in a 3D image must be
manually picked in a separate application
that displays the data in a 2D slice. This is
changing with the year-end release of the
GeoCube package within the Charisma system and the GeoViz 5.0 package within the
IESX system. Both the GeoCube and GeoViz
applications will permit direct interpretation
of horizons and faults in the 3D cube rather
than on 2D projections, making the most of
the 3D nature of the data volume.
Time-to-Depth Conversion
Once horizons and structures are interpreted in time, the next step is to convert the
interpretation to depth.13 The relationship
between time and depth is velocity, so a
velocity model is needed.14 Different workstation systems exhibit varying degrees of
sophistication in their creation of velocity
models for time-to-depth conversion. Most
systems, including GeoQuest’s RM Reservoir Modeling package and CPS-3 mapping
package, offer simple geometrical conversions based on velocity models that may
vary vertically and horizontally. These convert points from time to depth by moving
them in straight vertical lines. The Charisma
DepthMap package includes geophysical
modeling in the form of seismic ray tracing
and permits lateral translation of points to
perform time-to-depth conversion with
increasing reliability.
If more than one horizon is to be converted to depth, an average velocity to each
horizon must be estimated, or the average
velocity to the shallowest horizon and the
velocity between each horizon down to the
target horizon.
In the absence of logs or well seismic surveys, seismic stacking velocities can substitute for average vertical velocities. Stacking
velocities are derived from seismic data during processing, and used to combine seismic traces to produce data that are easier to
interpret. They contain large components of
horizontal velocity and are usually available
at 500-m to 1-km [1640 to 3280-ft] spacing
across the survey area. These data are interpolated to the same sample interval as the
seismic time horizon grid. Then the velocity
grid is multiplied by the time grid to give a
depth grid. The key limitation of stacking
velocities is their lack of accuracy, especially in regions of complex velocity or of
complex structure.
Time-depth data from a check-shot survey
give an accurate vertical velocity model, but
only at the check-shot location. In the
absence of other data, this velocity can be
used uniformly across the field to convert
the seismic times to depth. Stacking velocities can be calibrated at the well using
check-shot surveys.
A synthetic seismogram built from sonic
and density logs can provide a comparison
trace for time-to-depth conversion. Disadvantages of this technique are the limited
extent of logs—most logs do not provide
information all the way to the surface—and
the discrepancy between velocities measured at sonic frequencies and those measured at seismic frequencies. Synthetics are
most useful when calibrated with a checkshot survey, which improves the time-todepth conversion.
Velocity models and images from VSPs
are the most powerful data for converting
surface seismic times to depth. VSPs sample
velocities at more depths than check shots,
and unlike synthetic seismograms created
from sonic logs, VSPs have a frequency
content similar to that of surface seismic
waves. And above all, VSPs provide images
that can be matched directly to surface seismic sections.15
Putting It All on the Map
nA well section—a seismic section reconstructed between two deviated wells (red). This
display is sometimes called a spinnaker section after the sail of similar shape. Well sections can reduce error in planning horizontal wells and sidetracks from deviated wells,
and help correlate logs in deviated wells with seismic data. A seismic section between
any two trajectories can be extracted from the 3D volume.
30
Once data about reservoir structures are
stored, 2D and 3D map images can be generated for reservoir characterization. Surfaces may be mapped in time, or, if there is
a velocity model, in depth. Basic mapping
tools for this reside within most seismic
interpretation packages, and there are also
separate, stand-alone mapping packages
that accept seismic interpretations for map
generation.
One such package, the CPS-3 system, is
designed to provide accurate geographic
and volumetric information about the reser-
Oilfield Review
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2
8
10
9
7
12
3
11
4
5
6
nGeoViz 3D display of multiple seismic lines, horizons and wells from the Gulf of Mexico.
Blue lines are the 3D survey (1). Red lines are the 2D survey (2). Three horizons are displayed with different attributes; time horizon (3), illuminated horizon (4) and amplitude
horizon with a bright spot in yellow (5). A time slice (6) is displayed near the bottom. Also
shown are a crossline (7), inline (8), well section (9), well logs (10), markers (11) and a
fault (12).
voir. Given seismic horizons, faults and formation tops from logs, mapping programs
create surfaces that honor all data sets.
These packages can also give detailed volumetric information about the reservoir. With
these advanced mapping packages, processing steps applied in the same way to several
horizons can be automated by creating a
“macro,” a command file that repeats processes uniformly, saving time. Another
option is a running audit of all calculations,
so volumetric calculations can be verified
by operating partners. An advantage of the
CPS-3 package is the Full Fault Modeling
System, which accommodates nonvertical
faults, giving more accurate pay volume calculations in faulted reservoirs.
The End of the Beginning
After weeks or maybe months in the workstation, the seismic interpretation is ready to
move to the reservoir modeling system (see
“Integrated Reservoir Interpretation,” page
50 ), then possibly into a fluid flow simulator. But the seismic software should not be
left to gather dust until the next project.
Although seismic interpretation tools were
designed to display and interpret seismic
July 1994
data, they also solve one of the biggest
problems in reservoir characterization—
integration and visualization of all final output. Results from steps further down the
interpretation chain, such as porosity maps
or acoustic impedance sections from the
reservoir modeling package, can be loaded
back into the seismic interpretation system
for viewing and sliced into arbitrary sections
for accurate reservoir planning. No more
mental gymnastics are required to connect
squiggly lines or separate reservoir compartments in the mind.
And as the reservoir model is updated and
refined with new data, the seismic data
should be revisited.16 Analysis of pressure
data might indicate which reservoir levels
are in communication, bracketing the possible displacement on a fault that should be
reexamined in the seismic volume. A look
at production rates might turn up a fault that
was missed in the first seismic interpretation. With an interactive interpretation system the reservoir model can easily be
changed to incorporate new ways of
thinking, and can evolve throughout the
lifetime of the reservoir.
—LS
13. Most 3D seismic processing yields time-based
traces. Advanced processing called depth migration
outputs traces in depth. For more on migration techniques see: Farmer P, Gray S, Whitmore D, Hodgkiss
G, Pieprzak A, Ratcliff D and Whitcomb D: “Structural Imaging: Toward a Sharper Subsurface View,”
Oilfield Review 5, no. 1 (January 1993): 28-41.
14. For a tutorial on seismic velocities see: Amery GB:
“Basics of Seismic Velocities,” The Leading Edge 12
(November 1993): 1087-1091.
15. For a description of the technique see: Miller D and
Stewart L: “Reservoir Imaging Using VSP-Derived
Velocities: A Case Study,” 58th SEG Annual International Meeting and Exposition, Anaheim, California,
USA, October 30-November 3, 1988.
16. For an example of how seismic interpretation is
revised with input of reservoir engineering data see:
Stewart L: “Closing the Loop: How Reservoir Testing,
Production and Simulation Results Feed Back to Seismic Reprocessing and Interpretation,” presented at
the SEG Summer Research Workshop on Lithology:
Relating Elastic Properties to Lithology at all Scales,
St. Louis, Missouri, USA, July 28-August 1, 1991.
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