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The Time for Depth Imaging
Many of today’s exploration targets cannot be seen with conventional seismicimaging methods. Operators now are getting a clearer picture—even of the most
complex features—using prestack depth imaging. The more accurate results
reduce exploration risk and help delineate reserves.
Uwe Albertin
Jerry Kapoor
Richard Randall
Mart Smith
Houston, Texas, USA
Gillian Brown
Chris Soufleris
Phil Whitfield
Gatwick, England
Fiona Dewey
Wintershall Noordzee BV
The Hague, The Netherlands
Jim Farnsworth
BP
Houston, Texas
Gary Grubitz
BHP Billiton
Houston, Texas
Mark Kemme
Clyde Petroleum Exploratie BV
The Hague, The Netherlands
For help in preparation of this article, thanks to Ian Anstey,
Robert Bloor, George Jamieson, Patrick Ng and Erick Zubay,
Houston, Texas, USA; and Mark Egan, Gatwick, England.
1. Fold is the number of source-receiver pairs whose signals constitute a trace.
2
Throughout the last century, interpreters
accepted seismic images processed and displayed in the time domain. In many of today’s
active exploration areas, especially where structures are complex and seismic velocities vary
abruptly because of faulting or salt intrusion,
time-domain processing can give misleading
results; only depth imaging can define the true
position and correct geometry of subsurface features. In some cases, the difference between
depth and time images can make or break a
prospect: structures gain or lose closure, targets
move by hundreds of feet or meters, and reserves
can be added or lost. The difference can be an
expensive dry hole instead of a discovery.
This article explains how depth imaging has
emerged as the technique of choice for processing seismic data to image complex subsurface
features. Case studies show how oil and gas
companies operating in the Gulf of Mexico, North
Sea and onshore US are improving their drilling
success rates with depth imaging.
Events in Seismic History
Over the course of the 20th Century, notable milestones marked advances in seismic prospecting
methods. Although many new technologies have
taken about 10 years to mature from first introduction to accepted practice, each one has ultimately created new exploration opportunities.
Starting in the 1920s, single-fold analog
traces were introduced to detect dipping subsurface layers (next page).1 In the 1930s, this innovative technique was the key to discoveries around
salt domes, and became standard practice. The
1950s saw the arrival of multiple-fold seismic
data achieved by common depth-point (CDP)
stacking, which markedly improved signal-tonoise ratio. In the 1960s, digital data acquisition
and processing were introduced, replacing earlier
analog and optical methods. This created major
improvements in the quality of seismic data and
led to many new discoveries worldwide.
Throughout the 1970s, digital data and twodimensional (2D) surveys became common.
Together, these technologies opened up the
North Sea and other challenging areas. Timebased processing was standard, but 2D poststack
depth migration was introduced and tested. The
first small three-dimensional (3D) surveys
were acquired over developed fields to improve
reservoir delineation. In the 1980s, 3D surveys
gained wide acceptance in the industry and
transformed the exploration business. Trace
attributes and bright spots were used as seismic
indicators of hydrocarbons.
By the 1990s, seismic contractors routinely
acquired 3D exploration data over vast portions of
the world’s continental shelves. Three-dimensional poststack time migration evolved to
become standard practice, reducing finding costs
to their current levels; and 3D prestack depth
migration was introduced for particular cases.
Today, many operators won’t drill without 3D data
over their prospects, and in the areas of highest
risk, won’t drill without prestack depth imaging.
Currently, depth imaging is creating exploration opportunities in regions that were considered too risky just a few years ago. This
technique is helping explorationists generate
new subsalt prospects in the deepwater Gulf of
Mexico and discover new reserves in the North
Sea that were unimaginable using conventional
time-processed data.
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51381schD1R1 04/24/2002 09:06 PM Page 3
1920
Single-fold
analog shooting
1930
1940
1950
Multiple-fold common
depth-point stacking
Discoveries
around
salt domes
Common depth point
(CDP)
Offset
2
3
Digital data
acquisition
and processing
4
Hyperbolic
curve
Two-way time
1
+ Stacking
velocity
1960
2D surveys
1970
3D surveys
1980
Subsalt prestack
depth migration
1990
Multiclient 3D prestack depth imaging
2000
> Chronology of selected advances in seismic methods.
Spring 2002
3
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Introduction to Imaging
Imaging is the process that brings seismic reflections into focus at their proper positions. It consists of two main elements—stacking and
migration. Stacking increases signal-to-noise
ratio by summing records obtained from several
seismic shots reflecting at the same point. The
simplest case to illustrate is a flat layer of uniform
velocity overlying the reflector. Traces from several source-receiver pairs, centered on the reflection point but separated by different distances, or
offsets, are gathered together (below). The variation in arrival time with offset is called moveout.
The shape of the arrival times plotted against offset defines a hyperbola. Before the gather can be
stacked, the traces must be shifted to align
arrivals. The offset-versus-time parameter that
describes the shifts defines the stacking velocity
of that layer. The result of stacking is a single
trace—the enhanced version of a signal that
would have been recorded for a normalincidence, or zero-offset, shot at the midpoint of
the source-receiver pairs.
The second ingredient in imaging—migration—uses a velocity model to redistribute
reflected seismic energy from its assumed position at the midpoint to its true position (next page,
top left). One of the several classes of migration
may be chosen depending on the complexities of
the target and overburden structures. Simple
structures and smoothly varying velocities can be
imaged with simple migration routines that may
fail to work on complex structures with rapidly
varying velocities.2
Migration is accomplished by various solutions to the wave equation that describe the propagation of elastic waves through rock. Migration
algorithms often take the name of their inventor,
such as Kirchhoff, or the type of mathematical
solution, such as finite-difference.3 Each type of
migration has advantages and drawbacks.
Migration can be performed in two
domains—time or depth—and either before or
after stacking. Certain imaging problems can be
solved with time migration, but the most complex
problems need depth migration. In time migration, the velocity model, also called the velocity
field, may vary smoothly (next page, top right).
The velocity model has two-way traveltime as its
vertical axis. Seismic velocity increases with
traveltime, and horizontal variations are gradual.
Since these constraints are valid in most sedimentary basins, time migration is often applicable, and is used in most parts of the world.
In depth migration, the velocity model may
have strong contrasts horizontally or vertically.
Depth migration is chosen when steeply dipping
faults, folds or intrusions juxtapose layers with
vastly different elastic properties. Depth migration needs an accurate velocity model in depth
and is a more labor-intensive operation.
Migration applied after stacking—poststack—is much faster than migration before
stacking, because stacking reduces by an order
of magnitude the number of traces that must be
processed. For poststack migration to be successful, the assumptions made in stacking must
be well-founded: the amplitude of the stacked
trace must represent that of the normal-incidence trace and reflected arrivals must be
approximately hyperbolic. These suppositions are
valid only when variations in lithology and fluid
content over the span of the gathered traces can
be ignored and when the structure is simple. Any
other conditions call for prestack migration.
Performed before stacking, prestack migration can handle the most complex structures and
velocity fields. In the past, the main constraints
on prestack migration were the computing power
needed and the time and skill required to construct the velocity model within a reasonable
turnaround time. Advances in computing technology have eased these constraints.
Creation of the velocity model still remains a
time-consuming process and depends on the
local geology. In areas where the geology is layered, or well-defined fault blocks exist, velocitymodel building for depth migration proceeds on a
Offset 4
Offset 3
Offset 2
Offset 1
Zero offset
Two-way time
1
Offset
2
3
Offset
4
1
2
3
4
Hyperbolic
curve
With
stacking
velocity
+
+
+
=
Common depth point (CDP)
Corrected CDP gather
Stacked
CDP
> Stacking traces from a common depth-point (CDP) gather. Traces from several source-receiver pairs at different offsets from the common depth point are
collected to form a CDP gather (left). Gathered traces are displayed in coordinates of time versus offset (center), in which the shape of reflection arrivals
from a flat reflector defines a hyperbola. The arrivals are shifted into alignment using a stacking velocity, or offset-versus-time relationship, and stacked
(right), or summed, to create a single trace with higher signal-to-noise ratio than that of any of the original traces.
4
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51381schD1R1.p5.ps 04/24/2002 07:44 PM Page 5
Migrated
trace
Source
Midpoint
trace
Receiver
Simple velocities + simple structure = poststack
time migration
Simple velocities + complex structure = prestack
time migration
Complex velocities + simple structure = poststack
depth migration
Complex velocities + complex structure = prestack
depth migration
Original
data
Salt
Increasing velocity
MIG
> Migration of reflected seismic energy. For this
simplified two-dimensional (2D) example, migration repositions the data trace from its recorded
position at the source-receiver midpoint to its
true position (MIG) using a velocity model. In 3D
cases, reflections may be redistributed to and
from positions outside the plane containing the
sources and receivers.
> Simple and complex velocity models and structures treated by four migration classes—time, depth,
prestack and poststack. Poststack models are on the left and prestack models are on the right. Models
appropriate for time-based migration are on the top, and depth-based models are on the bottom. For
time migration, the velocity model may have smooth variations, but only with depth, and only monotonically—always increasing with depth, never decreasing. Depth migration is required for more complex
velocity models, such as those with lateral variation or decreases of velocity with depth. Poststack
migration works with models of low structural complexity. Prestack migration can handle even the
most complex models.
layer-by-layer basis. An initial model is constructed from the most suitable data available,
then updated through several iterations of
prestack depth migration for each layer. The initial velocity model can be constructed using all
the available information, such as stacking velocities, time-interpreted horizons and velocities
from borehole data. Stacking and borehole velocities can show representative velocity trends,
which should be taken into account in the model.
When the structure is not too complex, the
entire velocity model can be updated and constructed layer by layer rather quickly. In more
complex cases, the velocity analyst defines
blocks or other volumes bounded by faults or
intrusions, then builds the model for each block
layer by layer.
In areas where geology is more continuous,
such as in the Gulf of Mexico, a continuous sediment-velocity model is defined using either
tomography or local velocity updating. Once the
sediment velocity is defined, salt bodies are
inserted after their positions are determined
using several iterations of depth migration.
In areas where anisotropy is an important factor, significant differences may appear between
borehole-based velocities, which typically represent velocities in the vertical direction, and
stacking velocities, which represent horizontal
velocities. These differences must be accounted
for by introducing anisotropy into the velocity
model. More discussion on depth migration
in anisotropic velocity fields appears later in
this article.
Collaboration between operator and service
company can facilitate successful velocity model
building. Operating company interpreters often
have better knowledge and expectations of the
subsurface, and can help interpret layer boundaries and salt features for the velocity model.
Service company staff, with their knowledge of
processing, incorporate these interpretations to
help create the model for depth migration.
Spring 2002
Depth Imaging in the Gulf of Mexico
The Gulf of Mexico has been the most publicized
proving-ground for prestack depth-migration
techniques.4 Salt bodies in various stages of
intrusion and uplift have created complex structures that both motivate and challenge explorationists. Salt geometries can vary enormously,
and are critical in terms of hydrocarbon migration
and trapping. Salt massifs can appear to be
rooted to a deeper salt layer or completely
detached and floating. The high contrast in seismic velocity between the salt at 14,500 to
15,200 ft/sec [about 4500 m/s] and sediments,
often at less than half that value, causes problems for time-migration approaches.
2. For more on prestack, poststack, time and depth migration: Farmer P, Gray S, Whitmore D, Hodgkiss G, Pieprzak A,
Ratcliff D and Whitcombe D: “Structural Imaging: Toward
a Sharper Subsurface View,” Oilfield Review 5, no. 1
(January 1993): 28–41.
3. Kirchhoff migration is based on Kirchhoff’s solution to the
wave equation.
4. Huang S, Ghose S, Sengupta M and Moldoveanu N:
“Improvements in 3-D AVO Analysis and Structural
Imaging of Dipping Salt-Flank Events Using AmplitudePreserving Prestack Depth Migration,” The Leading Edge
20, no. 12 (December 2001): 1328, 1330, 1332, 1334.
Donihoo K, Bernitsas N, Dai N, Martin G and Shope D:
“Is Depth Imaging a Commodity? The Impact of New
Imaging Technologies and Web-Based Collaboration,”
The Leading Edge 20, no. 5 (May 2001): 486, 488, 490, 492,
494, 496, 543.
Albertin U, Woodward M, Kapoor J, Chang W, Charles S,
Nichols D, Kitchenside P and Mao W: “Depth Imaging
Examples and Methodology in the Gulf of Mexico,” The
Leading Edge 20, no. 5 (May 2001): 498, 500, 502, 504, 506,
508, 510, 512–513.
5
51381schD1R1 04/24/2002 09:20 PM Page 6
Technological advances have brought
increases in production ever since hydrocarbons
were discovered in the Gulf of Mexico (below).
Early on, drilling technologies were key to
exploration success. More recently, seismicimaging techniques have helped sustain the
discovery rate.
In the late 1980s, operators started testing 2D
prestack depth migration as a way to improve
images of layers truncating against the flanks of
salt domes. In 1993, partners Phillips Petroleum,
Anadarko and Amoco were the first to announce
a subsalt discovery in the Gulf of Mexico with the
Mahogany prospect. They attributed this success
to prestack depth imaging.5
Today, companies continue to explore below
salt, and many are also looking in deeper water.
Several of the recent large discoveries in the Gulf
of Mexico are in deep water—deeper than
5000 ft [1500 m] (bottom left). In these areas, the
cost of drilling a well can exceed $50 million, but
the rewards can be great. The Crazy Horse discovery by BP contains estimated reserves of 1 billion barrels of oil equivalent (BOE). BHP Billiton
has reported 200 to 450 million BOE recoverable
reserves at Mad Dog and 400 to 800 million BOE
at Atlantis.
Cumulative discoveries
Barges
50
Jackups
Semisubmersibles
Production, billion BOE
40
Hydrocarbon indicators
3D seismic, deepwater
30
Deepwater, subsalt
20
10
0
1940
1950
1960
1970
1980
1990
2000
2010
Year
> Impact of technological breakthroughs on Gulf of Mexico success rates.
Starting with the early achievements in drilling capability, and continuing
through modern seismic methods, each advancement has yielded an identifiable increase in production.
Reducing risk is a key concern for deepwater
operators, and prestack depth imaging is one of
the technologies that help reduce risk. Depth
imaging was performed to reduce drilling risk
over many Gulf of Mexico discoveries such as
Crazy Horse, Llano, Mad Dog, Atlantis and others. For BHP Billiton, prestack depth imaging is
the critical technology for reducing risk and
appraisal at Atlantis, Mad Dog and the rest of
the Western Atwater Fold Belt trend that encompasses these discoveries. BP credits prestack
depth-imaging breakthroughs with helping to
describe the elements of the Crazy Horse
prospect and to position the discovery well.6
Imaging a seismic volume containing a salt
body is different from traditional processing, in
which data tapes are sent off for processing and
a finished product is returned to the interpreter
for examination. Subsalt imaging requires several iterations of migration and interpretation
(below). Many of these steps are based on
proprietary processing techniques, allowing
contractors to differentiate their results from
those of other contractors.
The first step after general prestack processing is to build the initial velocity model for the
layers overlying the salt. In the Gulf of Mexico,
sediments typically are sand-shale sequences
without strong velocity contrasts between layers.
The initial velocity model can often be derived
from stacking velocities to produce a smooth
interval-velocity field describing the sediments.
Prestack processing
Lake Charles
Analyze velocities
Houston
Edit distorted velocities
New Orleans
Build depth-and spacevariant gradients
3D poststack
migrate
on fine grid
B
G
D
C
A
H
E
Discovery wells
Older wells
Salt
A
B
C
D
E
F
G
H
Crazy Horse
Mars
Crazy Horse North
Ursa
Atlantis
Mad Dog
Mahogany
Llano
> Recent deepwater Gulf of Mexico discoveries, with many occurring near salt bodies. Large recent
discoveries have estimated reserves in the hundreds of millions of barrels. Several of these have been
discovered with the help of prestack depth imaging.
6
Update
velocity
model
Analyze
migration
velocities
Define salt
geometry
F
GULF OF MEXICO
3D prestack
migrate
on fine grid
3D prestack
migrate on
sparse grid or
depth window
3D prestack
depth migrate
entire volume
for final image
> Data-processing flow for subsalt prestack
depth migration. The process is a complex interplay of several steps. Building the velocity model
itself requires iterations in prestack depth migration to define the velocity of each layer and the
geometric boundaries of each layer.
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Poststack Time Imaging
Prestack Depth Imaging
> Comparison of time migration and depth migration in the Green Canyon area of the Gulf of Mexico. The time migration (left) shows two
salt bodies, each uplifting and doming the overlying sediments. The salt body on the left has a domed top and a flat base, and
creates a shadow beneath. The one on the right seems to be in two pieces: a floating salt pillow has detached from the dome below.
Prestack depth imaging (right) retains the general shape of the body on the left, although its base is now sloping. However, the depth imaging reveals layers beneath, which were shadowed in the time migration. The salt intrusion on the right has a completely different shape
when depth migrated. Instead of rising in an anticlinal structure, sediments are truncated along the flanks of an hourglass-shaped salt body.
The second step takes this velocity model and
updates it. Velocity analysts have several ways
of revising models, most belonging to a category
of methods called tomographic inversion.
Tomography uses traveltime information derived
from seismic data to refine velocity models.
Classical reflection tomography uses the difference between predicted and observed reflection
traveltimes.7 Ray tracing predicts the arrival
times of reflections on common depth-point
gathers at control points. On each gather, the
shape of the actual arrival time of the shallowest
reflector is compared with the predicted arrival
times, and the velocity that best flattens the
actual arrival times is used to update the model.
This step is time-consuming and requires experts
in both processing and interpretation to create a
model that satisfies the data at all control points.
The next step applies depth migration using
the updated velocity model. The migrated traces
are gathered again and arrival flatness checked. If
the preliminary time migration shows the top of
Spring 2002
salt to be smooth, or structurally simple, the velocities of the overburden can be used in a poststack
depth migration to obtain an image of the top of
salt. If the top of salt is rough, or structurally complex, prestack depth migration should be applied.
After the top of salt is imaged and interpreted, the velocity model is updated by filling
the volume below the salt top with a uniform salt
velocity. With this new velocity model, the
volume is again prestack depth migrated, and the
bottom of salt comes into focus.
Applying the correct migration technique can
bring surprising changes to the seismic image.
Interpretation of one time-migrated section from
the Green Canyon area of the Gulf of Mexico
shows two anticlinal structures created by salt
intrusion (above). The salt body on the left has a
domed top and a flat base, and creates a shadow
beneath, obscuring deeper reflections. The salt
intrusion on the right appears to have pierced
through the top of the anticline and left a dome
of salt behind.
With prestack depth imaging, the picture
changes completely. The salt body on the left is
still domed, but is thicker, with a sloping base.
Layers can now be seen below the salt. The salt
feature on the right looks entirely different.
Instead of two disconnected salt bodies, the new
image shows a single hourglass-shaped body
with clearly delineated sides and base. Instead
of rising in an anticlinal structure, sediments are
truncated along the flanks of the salt hourglass.
5. Westcott ME, Leach MC, Wyatt KD, Valasek PA and
Branham KL: “Mahogany: Seismic Technology Leading to
the First Economic Subsalt Field,” Expanded Abstracts,
65th SEG International Meeting and Exposition, Houston,
Texas, USA (October 8-13, 1995): 1161–1164.
For more on subsalt exploration: Farmer P, Miller D,
Pieprzak A, Rutledge J and Woods R: “Exploring the
Subsalt,” Oilfield Review 8, no. 1 (Spring 1996): 50–64.
6. Pfau GE, Chen RL, Ray AK and Kapoor SJ: “Seeing
Through the Fog: Improving the Seismic Image at Crazy
Horse,” presented at the AAPG Annual Meeting, March
10–13, 2002, Houston, Texas, USA.
Yielding CA, Yilmaz BY, Rainey DI, Pfau GE, Boyce RL,
Wendt WA, Judson MH, Peacock SG, Duppenbecker SD,
Ray AK and Hollingsworth R: “The History of a New Play:
Crazy Horse Discovery, Deepwater Gulf of Mexico,” presented at the AAPG Annual Meeting, March 10–13, 2002,
Houston, Texas, USA.
7. Other types of tomography can use refracted or transmitted waves.
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Poststack Time Imaging
Prestack Depth Imaging
> Time and depth migrations of three large salt
features. Poststack time migration (top) reveals
the tops of the salt intrusions. However, this
method leaves an unclear image of the salt bases;
they might be interpreted at the lower limit of the
zone that has little reflection or no character.
Interpretation of the prestack depth image (bottom)
suggests that the two left-most salt bodies are
not floating, but connected to roots that extend to
40,000 ft [12,200 m].
8
In another portion of the Green Canyon area,
the tops of three large salt pillows are fairly
clearly imaged by poststack time migration, but
the bases are not (left). One reasonable interpretation would place the bases of the salt at the
lower limit of the reflectionless area of the seismic image. There is some indication of layering
between the salt bodies at great depth.
Prestack depth migration reveals a surprisingly different image. The two large salt bodies
on the left now are connected to roots that
plunge to about 40,000 ft [12,200 m]. The root of
the middle salt feature is about 3 miles [5 km]
across. The vast volume between the two salt
roots is filled with dipping sediments that are
truncated against the roots.
One of the achievements of the WesternGeco
approach to prestack depth migration is the ability to image dips “beyond 90 degrees,” that is,
layers that are overturned or below salt overhangs. Migration methods trace rays through the
velocity model to a reflector, then follow the rays
back to the surface. The rays bend at each interface according to the angle of incidence and the
velocity contrast between layers.
Usually it is sufficient to consider only those
rays that bounce from the top side of a reflector.
However, in some cases, reflections of interest
can also occur from the bottom side—as in the
case of reflections from underneath salt overhangs. Properly accounting for these reflections
in migration requires the ray tracing to be done
over long distances. By taking advantage of
these rays, called turning rays, the undersides of
salt overhangs can be imaged clearly.
In another example from the Gulf of Mexico,
poststack time migration is able to image the
northern flank of a salt intrusion, but the southern
side is lost in a shadow (next page, bottom). The
time migration did not use turning rays. Prestack
depth imaging, incorporating turning-ray energy
as well as energy passing through the salt, illuminated the steeply dipping layers and the overhanging salt on the south flank of the intrusion.
Imaging in the North Sea
The Gulf of Mexico is not the only place where
operators are using depth imaging. Many parts of
the North Sea can claim structural complexity
rivaling that of Gulf of Mexico salt intrusions. In
addition to tectonically active salt, North Sea
basins exhibit expanses of chalk and largescale faulting above and below the salt. The
smoothly varying sand-shale sequences overlying the Gulf of Mexico salt bodies may seem
simple by comparison.
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Wintershall Noordzee BV began exploring in
Blocks K10 and K13 in the Broad Fourteens
basin of the Dutch sector of the North Sea in
1968 (right). Since then, more than 30 wells have
been drilled, delineating seven producing fields.
As these fields enter their final years of production, new technology is being deployed to identify additional reserves and extend the producing
life of this mature area.8
The area is structurally complex, with largescale normal faulting, overthrusts and salt intrusions. Large velocity contrasts around the salt
domes and across major faults cause traditional
seismic-imaging methods to produce poor pictures of structures and faults. Deep channels cut
into the Tertiary sequence that overlies a thick
chalk unit of variable thickness and velocity. The
main reservoirs are even deeper—the Main
Buntsandstein and Rotliegend sandstones. Highamplitude carbonate rafts can be mistakenly
interpreted as Top Rotliegend reflectors, resulting in false targets.
6°
54°
< The K10 and K13 blocks in the
Broad Fourteens basin, southern
North Sea. Wintershall Noordzee
BV has achieved a clearer seismic picture of their reservoirs in
this gas-producing region by
applying prestack depth imaging.
K10
K13
53°
NORTH
SEA
Ijmuiden
The
Netherlands
52°
8. Dewey F, Whitfield P and King M: “Technology Offers
New Insight in a Mature Area—A 3D PreSDM Case
Study from the Dutch N Sea,” Transactions of the EAGE
63rd Conference and Technical Exhibition, Amsterdam,
The Netherlands, June 11–15, 2001, paper A-04.
3D Poststack Time Imaging
3D Prestack Depth Imaging
South
North
South
North
Turning-ray reflection
Constant velocity
Varying velocity
Salt
Spring 2002
> Imaging under a Gulf of Mexico salt overhang with time and depth migration.
Poststack time migration (left) manages to image the north side of a salt diapir, but
the southern side is lost in a shadow created by an overhang. By including turning
rays (inset) and rays that pass through the salt, prestack depth migration (right)
images the steeply dipping layers and the overhang on the south side of the intrusion.
9
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An early depth-migration project in 1996 over
a 50-km2 [19.3-sq. mile] portion of the two blocks
showed some imaging improvements, but used
simplistic velocity-modeling techniques, and so
the results lacked the detail to improve fine-scale
structural imaging.
Enhanced imaging and increased resolution
were required to improve understanding of the
geological history of the area and identify
remaining traps. In 1999, Wintershall and
WesternGeco carried out a high-fidelity 3D
prestack depth migration of both blocks. The new
project incorporated data from three 3D surveys
covering an area of 880 km2 [340 sq. miles].
The success of every depth-migration project
depends on the accuracy of the velocity model.
To create an accurate model, a meticulous
approach was developed using a combination
of state-of-the-art tools and more conventional techniques.
Iterative layer-stripping formed the backbone
of the analysis. For each layer, a combination of
tomography and multivelocity depth scans was
Depth Imaging 1996
used to derive the model. To verify the velocities
of each layer, a dense grid of 3D prestack depth
migrations was generated. The depth stacks
were used to update the structural model, and
the gathers were examined to monitor and
update the velocities. This allowed both the
structural and velocity variations to be continuously and consistently tracked and checked for
each of the 11 layers in the model as it was built.
The new images showed significant improvements over the previous time- and depthmigrated data sets, especially in the tectonically
complex areas. For example, results from the
1996 project using a simple velocity model gave
an unclear image of the top of the Rotliegend
sandstone reservoir under a complex fault
(below). The new depth migration with the
detailed velocity model gave a much clearer
image of this potential reservoir interval.
In a second example, a feature that is difficult
to interpret in the time-migrated section becomes
identifiable as a “pop-up” of the Rotliegend
formation in the properly depth-migrated image
(next page, top). What appears to be an isolated
discontinuous reflection in time migration can be
seen in the depth-migrated section to be an
abrupt pop-up with near-vertical sides. The complex structure overlying the pop-up, combined
with its steeply dipping flanks, makes this problem difficult to solve with time migration, but
completely tractable with depth migration.
The project’s success relied on close cooperation between processing geophysicists, interpreters and researchers from both Wintershall
and WesternGeco, along with the optimization of
all available technologies. The additional effort
put into deriving the detailed velocity model
has shown the benefits of aiming for the 90%
correct solution rather than making do with a
70% result, while satisfying tight operational
time and cost constraints.
A complete reinterpretation of the area is
under way and will be combined with a basinmodeling study to improve definition of the producing fields and identify the presence of any
untested reservoir compartments.
Depth Imaging 1999
Rotliegend sandstone
> Comparison of depth migrations with simple and complex velocity models. Depth migration for an earlier
project used a simple velocity model, and produced an unclear image of the top of the Rotliegend sandstone under a complex fault (left). Depth migration with the newer, more detailed velocity model gives a
much clearer image of the potential reservoir interval (right).
10
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Time Imaging
Depth Imaging
> Complex Rotliegend structure revealed by depth imaging. A disrupted interval in the time-migrated
section (left) is difficult to interpret. In the depth-migrated image (right), this becomes identifiable as a
pop-up of the Rotliegend formation.
Q4
Q5
in
as
Coastline
Q8
sB
Q7
en
rte
ou
dF
oa
Br
Building Reserves through Depth Imaging
In another North Sea development, operators
used depth imaging to improve delineation of
reserves and increase reserve estimates.
Clyde Petroleum and partners recently
deployed state-of-the-art depth imaging in a
renewed effort to explore, appraise and extend
existing gas discoveries in Blocks Q4 and Q8 of
the Dutch North Sea (right). The recently discovered Q4 gas fields lie in a complex inversion zone
(once low-lying, now upthrust along reactivated
faults) bounded by a series of major NW-SE-striking faults. The new fields are on a trend with two
producing gas fields in the Q8 block. Before Clyde
Petroleum began operating the block, seven dry
wells had been drilled on shallower prospects.
The tectonic history had produced highly
deformed structures, and early conventional seismic processing gave suboptimal results. After the
drilling of the first successful exploration well,
a new program called for a comprehensive
3D prestack depth migration, followed by complete reinterpretation.9
54°
No inversion
Low reservoir risk
Basin margin terrace
Low reservoir risk
Inverted terrace
Moderate reservoir risk
Deeply inverted terrace
High reservoir risk
Basin axis, maximum
burial and inversion
Very high reservoir risk
Gas
53°
NORTH
SEA
52°
Q4 Q5
Q7 Q8
Ijmuiden
The
Netherlands
9. Kemme M, Brown G, VanBuuren N and Greenwood M:
“Depth Imaging Unfolds Complex Geology and Impacts
Reserves—The Q4 Story,” Transactions of the EAGE 63rd
Conference and Technical Exhibition, Amsterdam, The
Netherlands, June 11–15, 2001, paper P071.
> Gas reservoirs (red) operated by Clyde Petroleum Exploratie BV in the Q4
and Q8 blocks of the Dutch sector of the North Sea. Color-coding shows
regions with different tectonic histories.
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51381schD1R1.p12.ps 04/24/2002 07:46 PM Page 12
The complex history of normal, reverse and
lateral movements had placed the basin fill on
top of the reservoir block. Time-migrated images
of these steeply dipping structures were
limited in quality, and fault positioning was
questionable. Image ray-tracing and boreholeseismic results indicated that lateral fault mispositioning could be as much as 300 m [1000 ft],
depending on the overburden velocity model.
The prestack depth-migration project was initiated to better understand the structural framework and correctly position faults, with the
expectation that the results could have a strong
impact on the size of the structure and the planning of the development wells.
Four 3D data sets, approximately 400 km2
[154 sq. miles] of seismic data, were input to the
prestack depth migration. Each data set was processed through a similar, conventional preprocessing flow with emphasis on noise reduction
and multiple attenuation. Although the individual
data sets had different orientations, no resampling was required. Phase matching and amplitude compensation were applied to each survey
to match all surveys to a common base.10 Each
data set was depth migrated individually and
merged after migration, but before stack.
Due to the complex nature of the geology,
major velocity contrasts were expected.
Therefore, the traditional top-down, layer-stripping approach to velocity modeling was not considered adequate.
The structural model indicated that the 3D
velocity model could be divided into five separate
NW-SE-trending velocity blocks, with up to six
velocity layers below the area-wide Tertiary layer
on top (below). Within each block, velocity was
determined layer by layer, but the inclination of
the fault blocks dictated the order in which the
velocity model should be built—from southwest
to northeast.
Typically, stacking velocities would be used to
derive initial interval velocities for a particular
layer. However, due to low confidence in the
stacking velocities in this complex area, a model
based on well data was used. A range of velocity
maps based on the starting velocity was used to
output a 3D prestack depth-migrated grid of inlines over the target area.11 A final velocity map
for the target layer was then derived by interactively picking on the depth-migrated common
image-point gathers.12 Finally, a 500-m [1640-ft]
grid of 3D prestack depth-migrated in-lines and
crosslines was generated. These lines were used
In-line
3600
0
3800
4000
4200
4400
4600
4800
5000
5200
5400
5600
5800
6000
6200
SW
6400
NE
500
1000
1500
Zone
1
Zone 2
Zone 3
Zone 4
Zone 5
Depth, m
2000
2500
3000
3500
Tertiary
4000
Chalk
Lower Cretaceous
4500
Upper Jurassic
Lower Jurassic
5000
Triassic
Permian
to interpret the target horizon in depth, for inclusion in the velocity model.
This procedure was iterated layer by layer
within each fault block until the base horizon had
been inserted into the velocity model. Then, the
final velocity model was used to generate a full
3D prestack depth-migrated volume on a 25-m by
25-m [82-ft by 82-ft] grid. Residual moveout
correction was performed, the data were
stacked, and appropriate poststack processing
was applied.
The new depth data showed notable improvements over the time-migrated data, and
increased the interpreter’s understanding of the
structural model and confidence in the fault positioning (next page, top). The prestack depth
migration enabled targeting of the second exploration well near a major fault without risk of
encountering a reduced reservoir section, and
revealed that the position of the fault was farther
to the west, increasing the reservoir volume. This
improved imaging also had a significant impact
on the interpretation of the eastern bounding
fault. Because of poor imaging of the traditionally migrated seismic data, this fault had been
imaged as an easterly dipping normal fault.
However, the superior resolution of the new
images shows that the reservoir-bounding fault
is actually a westerly dipping reverse fault,
adding an extra fault block of gas-bearing reservoir.
The updated structural interpretation resulted
in an increase of almost 50% in gas initially in
place (next page, bottom). Additionally, better
seismic definition decreased uncertainty in the
reserves estimate and allowed for detailed interpretation of faults within the reservoir, reducing
the risk of leaving compartments undrained.
The robust methodology followed throughout
the project allowed the construction of an accurate velocity model for this complex area. The
subsequent 3D prestack depth-migrated volume
provided a significant improvement in the quality
and confidence of the seismic image. As a result
of the improved seismic quality, not only did the
apparent volume of the structure increase significantly, but also the better data quality resulted
in a much more detailed interpretation of
intrareservoir faults. This allowed for more reliable planning for three to five future development wells. The Q4-A field came on-stream in
December 2000, only 21⁄2 years after the first
exploration well was drilled.
Pre-Permian flood
> Velocity model for the Q4 reservoir blocks. Steeply dipping faults laterally juxtapose contrasting velocities and place high-velocity layers on top of lower velocity layers. The red box
delineates the area of interest.
12
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Time Imaging 1996
Prestack Depth Imaging 1999
GWC
> Comparison of interpreted time- and depth-migrated seismic lines over the reservoir in the Q4 block. Interpretation of the time-migrated image (left)
shows a block of reservoir bounded on the west by a thrust fault (yellow), and on the east by an easterly dipping normal fault (black). Interpretation of the
depth-migrated image (right) changes the picture. The new interpretation raises the thrust fault (white line), adding volume to the reservoir on the west. The
normal fault on the east is no longer considered a bounding fault. The reevaluated reservoir boundary is a westerly dipping reverse fault (red), previously
not recognized. The approximate gas-water contact (GWC) is indicated.
Prestack Depth Migration on Land
Many onshore prospects have the same imaging
problems encountered offshore, but until
recently, land-based seismic campaigns were
less successful at imaging complex structures.
However, depth-imaging projects on land are
now showing the same level of improvement
over time-based methods as their Gulf of Mexico
and North Sea counterparts.
Exploration in south Texas is notorious for
complications caused by complex structures overlying potential reservoirs. Faults create shadows
that obscure the shape and disposition of deeper
layers. Imaging targets in “fault shadows” is a
challenge with time-migration techniques, but
depth migration gives much clearer pictures and
more geologically reasonable features.
10. Phase and amplitude of seismic traces are affected by
the timing and power characteristics of the acquisition
source and by processing, which may vary from one
survey to another. Combining data sets from different
surveys requires phase and amplitude of all data sets
to be matched.
11. An in-line is a seismic line within a 3D survey parallel to
the direction of towed-streamer acquisition. A crossline
is a seismic line perpendicular to the direction of
survey acquisition.
12. A common image-point (CIP) gather is the set of all
traces that reflect at the subsurface point being imaged.
A CIP gather is created by searching over all possible
rays in the acquisition geometry and collecting those
that reflect at the point of interest.
Spring 2002
0
feet
6560
0
meters
2000
< Increase in gas initially in place resulting from
interpretation of depth-migrated seismic data.
Interpretation of depth-migrated seismic data
moved faults and added roughly 50% to the gas
reserves in this reservoir. Old fault interpretations
are shown in black; new fault interpretations are
shown in blue. The increase in reservoir size is
shown in pink.
Q4-A
Time-migrationbased field outline
Gained area
New prestack
depth-migrationbased faults
Old time-migrationbased faults
Old time-migrationbased field outline
Q4-B
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Time Imaging
Depth Imaging
10,000
2.2
Depth, ft
Time, msec
2.4
12,000
2.6
14,000
2.8
> A time-migrated (left) and depth-migrated section (right) from south Texas. In the time-migrated image, velocity complexities cause a false anticline
immediately to the left of the fault plane denoted by arrows. Also, the reflections on the left side of the fault appear to be broken and have less continuity than reflections on the right side of the fault. The depth-migrated section shows gently dipping and continuous structures in the fault shadow.
The false structural high seen in the time-migrated data has become smoother, and reflection continuity is improved.
One example of benefits gained through
prestack depth migration is from a regional,
100-sq. mile [256-km2] WesternGeco multiclient
survey in south Texas. A conventional timemigrated image across a large normal fault
shows some of the typical problems seen in this
area (above). A pronounced false anticline, or
“pull-up” of the seismic reflections, appears
beneath the fault on this section. Also, the reflections beneath the fault appear to be broken and
have less continuity than reflections on the right
side of the fault, particularly along the interpreted horizon.
These imaging problems are caused by the
juxtaposition of rocks of different velocities on
opposite sides of the fault (next page, top left).
The layers on the upthrown, or left, side of the
fault, although older than the layers on the right,
are overpressured, and so have lower seismic
velocities. The lateral velocity contrasts cause
seismic rays to bend as they cross the fault.
Ray bending distorts the seismic image in the
time domain.
The depth-migrated section shows a different
picture. The reflections in this section dip less
steeply on the left side of the fault than do the
corresponding reflections in the time-migrated
section. The false structural high has diminished,
and reflection continuity is improved. An interpretation of the depth-migrated section produces
a different depth and shape to the layers beneath
the fault, potentially yielding a different exploration target.
14
Depth migration has been successful in other
parts of the world where land-seismic results are
known to be problematic. WesternGeco has
performed 3D depth-imaging projects in many of
the world’s oil-producing countries, including
Venezuela, Bolivia, Argentina, Germany, Russia,
Kazakhstan, Egypt, Libya, Kuwait, the United Arab
Emirates, Syria, China, Australia and Nigeria.
Reaching Full Potential
Today’s methods are more accurate than earlier
ones, but the full potential of depth imaging has
not yet been reached. The limitations to overcome center around creation of the velocity
model, deciding what type of migration produces
the best images, and the time required for completion of depth-imaging projects.
Several factors can complicate the modelbuilding process. One that has received recent
attention is anisotropy. Much of the subsurface is
anisotropic in some physical property, such as
elastic properties, permeability or electromagnetic properties.13 The simplest form of elastic
anisotropy is called transverse isotropy (TI). This
occurs when the seismic velocity has one value
parallel to bedding and a different value perpendicular, or transverse, to bedding. In typical cases
of TI anisotropy, velocity parallel to bedding is
greater than transverse velocity.
Usually, seismic data processing ignores
anisotropy. However, the effects of strong
anisotropy can produce a suboptimal data set if
not taken into consideration. Ignoring anisotropy
can result in vertically and horizontally mispositioned structures.
The effects of anisotropy can be seen as a
nonhyperbolic shape in the arrivals from a flat
reflector (next page, top right). Traces from long
offsets arrive earlier than predicted from a model
with isotropic velocity because they have traveled longer in the faster, horizontal direction.
Anisotropy can be incorporated into a prestack
depth-migration velocity model, with conspicuous
results (next page, bottom).14 Prestack depth
imaging with an isotropic velocity model produces
a fairly clear image of the sediment layers
uptilted by a North Sea salt intrusion. However,
the layers in the shadow of the salt overhang are
not as clear as they could be, and the gently dipping layers on the lower flank of the salt show a
mis-tie with formation depths measured in a well.
Prestack depth imaging with a model that
includes 10% anisotropy in the overburden
produces a clearer image and one that ties with
well data.
Identifying which imaging problems require
anisotropic velocity models and which ones are
simply displaying velocity heterogeneity will
become easier as more areas are tested.
Processing experts debate which type of
migration is best for imaging extremely complex
volumes. Prestack Kirchhoff migration has been
particularly effective in salt and subsalt imaging
in the Gulf of Mexico, but sometimes it has difficulty imaging features under rugose salt bodies.
Because this algorithm uses ray tracing, small
errors in the shape or location of the salt interface can cause migration artifacts.
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10,736
10,000
Offset
12,000
Two-way time
12,464
Depth, ft
Interval velocity, ft/sec
11,000
11,696
13,000
13,232
Anisotropic
Isotropic
> Comparison of arrival times versus offset for an
isotropic and an anisotropic layer. If the layer
were isotropic, the arrivals would define the red
curve, and if the layer were anisotropic, the
arrivals would define the black curve.
14,000
14,000
> Depth-migration velocity model for south Texas survey, showing the fault
interpreted on seismic data.
In such areas, finite-difference prestack
migration can provide effective imaging. This
approach uses wavefield extrapolation instead of
ray tracing, and can produce better images.15
Efficiency gains and the use of larger computer systems have shortened project cycle times.
But service companies continue to be pressured
to depth-image larger areas and to do it quickly.
Oil companies and contractors should share the
responsibility to define realistic time frames.
Depth migration brings a viable solution to
complex imaging problems. After seeing the difference between depth-imaged data and conventional time-imaged sections, operators often
change their interpretations and plans, whether
for prospect exploration or reservoir develop-
Isotropic Depth Imaging
ment. Furthermore, seeing the difference in one
seismic section forces the realization that all
other data acquired in complex areas probably
deserve a second look. Some operators now
insist on depth imaging before drilling in deep
water or other high-risk areas.
Other operators are reluctant to apply depth
imaging because of the costs involved in acquiring and processing target-specific data. To them,
it appears that this technology is only for the
super-major operators. However, it is possible to
use depth imaging in a cost-effective manner on
multiclient projects to improve understanding of
regional geological petroleum systems. The
WesternGeco approach to applying depth imaging on speculative regional-scale data sets is
helping make the technology available to operating companies of all sizes.
As more operators gain experience with the
technique, the process will become more efficient. Experts predict that in the future, essentially all seismic data will be depth imaged. —LS
13. Armstrong P, Ireson D, Chmela B, Dodds K, Esmersoy C,
Hornby B, Sayers C, Schoenberg M, Leaney S and Lynn H:
“The Promise of Elastic Anisotropy,” Oilfield Review 6,
no. 4 (October 1994): 36–47.
14. Bloor R, Whitfield P and Fisk K: “Anisotropic Prestack
Depth Migration and Model Building,” Transactions of
the EAGE 63rd Conference and Technical Exhibition,
Amsterdam, The Netherlands, June 11–15, 2001, paper A-01.
15. Albertin U, Watts D, Chang W, Kapoor SJ, Stork C,
Kitchenside P and Yingst D: “Improving Near-Salt-Flank
Imaging with Shot-Profile Wavefield-Extrapolation
Migration in the Gulf of Mexico,” to be presented at the
EAGE 64th Conference and Technical Exhibition,
Florence, Italy, May 27–30, 2002.
Anisotropic Depth Imaging
Well top
Well top
> Prestack depth imaging in the North Sea with an isotropic (left) and an anisotropic (right) velocity model. Including 10% anisotropy in the velocity of the
overburden helps to produce a clearer image of the layers that are truncated against a salt intrusion and produces a better depth match to well data.
Spring 2002
15