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Seismic Stratigraphy-A Primer on Methodology
By
John W. Snedden1, and J. F. (Rick) Sarg2
Search and Discovey Article #40270 (2008)
Posted January 19, 2008
1ExxonMobil Upstream Research Company, Houston, Texas ([email protected])
2Colorado Energy Research Institute, Colorado School of Mines, Golden, Colorado ([email protected])
Seismic stratigraphic methods allow one to interpret and map reservoir, source, and seal facies from reflection seismic data. Seismic stratigraphic methods have evolved since the first publications in the late 1970’s. This document attempts to provide an update of these elementary principles, written as a “how-to” series of steps.
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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.
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
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
3. Plot paper copies of selected
regional seismic lines at a reduced scale. We highly recommend
using wiggle trace paper 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
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
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 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
Interpretation Steps
1. Identify areas of major
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 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
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 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
--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
Stacking patterns seen on logs (and
outcrops 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
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
2.
Color systems tracts: green = TST, Blue=HST, terra cotta (brown)
= LST. Coloring lightly with pencil is particularly good for seismic
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 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.
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
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
Figures 8 and 9
illustrate use of the Ramsayer (1979) A-B-C seismic facies mapping
approach on a series of 2D
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
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
Rather than mapping the entire sequence, it is recommended that
individual
Comparing these 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
Combining Seismic Facies
Confidence in seismic facies mapping can be gained by combining
seismic facies
Isochron/Isochore
Paleogeographic
Paleogeographic
Application to Petroleum Exploration and Exploitation
The major reason for developing seismic stratigraphic
Highstand Systems Tract (HST)
In many hydrocarbon exploration
plays, many of the earliest discoveries are found in updip
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
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 ( 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. Summary and ConclusionsThis 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
AcknowledgementsThe 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.
References and Further Reading Abreu, V., M. Sullivan, C. Pirmez, and D. Mohrig, 2003, Lateral accretion packages (LAPs): an important reservoir element in deep water sinuous channels: Marine and Petroleum Geology, v. 20, p. 631-648. Abreu, V., P. Teas, Thomas De Brock, Kendall Meyers, Williams Spears, Steve Pierce, and Dag Nummedal, 2002, Reservoir characterization of the South Timbalier 26 Field: The importance of shelf margin deltas as reservoirs in the Gulf of Mexico: AAPG Bulletin, v. 86, p. 212. Armentrout, J. M., 1991, Paleontologic constraints on depositional modeling: examples of integration of biostratigraphy and seismic stratigraphy, Plio-Pleistocene, Gulf of Mexico, in Seismic Facies and Sedimentary Processes of Submarine Fans and Turbidite Systems, p. 137-170. Armentrout, J.M., S.J. Malecek, L.B. Fearn, C.E. Sheppard, P.H. Naylor, A.W. Miles, R.J. Demarais, and R. E. Dunay, 1993, Log motif analysis of Paleogene depositional systems tracts, Central and Northern North Sea: defined by sequence analysis, in J.R. Parker, ed., Petroleum Geology of Northwest Europe, Proceedings of 4th Conference. p. 45-57. Armentrout, J.M., S.J. Malecek, V.R. Mathur, G.L. Neuder, and G.M. Ragan, 1996, Intraslope basin reservoirs deposited by gravity-driven processes: Ship Shoal and Ewing Banks areas, Offshore Louisiana: GCAGS Transactions, v. 46, p. 443-448. Bally, A.W., 1982, Atlas of Seismic Stratigraphy, AAPG Studies in Geology no. 27, 300 p. Brami, T. R., C. Pirmez, C. Archie, S. Heeralal, and K.L. Holman, 2000, Late Pleistocene deep-water stratigraphy and depositional processes, Offshore Trinidad and Tabago: GCS-SEPM, v. 20, p. 104-115. de Graciansky, P. et al., 1998, Mesozoic and Cenozoic Sequence Stratigraphy of European Basins: SEPM Special Publication no. 60, 786 p. Duval, B.C., C. de Janvry, and B. 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