Introduction
Seismic
stratigraphic techniques have evolved considerably since the
underlying principals were first discussed over twenty years ago
(e.g. Vail et al., 1977).
Seismic
stratigraphy methodology has
proven quite successful in
identifying
plays on a regional basis,
maturing leads to drillable prospect status, and exploiting field
hydrocarbon resources (Greenlee, 1992; Duval et al., 1992).
In this document, we discuss some guidelines for conducting a
seismic
stratigraphic investigation and include guidelines for data
preparation. This type of work should lay the foundation for later
sequence stratigraphy (Van Wagoner et al. 1988),
seismic
attribute
analysis (2D or 3D), volume interpretation (3D), and forward
seismic
and geological modeling.
However, these recommendations are meant to form a working approach
rather than a series of subjective directions. Methodologies must
always be adjusted to fit the data from a given area. Further
reading is listed to support the information provided here.
Data
Preparation
Figures 1-4, Table 1
As regional
seismic
stratigraphic
analysis often proceeds detailed 3D
seismic
mapping, it is assumed
that the first stages of analysis involve 2D
seismic
or merged 2D/3D
datasets with relatively long lines (>1-5 km line length). Preparing
these data for analysis usually require the following six steps:
1. Plot regional base maps showing
shot points and posted wells. These should be at an appropriate
scale and size for later use in mapping. Bathymetry is also useful
to have in offshore datasets. Base maps serve several functions,
including places to mark
seismic
facies notations, areas of
interest, anomalies to further investigate, checking line ties, etc.
2. From the base map, select key 2D or 3D
seismic
lines, emphasizing
regional or sub-regional dip lines with important well-ties. Avoid,
if possible, areas where wells must be extrapolated considerable
distances (> 1 km) along strike or down structural dip to tie
seismic
lines. Select lines to allow loop ties in a progressively
widening grid, avoiding severe tectonic deformation zones, if
possible. Identify possible "hero" lines, often dip lines, which tie
key wells and show clear stratigraphic trends and are good "show
lines". Sometimes the best choices for hero lines emerge later on,
following initial interpretation.
3. Plot paper copies of selected
regional
seismic
lines at a reduced scale. We highly recommend
using wiggle trace paper
sections
at the first stages of an
investigation as this is usually the best way to see complex
stratal relationships and terminations over long distances (Table
1). On the
seismic
workstation, such stratal observations are often obscured or
masked by a high degree of vertical exaggeration. Long regional
lines often require panning large back and forth on a workstation,
whereas paper
sections
allow uninterrupted visual scanning for key
terminations. In addition, wiggle trace
sections
, which allow for
marking of often subtle stratal terminations, do not display well on
the workstation screen.
Figures 1
and 2 illustrate the results of plotting a small portion of a
seismic
workstation view with wiggle trace and variable density
displays at regional scales (1:50,000). Notice how onlap of the
seismic
reflections is more clearly displayed on the wiggle trace
section (Figure 1) than the variable
density plot (Figure 2).
This also holds true for the
prospect or field scale at 1:25,000 (Figures
3 and 4). Variable density
sections
(as on
seismic
workstations)
are more difficult to interpret stratigraphically than wiggle trace
(variable area)
sections
because stratal terminations tend to be
“smoothed out” by this type of display. In addition, the subtle
brightening of adjacent reflections at a stratal termination, due in
part to tuning effects, is often masked.
If there is a desire
to make the troughs stand out more, one can color these with a light
shade of gray for greater contrast.
4. Avoid data which has trace-mixing
that obscures stratal terminations. Avoid narrow AGC (automatic gain
control) windows which tend to reduce differences in relative
amplitude between stratigraphic units. Use migrated
sections
where
possible, but this is not a requirement (sometimes non-migrated data
is better for
seismic
stratigraphic interpretation).
5. Prepare well data for
seismic
ties. We recommend that well ties be made paper to paper in the
early phase of a
seismic
stratigraphy study. One reason is that
it is normal practice to tie synthetics to wiggle trace
sections
.
Wiggle trace
sections
are preferred over variable density for other
reasons as discussed above. Be sure to include the gamma ray or
other critical logs. Time-based logs should be at the same scale as
the
seismic
section (10 or 20 cm/sec). Time-based logs can also be
used in various log correlation program cross-
sections
, for example.
Seismic
displays at 10 cm/sec offer an obvious advantage over 5
cm/sec while 20 cm/sec are good for detailed, prospect or field
scale. Biostratigraphic and lithostratigraphic tops should be input
into the synthetic seismogram program; this saves time by not having
to do it by hand later. Check-shot surveys or VSP's (vertical
seismic
profiles), when available, should be used in generation of
the synthetic. If these are not available, two other options can be
employed:
1)
Identifying
a key reflection
(typically a limestone/shale contact) with high acoustic impedance
contrast and hanging the synthetic on it.
2) In some cases with limited or older velocity data, there is some
utility in constructing a time-depth (T-Z) curve for the region
using other checkshot surveyed wells. This empirical approach often
yields a polynomial equation to predict depths from
seismic
TW time.
Most check-shot data can be fit with a second-order polynomial (y =
2x +b) where y is depth and x is TW time. Be careful of areas where
overpressuring causes variations in T/Z plots.
Keep in mind that some bulk
time-shifting can still be required to match the
seismic
(generally
less than 100 ms).
6. We highly recommend
construction of a well-tie template for illustrating the
relationship between seismically-defined surfaces, time-based well
log, biostratigraphic calibration, and global chronostratigraphy.
This template can be prepared once horizons have been identified and
well-ties are made with general agreement among interpreters. It
also useful for project presentations as it provides a clear
documentation of the stratigraphic age model used.
Seismic
Stratigraphy
Interpretation
Once data has been properly
prepared,
seismic
stratigraphic interpretation begins, typically
using colored pencils for different horizons. While the speed and
ease of work-station correlation is far greater than hand
interpretation, there always is a basic need to develop regional
‘hero lines” to illustrate key stratigraphic relationships. Having
a hero line or series of hero lines is a useful way of reducing
variations among interpreters, as these become the starting point
for any new
seismic
workstation project.
Pencil-interpreted paper
sections
allow for some changes in correlation, especially when looping
across other
sections
occurs. However, at some point the lead
interpreter declares that the key horizons are “looped” and only
limited significant subsequent alterations are allowed.
Figures
5 and 6
Interpretation
Steps
1. Identify areas of major
structural deformation and data artifacts (sideswipe and
diffraction) on the
seismic
sections
. One should have a sense of the
general tectonic style, presence of structural decollements, or key
deformational events from previous reports or the literature. Do not
blindly adhere to conventional wisdom if
seismic
data dictates
otherwise.
2. In structurally complex terrains,
it may be useful to do an initial correlation of a few surfaces and
then cut, flatten, and tape together
sections
to see key tectonic
relationships. A few half-scale
seismic
displays at or near 1:1
vertical exaggeration may also be helpful if structure is not
clear-cut. Interpret faults (with normal pencil) where obvious
offsets can be identified. Be sure to differentiate between migrated
and unmigrated
seismic
sections
where
identifying
faults. Also be
careful of pitfalls due to over- or undermigration of
seismic
data.
In some cases, complete restoration of a series of
seismic
sections
is necessary to fully understand the original
depositional
patterns
and stratigraphic organization (e.g. Gulf of Mexico slope salt
province).
3. Review key lines (especially dip
lines) to identify major (second-order) shelf margins, if present in
the region. Indicate by triangle or circular symbol. Get a feel for
the scale of the
seismic
sequences
(2nd order, 3rd
order, etc.), and pre-, syn-, and post-orogenic
sequences
. Identify
major angular truncations by bold top truncation arrows (in red).
4. Begin to identify major lapouts
with red pencil marks. Do this BEFORE making
seismic
correlations.
Stratal terminations are listed in order of importance and
illustrated in Figure 5:
-angular truncation
obvious erosional termination of
dipping reflections up against a reflection of lesser dip)
-onlap
(stratal termination up against a reflection of greater dip)
-downlap (stratal termination
down against a reflection of lesser dip)
-toplap (termination of
successively younger reflections against a reflection,
passing downdip to
prograding clinoforms (in some cases))
5. Connect onlap and angular
truncation terminations as a candidate sequence boundary. Connect
the downlaps as a candidate maximum flooding surface (MFS), keeping
in mind the caveats listed above. Toplaps remain unconnected
temporarily. Be careful when interpreting onlaps and downlaps in
strike
sections
or in tectonically rotated and growth fault
sections
. Please note that listric fault planes or glide planes
can be misinterpreted as onlaps.
6. Keep in mind that the most
important
seismic
stratigraphic surface is the sequence
boundary (SB), which is most easily identified by stratal
onlap, especially in shelfal portions of the
sequences
. It will
be most continuous throughout the area of interpretation. Both
toplap and downlap surfaces can change reflection position for
various reasons. For example, the toplap surface can drop below the
sequence boundary in a lowstand systems tract (LST) or can be part
of rising, shingled lowstand wedges (LSW's). The downlap surface
can also rise as basinward progradation occurs in both highstand
systems tract (HST) or LST. Toplap and downlap surfaces may step up
stratigraphic section as well. Loop typing will help identify the
regional downlap surface associated with a condensed section and
maximum flooding. Also keep in mind that
sections
oblique or
parallel to
depositional
dip will not yield classical downlap
progradational direction.
7. Look in basinal positions for
double downlap as an indicator of LST-basin-floor thick or (in
slope) slope thicks or channels. The sequence boundary on the basin
floor is by definition a correlative conformity and may not
necessarily show much associated erosion. However, in confined
deepwater channel systems this surface will tie with significant
erosion, collapse, or failure.
8. Look in shelf-margin position for LSW’s, which will often be
indicated by detached, shingled toplap-downlap couplets. These
should be colored separately from other systems tracts. The LSWpc (lowstand
wedge prograding complex) is often identified where smaller
clinoforms downlap the sequence boundary.
9. Carry through the correlations
made by connecting stratal terminations marks. Loop-tie the sequence
boundary (SB) and maximum flooding surface (MFS) in a progressively
widening set of line ties, in order to gain confidence in the
correlations. At least five or more surfaces need to be tied in
multiple loops before correlations are considered more than
“candidate” SB or MFS.
10. A good practice in
seismic
stratigraphic correlation is to drag your pencil on the black peak
or at the zero crossing just above the peak. One reason for this is
the ease in erasing the pencil line should a miss-tie occur.
However, if the impedance characteristics of sand and shale are
well established and the surface type and position are known, it is
more important to correlate the surface in the appropriate peak or
trough. Knowing whether
seismic
data is quadrature or zero phase is
also important, as these will control surface position to some
degree.
11. A general rule of thumb when
correlating, either with pencil or with workstation cursor, is to
stay low as possible without crossing reflections when correlating a
SB in the basin. Conversely, it is wise to stay high when
correlating on the shelf, without crossing reflections. A MFS
surface may rise in the basin (due to sedimentation prior to downlap).
As mentioned, low toplap is common and can be confused with a
sequence boundary but may be an internal surface in the LSWpc.
This is why it is so important to understand the type of surface
that is being correlated and the basin position of the area being
interpreted.
Integration
with Other Data Types
After key stratigraphic surfaces
have been identified and correlated, the next set of steps are
undertaken to integrate any available well data.
1. Integrate with
logs, cores, and biostratigraphic information.
--Biostratigraphic data: It
is important when using biostratigraphic data to look for
concentration/dilution cycles. In general terms, concentration
cycles, zones where large numbers of microfauna and flora are
condensed over short intervals, are often associated with maximum
flooding surfaces (MFS). By contrast, dilution cycles are often
associated with sequence boundaries. Keep in mind the potential for
depressed fauna and displaced (transported) fauna. Be careful where
data comes from wells with thin stratigraphic
sections
on structural
or paleogeographic highs. Sequence boundaries sometimes are
associated with high numbers of reworked older fauna, usually due to
updip or local erosion of older strata. Biofacies and paleoclimatic
inferences from paleontologic data should also be considered in this
integration because latitude variations in faunal and floral content
can also occur (Armentrout et al., 1991).
--Logs:
Stacking patterns, log motifs, and lithology are keys to the
intermediate scale of correlation which should support the
seismic
correlations. In fact, the best log correlations are
established when the
seismic
data is used as a guide to extending
stratigraphic surfaces from well to well. While
seismic
data
does not often capture the high-resolution stratigraphic
correlations possible in a log cross-section, it usually displays
gross geometries (e.g., dipping clinoforms) which should be followed
in log correlation. For example, experience has shown that
clinoforming parasequences or stacked sequence architectures can be
missed in log correlation if not first identified on
seismic
.
Stacking patterns seen on logs (and
outcrops
sections
) are often indicative of key stratigraphic
surfaces. For example, the change from retrogradational to
progradational stacking often is associated with a maximum flooding
surface, which can be checked against both
seismic
and
biostratigraphic data.
Log motif interpretation of systems
tracts is particularly well defined (e.g., Mitchum et al., 1994).
Stacking patterns, log curve shape, vertical trends in sand content,
and relationship to over- and underlying surfaces are keys to
identifying
the systems tracts. However, integration with
seismic
and other data is critical to validating these interpretations.
--Lithologic relationships
can help identify systems tracts: 1) in mixed siliciclastic/carbonate
systems, HST's are often dominated by carbonate rocks while
sandstones are often found in the LSW’s and TST (e.g., Guadalupian
strata of the Permian Basin; Sarg and Lehman, 1986). 2) In some
LST’s, the carbonates can dominate the LSWpc, but sandstones onlap
as basin-floor thicks. In-situ coals often reside in the HST’s
and/or TST’s while transported terrestrial organic matter and coal
spar (clasts) occur in the LST’s (e.g., North Sea Tertiary;
Armentrout et al., 1993). Juxtaposition of contrasting lithologies
and unlike facies types often signals a major basinward facies
shifts (SB) or major transgressive event (parasequence set boundary
(PSSB)).
--Cores:
The best evidence for identification and validation of important
stratigraphic surfaces often comes from cores. Sequence boundaries
can be associated with basal lags or paleosols (on the interfluves
of incised valley-fills (ivf’s)). Parasequence boundaries (PSB’s)
can be associated with burrowed, wave rippled surfaces. The
Glossifungites trace fossil assemblage is a firm or hard ground
indicator and this can be associated with PSSB or PSB’s.
At this point, it is often helpful
to take some of the sequence boundaries and maximum flood surfaces
from the sequence stratigraphically interpreted
seismic
sections
and
post these on log cross-
sections
. The result is
seismic
-consistent
well log correlation (as described in item #1). Such
sections
are
good ways to illustrate how
seismic
geometries point to sand type,
thickness, and distribution (shelf vs. basin, for example). Of
critical importance is the need to pick a surface that is a good
(flat) datum. The surface chosen should have been close to
horizontal at the time of deposition. This is not easy, considering
that virtually every surface has some stratigraphic dip. If the
surface elevations are close, then perhaps hanging on subsea depth
might work. Maximum flooding surfaces often work well in basinal
settings while shelf top sequence boundaries in shelfal domains are
favored. Flooding or transgressive surfaces work well locally, but
are clearly diachronous at the regional scale.
Once surfaces are established, it is relatively easy to compute
statistics like net/gross, etc., used in map overlays described
below. Multiple datums may be necessary, particularly with long
regional cross-
sections
, but many computer cross-section programs
have some difficulty with this.
2.
Color systems tracts: green = TST, Blue=HST, terra cotta (brown)
= LST. Coloring lightly with pencil is particularly good for
seismic
sections
which become the hero line and are used in the workroom as
a “rosetta” stone for the group.
3. Use biostratigraphic information
to date the sequence
boundaries and MFS. It is very important to establish sequence
boundaries ages at the narrowest lacuna (smallest hiatus). This is
particularly critical for major angular or structural unconformities
(e.g., Middle Miocene Unconformity (MMU) of SE Asia, Base Cretaceous
in Northern Viking Graben). Figure 6
illustrates how the MMU of Malaysia was definitively dated at 15.5
ma (Haq et al., 1987 terminology) by using biostratigraphic age
dates where the gap between the oldest strata above and the youngest
strata below the MMU was identified.
4.
Compare to global chronostratigraphy: a) assign age and b)
appropriate surface nomenclature. We recommend use of terminology
following the European Basins Cenozoic and Mesozoic
Chronostratigraphy (de Graciansky et al., 1998). This system and
associated charts are gaining industry acceptance as a global
reference standard. The surface is named using the European Basins
nomenclature; e.g.:
Tor1_sb Tortonian-1 sequence boundary (3rd
order)
Tor1_200fs Tortonian-1 200 flooding surface
(4th order)
MioX1_100mfs
Miocene 4th order surface, unknown stage
or
depositional
sequence
Seismic
Mapping Based Upon Sequence Stratigraphy
Once a preliminary stratigraphic
framework has been established, mapping based upon sequence and
seismic
stratigraphic interpretation is done to provide
documentation to
seismic
observations. These also serve to help
identify prospective petroleum plays, fairways for prospect
generation, and evaluating acreage and development well
opportunities. While amplitude-based mapping approaches are evolving
rapidly with the computing and workstation technology, the
traditional approaches discussed below still offer value to the
interpreter.
Figures 7-13, Tables 2 and
3
![](thumbs/07.jpg) |
Figure
7. A-B-C seismic facies technique of Ramsayer (1979). |
![](thumbs/08.jpg) |
Figure
8. Using Ramsayer (1979) seismic facies code system on a
workstation (seisfac horizons). Note color added to sequences
for clarity. Shelf margin positions shown by pink triangles.
Seismic section modified from Armentrout et al. (1993). |
![](thumbs/09.jpg) |
Figure
9. Workstation seismic map using Ramsayer (1979) seismic facies
code system. |
![](thumbs/10.jpg) |
Figure
10. Importance of mapping seismic facis by systems tract
(modified from Armentrout et al., 1993). |
![](thumbs/11.jpg) |
Figure
11. Interpretation of reservoir sand bodies from seismic facies
(modified from Armentrout et al., 1996). |
![](thumbs/12.jpg) |
Figure
12. Examples of deepwater seismic facies types based on
amplitude-associated and –dependent characteristics. Acronyms
and sources: LAP’s: lateral accretion packages, from Abreu et
al. (2003); HAC: high amplitude continuous, from Posamentier
(2002a); HASC: high amplitude semi-continuous, from Kolla et al.
(2001); LASC: low amplitude semi-continuous and Gullwing, from
Brami et al. (2000); LAC: low amplitude continuous, Choatic,
HASC-mounded, LASC-mounded, from McGilvery and Cook (2003). |
![](thumbs/13.jpg) |
Figure
13. Example of trace classification approach to seismic facies
mapping, South Timbalier-26 Field, Gulf of Mexico. Left image is
uninterpreted; right shows interpretation of delta environments.
Inset shows trace classification used in seismic facies mapping.
Modified from Abreu et al. (2002). |
![](thumbs/t02.jpg) |
Table 2.
Seismic reflection characteristics of seismically definable sand
bodies. |
![](thumbs/t03.jpg) |
Table 3.
Seismic facies mapping codes (modified from Ramsayer, 1979). |
Seismic
Facies Mapping
Seismic
facies mapping involves
qualitative to quantitative analysis of
seismic
character to infer
areal trends in either lithology, paleoenvironment, or both (e.g.,
outer shelf shales). Generally,
seismic
character is analyzed from
two standpoints: external form (geometry) and internal character.
Internal form includes the continuity, frequency, and amplitude of
seismic
reflections (Table 2). Many of
these parameters relate to lithology or the processes responsible
for deposition and thus are often used to interpret sand body origin
and reservoir type. Others relate to the acoustic impedance
contrast, tuning, etc., and thus
seismic
resolution plays a role in
their discernible patterns of occurrence. Bed or stratal continuity
is assumed to exceed the Fresnel zone width for a given
seismic
frequency.
Workstation- and some PC-based
seismic
analysis programs can provide quantitative measures of
frequency, continuity, and amplitude to support mapping.
Seismic
amplitude mapping is particularly well advanced in industry today.
Seismic
volume interpretation allows
seismic
amplitudes “polygons”
and 3D objects to be viewed in proper spatial and temporal
relationships.
External Form and Internal
Geometry-A-B-C Mapping
Seismic
facies mapping was definitively explained in Ramsayer’s
(1979), based upon 2D
seismic
sections
interpreted prior to the
advent of
seismic
workstations. This is referred to as the “A-B-C”
mapping approach, as observations are made upon the upper boundary
(A), the lower boundary (B), and internal reflection character (C).
For example, a prograding
seismic
package with oblique clinoforms,
toplap at its upper surface and downlap at its base would be noted
as Top-Dwn/Ob (Figure 7).
The three categories (A-B-C) of Ramsayer's (1979)
seismic
facies
codes each include five types, thus providing 15 different
variations for a given
seismic
interval of interest (Table
3). Although the technique was developed largely from 2D
seismic
data, it can be used on modern 2D and 3D
sections
displayed on
conventional industry workstations.
Figures 8 and 9
illustrate use of the Ramsayer (1979) A-B-C
seismic
facies mapping
approach on a series of 2D
sections
interpreted using a workstation.
In the Paleogene section of the North Sea, five or six
depositional
sequences
were recognized, correlated, and mapped (Armentrout et
al., 1993). The shelf margin break is denoted by a pink triangle.
Thick lowstand wedge prograding complexes (orange) formed in the
shelf margin position, seaward of the highstand systems tracts and
thin embedded transgressive systems tracts (blue).
Four
seismic
facies were identified in sequence 30, as indicated in
Figure 8. The workstation method is to
assign each different
seismic
facies to different parts of the
vertical time or depth scale (seisfac horizon in
Figure 8). For example, the
cross-section position of
seismic
facies C-C/P is assigned to time
horizon 300ms, while C-Dn/Si is indicated along time 400ms, Tp-Dn/Ob
along time 500ms, and On-C/P to 600ms, all above the interval of
interest to avoid overlapping the key interpretation interval below
700ms. The horizontal distribution or geometry of the various
seismic
facies is seen on the corresponding
seismic
map view (Figure
9). It is also important to indicate areas of bad data or poor
seismic
reflectivity.
When placed in a map view, the interpreter infers patterns of
similar
seismic
character as well as trends going from
up-
depositional
dip to downdip (Figure 9).
The intent is to make objective observations of
seismic
character
and then interpret the meaning of these
seismic
facies in a regional
and local
depositional
context.
In addition to A-B-C
seismic
facies maps, other observations include
marking stratal terminations (e.g., arrows indicating downlap and
toplap), isochron thickness, or
depositional
limits of the
individual lobes and interpreted progradation direction or sediment
input orientation. Different
seismic
facies sometimes correspond to
different progradational lobes. It is useful to indicate paleoshelf
margin location by symbols, such as triangles or filled circles.
Rather than mapping the entire sequence, it is recommended that
individual maps be constructed for each
depositional
systems tract (Figure
10). These often have different
seismic
facies character and map
geometry. Note how the interpreted highstand systems tract (HST) is
characterized by offsetting lobes, which define the highstand shelf
phase deltas, which in aggregate prograde the shelf margin from the
maximum flooding position. The transgressive systems tract (TST) has
a different map pattern than the overlying highstand systems tract.
Few stratal terminations can be identified. The mapped
seismic
facies is located largely inboard of the shelf margin position. Only
one
seismic
facies (largely parallel continuous reflections) can be
recognized, in contrast to four facies mapped in the HST. The
lowstand systems tract (LST) is largely formed seaward of the shelf
margin position. Two distinct
seismic
facies are represented: 1) a
large mounded to parallel
seismic
facies thought to be the
basin-floor fans or thicks and 2) more lobate but areally limited
packages near the shelf margin, interpreted as
lowstand-wedge-prograding complexes (Figure
10).
Comparing these maps, one can see the variations in map pattern
through one eustatic sea level cycle (Figure
8). Stacking all the systems tracts for one cycle, by contrast,
leaves a very complicated map (Figure 10,
inset).
Seismic
facies mapping on the workstation can be done with both 3D
and 2D
seismic
, although the latter case involves some
interpretative interpolation between 2D lines (Figure
11, A). Using the map geometries and
seismic
facies
characteristics tied to well control, interpretation of the
depositional
sand bodies is made (Figure 11,
B).
Seismic
Facies with Emphasis on
Amplitude Characteristics
Since Ramsayer’s seminal paper in 1979,
seismic
facies techniques
have evolved to include additional information on internal amplitude
characteristics. Robust
seismic
facies information related to
amplitude strength (high or low), continuity, and reflection
frequency (Figure 12) can be described
in qualitative terms or quantified using various software products
and analysis techniques. This is particularly important in
deepwater paleoenvironments as amplitude often provides critical
lithologic and
depositional
facies information (e.g., channel axis
vs. margin). Of course, the key is to calibrate
seismic
facies
against available well control where possible (Garfield, 2000).
Calibrated internal and external
seismic
observations provide a
means of interpreting
depositional
systems directly from
seismic
in
areas with little or no well control.
Seismic
Facies by Trace
Classification
Recent innovations in
seismic
facies involve use of programs that
discriminate and classify
seismic
wavelet trace shape. The approach
is used within a sequence or systems tract to differentiate
seismic
facies (Figure 13). The user defines a
set of trace shapes from experience or iterative review of the data.
These are plotted in map view, using color as a means of
discriminating different facies. The map geometries often lend
themselves readily to interpretation, in similar fashion to
amplitude based maps. Once calibrated against well control, this
technique can be a powerful tool and is considerably faster than
maps created by hand.
Combining
Seismic
Facies
Maps with other Maps
Confidence in
seismic
facies mapping can be gained by combining
seismic
facies maps with other types of displays such as isochron/isochore,
etc., as explained below.
Isochron/Isochore Maps:
These maps provide more quantitative information on the gross
thickness of
sequences
or systems tracts and are particularly
powerful when combined with overlays showing net sand, net/gross
reservoir, etc. (e.g., Snedden et al., 1996). Conventional methods
for isochron (
seismic
time) or isochore (depth-converted thickness)
are employed. These thickness variations can indicate areal
differences in accommodation, particularly related to differential
subsidence. However, without some measure of net/sand or
seismic
facies, it is difficult to ascertain whether the "thicks" contain
any reservoir rock. Overlays providing reservoir statistics or
trends in nearby drilled areas allow inferences to be made about the
depositional
system (was the delta lobe nearby?). Combining this map
with the stratal termination map provides a means of interpreting
the observed map patterns. For example, an isochron or isochore
thick located downdip of a submarine canyon and shelf-break may
suggest the presence of a possible sandy submarine fan. However,
such interpretations need to be referenced against regional trends
and
seismic
amplitude maps.
Paleogeographic Maps:
Traditionally, paleogeographic maps have been based on
paleoenvironmental trends inferred from
depositional
systems
analysis. Paleogeographic maps based on sequence stratigraphic
correlations are truer representations of the paleogeography as they
are based on stratal "timelines" observed in
seismic
sections
. Paleogeographic
maps are best constructed at the systems tract level (Figure
10). Mapping at the
depositional
sequence or level tends to
average the highstand, transgressive, and lowstand systems tract
trends. There can be considerable differences between the systems
tracts, for example, differing shoreline trends at highstand and
lowstand time. These maps are most useful when: 1) there is
considerable well control (to support paleoenvironmental
interpretations); and/or 2) combined with
seismic
facies mapping.
Paleogeographic maps are
particularly useful when they represent the sum of other
seismic
maps. Combining
seismic
facies, isochron or isochore maps, and
stratal observations (lapout maps) onto one map, if not too busy,
provides an integrated basis for intepretation.
Application to Petroleum Exploration and Exploitation
Figures 14-17
The major reason for developing
seismic
stratigraphic maps is to
reduce critical risk in exploration and to extract benefit from
hydrocarbon discoveries.
Sequences
and Sequence sets are large scale
elements primarily used for global, regional, and local exploration
(Figure 14) Field and compartment scale
elements are found in parasequences, parasequence sets, and high
frequency
sequences
(Mitchum and Van Wagoner, 1991), but these are
not normally resolvable on conventional
seismic
data (Fulthorpe,
1991). Systems tracts (Figure 15) are
the link between these two scales but are often under-utilized. The
discussion below re-emphasizes systems tract as a part of the
petroleum exploration and exploitation workflow using
seismic
stratigraphy.
Highstand Systems Tract (HST)
In many hydrocarbon exploration
plays, many of the earliest discoveries are found in updip
structural traps, which tend to be dominated by reservoirs of the
HST or highstand sequence set (Figure 16;
Snedden et al., 2002). In some high accommodation basins like West
Africa or Gulf of Mexico, this scales up to the highstand sequence
set level (Figure
14). Stratigraphic traps
are less common in HSTs as strata often continue updip without
significant barriers and hence are regionally "leaky" (Figure
17). Structural closure (anticlinal or fault-type) can provide
the potential for entrapment, especially if sealed by overlying
shaly TST's.
Transgressive Systems Tract (TST)
Transgressive systems tract (TST)
and in high accommodation settings, the transgressive sequence sets
(TSS), are the most overlooked hydrocarbon-bearing component of the
sequence stratigraphic model (Posamentier, 2002b). TST's often
provide lateral and top seal for LST reservoirs in the basin, when
they are shale-prone, and for highstands on the shelf, when they
comprise 2nd-order transgressive mudrocks. They also can
contain significant source rocks facies, particularly at the
second-order (Duval et al., 1998; green strata in
Figure 14). When reservoirs are present,
they tend to be more marine than those of the HST or LST, and thus
more laterally continuous. Development of thick TST’s usually
involves high local subsidence (e.g., growth fault wedges).
Lowstand Systems Tract (LST)
The lowstand systems tract (LST;
Figure 15) and lowstand sequence sets (LSS;
Figure 14) are the most controversial
and yet often the most economically important elements of any
sequence (Posamentier et al. 1992). Much attention has been devoted
to LSTs as the greatest remaining potential in many plays lies in
deeper and
depositional
downdip areas (Figure
16), where LST/LSSs are more common than HST/HSS’s and TST/TSS's
(Snedden et al., 2002). The potential for stratigraphic entrapment
is also greater, as strata do not generally continue updip (Figure
17).
The presence of a significant
relative sealevel fall causes a major basinward shift in onlap,
particularly when shifted seaward of the offlap break. Mid-shelf
LST's can also occur (incised valley-fill of Van Wagoner et al.,
1990). A common motif on
seismic
is often toplap/downlap couplets,
with toe of clinoform debris wedges or sandstones. These are
typically sand rich, although carbonates can also form (the downdip
oolite play of the Permian basin).
The vertical succession in a LST
prograding complex is (bottom to top): downlap, progradation, toplap,
aggradation, and floodback (Figure 17).
Earlier models for deepwater settings suggested that there may be
three parts to the LST: the basin-floor systems (distributary
channel and sheet), slope channel systems (confined to weakly
confined), and the prograding complex (LSWpc; Mitchum et al., 1994).
Basin-floor systems sometimes show double downlap while the
prograding complex shows toplap/downlap lapouts. Slope systems
exhibit incision, lateral truncation of reflections, and complex
filling geometries. These can greatly impact the internal fluid
connectivity of a deepwater reservoir within the LST.
More recent work suggests that
deepwater systems are very complex arrangements reflecting shelf
margin evolution, sediment load, climate, eustacy, and other
factors. The methodologies for stratigraphic correlation,
interpretation, and mapping in these complex, hierarchical deepwater
channel systems are well defined and described in documents at these
chapters.
The lowstand systems tract
prograding complex (LSWpc) can be confused with the highstand
systems tract, as both are progradational. However, there are ways
to differentiate the two systems, which have important implications
for hydrocarbon entrapment (Figure 17).
The LSWpc typically is dip-restricted, with strata not continuing
updip vs. the more continuous HST. As a result, all other factors
being equal, the HST’s tend to have less potential for lateral
sealing than the LSWpc. Stratal terminations at the top of a HST
tend to be tangential to non-terminated, versus toplap patterns in
LSWpc's. The stacking patterns also differ, as LSWpc show early
progradational and late aggradational patterns on logs, versus HST's
with early aggradation and late progradational motifs
Key
Questions
One measure of the value of a
seismic
stratigraphic mapping effort is seen in the ability to
address and answer the following key questions:
a) Is the petroleum system
complete? Is there a critical missing element which will
fatally flaw the petroleum system and prevent discoveries in un- or
under-explored basin?
It is recommended to use the
resulting products (cross-
sections
and maps) to identify source and
seals, not just reservoir rocks. For marine source rock mapping,
recognition of the large scale, major downlaps (maximum flood) of
major continental encroachment cycles is a good starting place (for
more detail, see Duval et al., 1998).
It is also useful to relate to
worldwide eustatic charts and known source bed events. For example,
Klemme and Ulmishek (1991) determined that six stratigraphic
intervals have provided 90% of the world's discovered original
reserves of oil and gas (Silurian-9%, U. Devonian-Tournasian-8%,
Pennsylvanian/Lower Permian-8%, Upper Jurassic (25%),
Mid-Cretaceous-29%, Oligo-Miocene (12.5%)).
b) Are certain systems tracts
under- or unexplored? In a recent survey of Texas onland plays,
it was determined that nearly one-third of the plays produced from
only one systems tract, with the highstand systems tract containing
nearly 70% of the produced hydrocarbons (Snedden et al., 2002). It
is evident that in many plays, the lowstand systems tract is
underexplored
c) Can the sequence stratigraphic
model built here explain the present distribution of fields and dry
holes? Do the downdip dry-holes define a poorly developed
lowstand systems tract, or just the distal limits of the highstand
systems tract? In some basins, there is a zone of bypass between the
HST and LST, which can be misinterpreted.
d) If the lowstand system tract
play corridor can be identified, are downdip prospects located in
the major deltaic fairway or marginal to it? Even the world's
greatest basinward shift will fail to send sand into a basinal area
of interest if no updip deltaic source is present or an appropriate
conduit for sand delivery is not in proximity. It is critical to be
in the sand "fairway"!!
e) Finally, identify possible play types for prospectors:
e.g., pre-orogenic HST, if sealed by syn-orogenic shales; LST, if
detached and sealed. TST, if sealed by MFS and sourced by 2nd-order
TST shales.
This document is meant to be used as
a working guide to
seismic
stratigraphic interpretation and not to
be used as a strict set of best practices or conceptual basis for
sequence stratigraphic interpretation. It is a gross representation
of regional to lead level analysis, and is not meant to substitute
for normal prospect definition or upgrading to RTD (ready-to-drill)
status.
Much of the methodology described
here and in this volume involves interpretation on paper
sections
and handmade well-ties (paper to paper). Much of any company’s
seismic
interpretation today is done on a
seismic
workstation.
The use of paper
sections
is most useful at the early stages of a
project, as geoscientists seek to make correlations and establish
criteria for
identifying
horizons. Once a
seismic
stratigraphic
framework is established on some paper
sections
(hero lines), the
geoscientists can make better interpretations and often faster ones,
as no delays occur when multiple interpreters cannot agree on
correlations, terminology, or ages. Interpretation is then taken to
the workstation for efficient and optimized mapping.
The authors appreciate the
assistance of Kurt Johnston (EMEC) in preparing
seismic
examples for
this document. ExxonMobil is thanked for permission to publish this
document. John Armentrout provided many insights on scale,
hierarchy, and source rocks.
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