Seismic Stratigraphy

Ž .Earth-Science Reviews 47 1999 189–218www.elsevier.comrlocaterearscirev

Definition of subsurface stratigraphy, structure and rockproperties from 3-D seismic data

Bruce S. Hart )

New Mexico Bureau of Mines and Mineral Resources, Socorro, NM 87801, USA

Received 2 February 1998; accepted 12 April 1999

Abstract

Ž .This paper summarizes how three-dimensional 3-D seismic technology is being used, primarily in the petroleumŽ .industry, to define subsurface structure, stratigraphy and rock properties. A 3-D seismic data volume: a provides a more

Ž .accurate image of the subsurface than can be obtained with 2-D seismic methods; b is continuous, and so has a muchŽ . Ž .greater spatial sampling than is obtained with 2-D seismic or other subsurface data e.g., wells ; and c can be viewed and

interpreted interactively from a variety of perspectives, thus enhancing the interpreter’s ability to generate an accuratedescription of subsurface features of interest. Seismic interpretation was once the almost exclusive realm of geophysicists,however, most 3-D seismic interpretation today is conducted by multidisciplinary teams that integrate geophysical,geological, petrophysical and engineering data and concepts into the 3-D seismic interpretation. These factors, plus propersurvey design, help to increase the chances of success of a 3-D seismic interpretation project. Although there are cases where

Ž .the technology is not appropriate or cannot be applied for economic reasons or otherwise , the general success of 3-Dseismic has led it to become a mainstay of the petroleum industry. The approach and technology, first developed in thatindustry, have potential applications in other applied and fundamental earth science disciplines, including mining,environmental geology, structural geology and stratigraphy. q 1999 Elsevier Science B.V. All rights reserved.

Keywords: seismic; petroleum; structure; stratigraphy; rock properties

1. Introduction

Few technologies have affected a geoscience sub-Ž .discipline to the extent that three-dimensional 3-D

Žseismic has affected petroleum geoscience geology.and geophysics . Like the field of seismic stratigra-Žphy before it which more or less directly spawned

.sequence stratigraphy , 3-D seismic technology wasdeveloped in the petroleum industry and until re-

) Fax: q1-505-835-6333; E-mail: [email protected]

cently has been utilized almost entirely within thatfield. However, potential applications of 3-D seismicdata in other geoscience disciplines are many, includ-ing studies in structural geology, stratigraphy, geo-physics and petrophysics. The mining industry hasbegun to investigate the potential of 3-D seismic toidentify and map ore bodies, and to plan mine devel-

Ž .opment Eaton et al., 1997 . Furthermore, it may bepossible to transfer the technology cost-effectively to

Ž .the environmental sector Siahkoohi and West, 1998 .The cost and technical requirements of collecting

0012-8252r99 r$ - see front matter q 1999 Elsevier Science B.V. All rights reserved.Ž .PII: S0012-8252 99 00029-X

( )B.S. HartrEarth-Science ReÕiews 47 1999 189–218190

and interpreting 3-D seismic data have prevented,until recently, most academic researchers from ob-taining and utilizing them, although some 3-D seis-mic data have been collected to study deep crustal

Ž .structure e.g., Kanasewich et al., 1987, 1995 andothers have been collected in conjunction with the

Ž .ocean drilling program Shipley et al., 1994 .Changes within the petroleum industry that have

been brought about by the use of 3-D seismic alsohave had a significant, albeit indirect, impact in otherareas. One example is the use of computer worksta-tions in data visualization. Some large 3-D seismicsurveys contain gigabytes of data. Seismic inter-preters have been pushing software and hardwaredevelopers to be able to visualize and interpret theseenormous data sets interactively, and the hardware,software and concepts developed this way will havean impact on other earth science fields. The 3-Dseismic revolution has helped to promote the devel-opment of multidisciplinary teams. Integration ofseismic and geological data and concepts in worksta-tion environments has been undertaken for at least a

Ž .decade cf., Cross and Lessenger, 1988 . However,the continuous coverage provided by 3-D seismicdata has revealed details of reservoir complexitiesthat cannot be characterized using 2-D seismic andwell control. Multidisciplinary teams in many com-panies integrate different data types and use the 3-D

Žseismic workstation and derived products such as.maps and volume interpretations as focal points for

their exploration and development efforts. In someregions and organizations, wells are not drilled with-out previously collecting and interpreting 3-D seis-mic data.

Why have 3-D seismic and associated technolo-gies had such a profound impact on the petroleumindustry? What are the benefits of 3-D seismic? Howdoes one acquire and interpret such data? This sum-mary will address these questions, and present an-swers in terms that will be accessible to the geo-science community at large. The main purposes of

Ž .this paper are: a to illustrate how 3-D data arecollected and interpreted in the petroleum industry,

Ž .and b to suggest how other subdisciplines of geo-science might exploit the technology.

There are other developing fields of seismic tech-nology, such as amplitude variation with offset, ver-tical seismic profiling, seismic inversion and cross-

well seismic technology that are often used in con-junction with 3-D data. It is beyond the scope of thispaper to discuss these topics. Furthermore, a com-plete review of the principles of seismic surveyingand interpretation will not be presented here. Instead,only those aspects that are germane to 3-D seismiccollection, processing or interpretation will be pre-sented here. Numerous other sources present infor-

Žmation about the seismic method e.g., Sheriff and. Ž .Geldart, 1995 . Brown 1996a dealt exclusively with

Ž .3-D seismic analyses, and Weimer and Davis 1996presented many illustrative case studies of the use of3-D seismic data, principally for petroleum explo-ration and development.

2. 3-D seismic acquisition and processing

Like 2-D seismic studies, 3-D seismic data areacquired by generating an acoustic pulse at or near

Ž .the surface land surface or sea surface , and record-ing the energy that is reflected from subsurface

Žchanges in physical properties specifically, velocity.and density . Contacts between stratigraphic units

having detectable changes in physical propertiesŽoften associated with the tops of formations, mem-

.bers, etc. will cause reflections and be picked asseismic horizons 1 during the interpretation phase inorder to discern structural and stratigraphic details ofinterest.

On land, sources are typically vibroseis trucks ordynamite, and the receivers are geophones that detectground motions. At sea, 3-D seismic surveys arecollected using airgun arrays, with pressure sensitivehydrophones detecting the reflected energy. In al-

Ž .most all cases, it is compressional wave ‘‘p wave’’energy that is recorded, although multicomponent3-D surveys that include recording of shear wave

Žreflections are becoming more common e.g., Arestad.et al., 1996 .

With 2-D seismic data collection, sources andreceivers are laid out along a line, and the reflectedenergy is assumed to come from a point mid-way

Ž .between source and receiver the common midpoint

1 Italicized terms are defined in Appendix A.

( )B.S. HartrEarth-Science ReÕiews 47 1999 189–218 191

along a vertical 2-D plane. In the case of horizontallylayered strata, this assumption is valid. However, inareas where there is appreciable subsurface structure,reflected energy can be recorded from interfaces that

do not lie mid-way between sources and receivers.Seismic migration is a processing technique thatattempts to reposition this reflected energy to its truesubsurface location. The need for migration of 2-D

Fig. 1. Seismic modeling results showing an example of sideswipe and Fresnel zone effects associated with a reef. The upper image showsthe model in map view, illustrating the locations of seismic transects shown below. The reef is visible in a seismic transect that is over 300m to the side. Although the sections have not been migrated, 2-D migration will not be able to remove the sideswipe image of the reef from

Ž .the transects Jackson and Hilterman, 1979; cited by Crawley Stewart, 1995 . Reproduced with permission from Hilterman.


seismic data has been recognized from the earlyŽstages of seismic exploration Sheriff and Geldart,

.1995 .Where subsurface structural or stratigraphic enti-

Žties have a distinct three dimensionality i.e., many.or most areas of geologic interest , reflections may

be recorded from interfaces that are outside of theŽ .plane containing the source and receivers Fig. 1 .

These reflections, sometimes called sideswipe, can-not be removed from seismic profiles using 2-Dmigration. It may be impossible to distinguish thissideswipe from reflections that are truly in the planeof the seismic profile, and maps or interpretationsthat are drawn from such seismic sections will beerroneous. Applied and theoretical examples of this

Ž .problem have been presented by French 1974 ,Ž . Ž .Crawley Stewart 1995 and Brown 1996a among

others.The acquisition of 3-D seismic data exploits the

spherical expansion of the acoustic pulse in thesubsurface away from the source. On land, onecommon acquisition pattern spreads receiver groupsout in lines that are oriented at 908 to the shot linesŽ .Fig. 2 . Reflections from each shot are recorded bymany geophones, producing a row of common mid-points that is perpendicular to the orientation of thesource lines, and parallel to the orientation of thereceiver lines. By moving the shot location, a subsur-face grid of common midpoints is generated. Notethat the acquisition geometry shown in Fig. 2 is agross simplification of real survey design. Althoughthere are many different designs that can be used,each survey typically consists of many parallel sourcelines and many parallel receiver lines that are ori-ented perpendicular to the source lines. Each shot isrecorded by a patch of geophones. In this way,individual midpoints are imaged by different combi-nations of sources and receivers, thus, building up

Ž .the fold or multiplicity of the survey. Higher folddata, all else being equal, will result in a highersignal-to-noise ratio and therefore more interpretableseismic data. Experience has shown that the fold of a3-D survey needs only to be about one half the foldof a 2-D survey to obtain the same interpretabilityŽ .B. Hardage, personal communication, 1994 .

At sea, 3-D seismic data are generally acquired byships towing airgun arrays and hydrophone streamersthat sailed back and forth across the survey area.

Fig. 2. Sample source and receiver layout for a land-based 3-Dseismic acquisition program. In this simple case, each shot isrecorded by a line of receivers. By moving the source location, arectangular grid of common midpoints is generated. In practice,many source and receiver lines would exist, increasing the numberof source — receiver combinations that image a particular mid-

Ž .point to build up the fold and data quality of the survey. Other,more complex, survey layouts are typically used in practice.

Increasingly though, innovative techniques such asusing two vessels simultaneously, or implanting geo-phones on the sea floor, are being developed andexploited.

The spacing between the midpoints in the receiverdirection is one half the distance between the re-


ceivers, while the spacing in the source direction isone half the distance between the source locations.For example, assuming that source and receiver loca-tions are both at 60 m intervals, midpoints will begenerated every 30 m=30 m. In this case, eachmidpoint represents an area or bin of 30 m=30 m.The bin size might be rectangular, rather than square,if the distances between source and receiver loca-tions are not identical.

By acquiring continuous coverage of seismic datain three dimensions, the data can be migrated inthree dimensions. In this way, reflection energy isaccurately repositioned to its true subsurface loca-tion, and transects through a 3-D seismic volumewill only show those features that are truly in the

Ž .plane of the section e.g., Brown, 1996a . As such,all else being equal, a vertical transect through a 3-Dseismic volume is a more accurate, better image thanan equivalent seismic transect derived using 2-Dacquisition and processing.

3. Viewing 3-D seismic data

Virtually, all interpretation of 3-D seismic data isconducted on workstations or powerful personal

Ž .computers Hart, 1997 . By exploring and visualiz-ing both the data and interpretations in progress, thegeoscientist can derive a much better understandingof the three dimensionality of subsurface strati-graphic and structural elements. This allows the in-terpreter to generate a more accurate subsurface de-

Ž .scription depicted in maps, etc. , than by workingwith paper seismic displays andror well logs alone.These visualization technologies further aid the geo-scientist in conveying the results of his or her workto others who have not been involved in the interpre-tation process.

ŽEach bin in a 3-D seismic volume having x, ydimensions that are defined primarily by data acqui-

.sition operations can be represented by a singleseismic trace, conceptually centered in the middle ofthe bin. Each trace in turn is divided into equalincrements in the z direction that define the sam-pling interval. For petroleum exploration purposes,the sampling interval is typically 2 or 4 ms. Theresult is that the 3-D seismic volume can be thought

Žof as a series of cubes, or Õoxels a term analogous.to the 2-D pixels of remote sensing , each of whichŽ .stores a particular amplitude value Fig. 3 . Using

modern computer graphics capabilities, it is possibleto visualize and interpret the seismic data in a variety

Ž .of ways see below .When seismic data were primarily viewed as pa-

per sections, the standard display format was to useblack and white variable area wiggle displays. Thisdisplay presents seismic traces as continuous curves

Ž .that define a time series of positive peaks andŽ .negative troughs amplitudes, and the peaks are

filled in with a solid black colour.A drawback of the variable area wiggle display is

that the eye tends to focus on the peaks, and the

Fig. 3. Conceptual diagram showing a 3-D data volume. Eachvoxel in such a volume is characterized by x, y, z coordinates

Ž .and an amplitude value positive and negative values . The x andy dimensions of each voxel represent the bin size, and are afunction of acquisition parameters, whereas the z dimension of avoxel represents the digital sampling interval. The range of ampli-tudes depends upon how the data have been scaled. In a variable

Ž .density display top and side of the cube , the numerical amplitudevalues are represented by colours that are selected by the inter-

Ž .preter see Fig. 4 .


Ž . Ž .Fig. 4. Colour displays of seismic data. a Seismic data has traditionally been displayed as Õariable area wiggle displays left in which theŽ .reflected energy is displayed as waveforms consisting of positive and negative amplitude values peaks and troughs respectively . Peaks are

Ž .filled in with black to enhance the interpretability of the seismic transect. Computer graphics displays allow the amplitudes center to becolour coded so that positive and negative amplitudes are shown, respectively, in blues and reds with the darkness of each colour being

Ž .proportional to the amplitude value. Whites correspond to zero amplitude. By removing the wiggle trace right the seismic traces are shownŽ .as Õariable density displays. b Variable density display of a seismic transect. By displaying adjacent traces side by side, the display has the

Ž .appearance of data continuity throughout the entire transect. Compare with the variable area wiggle display of the same transect c . TheŽ .colour display gives approximately equal weight to peaks and troughs blue and red, respectively , helping the interpreter to detect

stratigraphic and structural features. Variations in amplitude along a single reflector are also easier to detect. Although the blue–white–redcolour scale shown here is the most commonly used, interpreters will choose other scales to enhance certain aspects of the seismic data.


Ž .Fig. 4 continued .

information present in the troughs can be overlookedŽ .Brown, 1996a . With the advent of interactive com-puter displays, variable density displays have be-come the norm. In this display, the peaks and troughsare arbitrarily assigned distinct colours. One com-monly employed colour scheme shows peaks as blueŽwith stronger positive values being shown as darker

. Ž .blue passing through white near zero amplitudesŽ .to red troughs more negative values as darker red .

Other colour schemes can be generated by inter-preters to highlight specific aspects of the seismic

Ž .data e.g., bright spots, dim spots on which theywish to focus. The variable density display gives theappearance of reflection continuity throughout the

Ž .entire 3-D volume Fig. 4 .The 3-D seismic data volume is stored in digital

format, on disk. The types of displays that can beŽ .generated Fig. 5 depend on the software and hard-

ware capabilities of the interpreter, but generally canbe grouped into a few distinct categories that arediscussed next.

3.1. Vertical transects

Vertical transects through a 3-D seismic volumeŽ .Fig. 5a–d look like 2-D seismic profiles, but differin that their location and orientation are decided by

the interpreter in an interactive manner, rather thanbeing constrained by the original seismic survey lineorientation as is the case for 2-D data. Since the dataare stored digitally, the interpreter can also zoom inon small portions of the seismic data, or zoom out tosee the larger structural and stratigraphic framework.Most software packages allow the user to quickly

Ž .display vertical transects: a in the inline or lineŽ .direction, b in the crossline or trace direction, and

Ž .c arbitrary lines that represent transects throughthe data in any direction decided upon by the inter-preter. The arbitrary line may consist of a singletransect or a series of continuous transects that zigzag

Žtheir way through the data set sometimes called a.multipanel display . Arbitrary lines are used when

the interpreter wishes to view the true geometry ofstructural or stratigraphic features that are oriented

Ž .obliquely to the line or trace orientation see below ,or when wishing to tie borehole log informationfrom more than one well by integrating with theseismic data. With vertical transects, the data can beflattened on a selected horizon to more clearly viewtrue stratigraphic relationships in areas that havebeen structurally deformed. This latter process isakin to using a formation top or log pick as a datum

Žto construct a stratigraphic cross-section using well.logs or outcrops rather than generating a structural

cross-section.


Ž .Fig. 5. Different types of 3-D seismic displays that can be viewed during an interactive interpretation session. a, b Line and trace transectsŽ . Ž . Ž . Ž . Ž .that correspond to source and receiver line orientations, c arbitrary transect, d multipanel display, e time slice, f horizon slice, g

Ž .perspective display, h cube display. See text for discussion.

3.2. Horizontal sections

These displays, known as time slices, represent aslice through the data at a given two-way traveltimeŽ .TWT, constant z coordinate; Fig. 5e and Fig. 6 .The display is somewhat analogous to a geologicmap. The difference is that instead of viewing how

Žstratigraphic units intersect the ground surface which.may or may not be planar , the interpreter sees how

the seismic manifestation of the stratigraphy inter-sects an arbitrarily selected plane of constant TWTthrough the seismic data. In both cases, however, thethickness of the reflection from a given stratigraphic

Ž .unit on the display map is a function of the strati-Žgraphic dip for a constant thickness, a less steeply

.dipping bedrreflection will appear wider; Fig. 7a,bŽ .and ‘‘thickness’’ frequency of the reflection event

Žfor a given structural dip, higher frequency events.will appear thinner; Fig. 7c .

Ž .Although Brown 1996a and others recom-mended using time slices for horizon interpretation,most interpreters tend to concentrate their use ofthese displays on interpreting faults — especially

Žwhere stratigraphic dips are small i.e., relatively

.undeformed basins . The utility of time slices forhorizon interpretation is greatest when beds have apronounced dip. In this case, horizon mapping ontime slices can be a quick way of generating timestructure maps for those horizons. With the advent ofautomatic horizon tracking and interfacing of seismic

Ž .interpretation with mapping packages see below ,time structure maps can, in most circumstances, begenerated just as readily by basing most interpreta-tion on vertical sections.

Fault interpretation and correlation can be signifi-cantly improved by interactively working with timeslices and vertical slices together. Time slice displaysshow faults as curvilinear features that display lateraloffsets of reflections, amplitudes or abrupt changes

Ž .in seismic reflection character Fig. 6 . Typically,faults can be traced laterally for considerable dis-tances on time slices, thus, reducing the ambiguityinherent in interpreting fault locations and orienta-

Ž .tions from 2-D seismic or well data see below .

3.3. Horizonr fault and map displays

These displays show characteristics of horizons orfaults that have been interpreted in a seismic volume.


Fig. 6. Time slice through 3-D seismic volume, offshore Gulf of Mexico. Note curvilinear trends of reflection character offset thatcorrespond to faults viewed in vertical sections. By interpreting the faults on both vertical transects and time slices, the potential formiscorrelation is reduced, leading to a more accurate interpretation than could be generated using 2-D seismic data.

They allow the interpreter to view spatial relation-ships in two dimensions. Time structure of an inter-preted horizon, showing locations of faults, folds andstructural dips, is perhaps the most commonly vieweddisplay. If desired, the interpreter can interactivelyadjust the colour scale bar to detect structural rela-

Žtionships e.g., areas with subtle closure that could.act as hydrocarbon traps that might otherwise be

overlooked.In many areas, the seismic amplitudes associated

with particular stratigraphic horizons can be of sig-Ž .nificance e.g., Enachescu, 1993 . For example,

‘bright spots’ are associated with hydrocarbon accu-mulations in some areas, and interpreters will exam-ine map displays of the amplitude of seismic hori-zons in order to look for stratigraphic or structuralfeatures that might be hydrocarbon traps. Displays of

horizon amplitudes are sometimes called horizonŽ .slices Fig. 5f . Channel sandstones and other strati-

graphic features can also, under some circumstances,Žbe identified using seismic amplitudes e.g., Hardage

.et al., 1994; Brown, 1996a . Structural contours canbe superimposed onto amplitude displays in order toallow the interpreter to easily search for relationships

Ž .between these two data types Fig. 8 .Ž .Bouvier et al. 1989 present an example of the

use of fault slices to examine fault sealing capabili-ties of Tertiary faults in the Niger Delta area. Bygenerating fault slices in both the hanging wall andfootwall, the juxtaposition of lithologies across thefault can be assessed. In this way, it might bepossible to judge whether a fault is a barrier to fluid

Ž . Žflow e.g., sand on shale contact or not e.g., sand.on sand along the entire fault plane.


Ž .Fig. 7. Schematic diagram illustrating the effects of: a strati-Ž .graphic dip, and b reflection frequency on the thickness of a

Ž .reflection viewed on a time slice. Adapted from Brown 1996a .

Although strictly not related to one horizon, mapdisplays are also employed to view thickness, in timeŽ . Ž .isochrons or depth isopach units, between twostratigraphic horizons. Other interÕal attributes, suchas the maximum amplitude between two horizons,can also be viewed and interpreted in this fashion.These, and other interval attribute analyses are some-

times employed in a ‘quick look’ fashion to identifystratigraphic configurations or rock properties ele-ments that warrant detailed investigation. Horizon

Ž .attributes discussed below are also viewed in mapviews.

3.4. PerspectiÕe displays

Ž .This type of display Fig. 5g shows horizons,Ž .faults and well data as 3-D perspective isometric

views that can be rotated to help the interpreterassess spatial relationships in 3-D. Additionally, theycan be employed to quality check interpretations —for example, to ensure that horizon or fault picks arephysically plausible. With some interpretation pack-ages, it may be possible to superimpose ‘attributes’

Žsuch as seismic amplitude, isochrons thickness, in.time units , etc. on top of the 3-D surface to more

easily evaluate, for example, possible relationshipsbetween amplitudes and structure. Illumination an-gles and opacity might also be adjusted to helpdetect subtle structural trends.

3.5. Cube displays

Ž .This type of display Fig. 5h and Fig. 9 allowsthe interpreter to view the seismic data as a volume.

ŽBy scrolling through the data cube front to back, left.to right, and top to bottom , the interpreter can

quickly get an intuitive feel for the broad scalestratigraphic and structural configuration of a studyarea before beginning detailed interpretation. Inter-

Ž .pretations fault and horizon can, however, be madeon the faces of the data cube. The data may be‘clipped’ in various ways to visualize specific as-pects of the data set that will assist in the interpreta-tion.

Most cube displays show the faces of the datavolume, while data behind those faces remain out of

Ž .Fig. 8. a Vertical transect through 3-D seismic volume from the San Juan Basin, New Mexico, showing classic ‘‘doublet’’ responseŽ .troughs associated with thick accumulations of aeolian Jurassic Entrada Formation. Strong peak above the Entrada is the Todilto

Ž . Ž .Formation gypsum and limestone . b Time structure contours of the Entrada horizon superimposed on horizon slice of the formation.Contours were generated by picking the horizon on seed lines, autotracking the horizon throughout the survey area, quality checking theresult, then contouring the data. The contours suggest a thick build-up of the dune deposits along the lower margin of the survey area. The

Ž .amplitude of the Todilto reflection decreases over the crest of the buildup lower amplitudes shown in lighter greys , helping to corroborateŽthe interpretation and increase the attractiveness of this area as a drilling target see Vincelette and Chittum, 1981, for a description of the

.seismic character of Entrada reservoirs . Although small, these deposits can form attractive drilling targets. It would not be possible topinpoint the optimal drilling location for these types of buildups, or other features such as pinnacle reefs, meandering channel sands, etc.,with this degree of confidence using 2-D seismic or well control alone.


sight. Voxel rendering technologies allow the inter-preter to make specific ranges of amplitudes trans-parent, leaving only particular ranges of amplitudesvisible. The objective is to facilitate the 3-D viewingand interpretation of subsurface features, such as

bright spots associated with hydrocarbon accumula-tions, that have specific amplitude characteristics.This type of display can be especially useful, forexample, when planning a deviated wellbore so thatit penetrates multiple pay zones that manifest them-



selves as bright spots at distinct stratigraphic levels.Virtual reality technologies are being explored thatallow the interpreter to view the data in 3-D or even

Ž .to ‘‘enter’’ the seismic volume Dorn, 1998 . How-ever, application of these technologies is notwidespread.

3.6. Combination displays

Some software applications allow several differ-ent types of data and interpretations to be visualized

Ž .together e.g., Fig. 10 . For example, it may bedesirable to examine well paths, interpreted horizons,and some seismic data together. As is the case withthe other types of displays, the objective is to helpthe interpreter to visualize the geology, engineeringand other types of data in 3-D. Another importantcomponent is that these displays help the interpreter

Žto present hisrher results to others e.g., co-workers,.management, investors who have not been active in

the interpretation process.

4. Interpreting 3-D seismic data

In the petroleum industry, most 3-D seismic inter-pretation is conducted by members of multidisci-plinary teams that are composed of geologists,

Ž .geophysicists and engineers Hart, 1997 . This isbecause experience has shown that the ambiguity

Žinherent in the seismic method due to limitations onvertical and lateral resolution and the non-uniqueness

.of the seismic response can be reduced by integrat-ing geologic and petroleum engineering data and

Ž .concepts Fig. 11 .As with other subsurface studies, the principal

objectives of a 3-D seismic survey are definition ofsubsurface stratigraphy, structure and rock physicalproperties. Most such data sets are collected fromareas of existing production, so that some subsurface

Žcontrol e.g., wireline logs, paleontological data, en-

.gineering data exists already. Having this informa-tion ‘up front’ allows the interpretation team mem-bers to better exploit the massive amounts of dataavailable to them in the 3-D seismic volume. Typi-cally, however, an interpretation is not viewed somuch as a ‘final product’ as a ‘work in progress’that is to be updated and revised as new data becomeavailable through drilling. The establishment of de-

Žvelopment drilling plans finding infill and step out.drilling sites is a common application of 3-D seis-

mic, although most interpreters will also use the dataŽfor exploration purposes e.g., looking for other, as

.yet unproductive, stratigraphic intervals . There isincreasing use of 3-D seismic data, particularly bylarge companies, as a purely exploration tool.

It should be noted that although the vertical reso-Žlution of seismic data generally, only features 10 m

.or more in thickness will be resolved is not as greatŽas wireline logs or core millimeter scale in core,

.decimeter scale in logs , the continuous subsurfacecoverage in a 3-D survey provides much better spa-tial control for mapping. For example, in NorthAmerica, typical development drilling density might

Ž 2 .be 16 wells per section 2.59 km , yielding 16Ž .‘control points’ wells with wireline logs in that

area. A 3-D seismic survey over that same areamight have 33.5 m=33.5 m bins, yielding 2304control points in the same area. The result is that the3-D seismic survey has 144 times more controlpoints for mapping than even the relatively tightly

Ž .spaced wells Ray, 1995 . As such, mapping ofstratigraphic and structural features using 3-D seis-

Ž .mic provided that they can be detected seismicallyis much more accurate than mapping based on inter-pretation between even densely spaced wells or 2-Dseismic data.

4.1. Stratigraphic interpretation

As with a 2-D seismic interpretation, the strati-graphic interpretation of a 3-D seismic volume typi-

Ž .Fig. 9. Sample cube displays. a Entire data set showing east–west and north–south vertical transects along the front and right side faces ofŽ .the cube, respectively, and a time slice on the top face. b Entire time range is shown, but the front face has been cut to show an east–west

Ž .transect about 2r3 of the way into the volume, showing only a limited part of the survey area. c Entire area of survey is shown, but the topface has been cut down about 3r4 of the way into the volume. By interactively scrolling through a data cube such as this, the interpreter canquickly assess changes in stratigraphic and structural style with location and depth.

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Ž . Ž . ŽFig. 10. Combination display showing a 2-D seismic line left, colour , a portion of a 3-D seismic cube back, grey tones , a voxel display of a 2nd 3-D volume greens and. Ž . Ž . Žyellows, right , two interpreted horizons from the seismic data blue, pink , some well logs blue, coming down from top and the locations of the 3-D seismic data sets yellow

. Ž . Ž .and red grid at bottom , 2-D seismic lines blue, at bottom and wells red dots at bottom . By integrating different types of data and interpretations into single displays such asthis, multidisciplinary teams can make better drilling and reservoir management decisions. Figure courtesy of Landmark Graphics.


Fig. 11. Bar graph showing responses of 133 seismic interpreters when asked about the need to integrate geologic and engineering data andconcepts into a 3-D seismic interpretation. Experience shows that it is only through integration of the technology with other data types that

Ž .the true potential of 3-D seismic technology is realized. From Hart 1997 .

Ž .cally begins by tying wireline logs geologic data tothe seismic data using Õelocity surÕeys, Õertical

Žseismic profiles andror synthetic seismograms e.g.,.Sheriff and Geldart, 1995 . From these initial seed

points, horizons are interpreted on a grid of verticaltransects. The grid allows the user to ‘box in’ thepicks, helping to ensure a consistent interpretation.

Picking a horizon on every line in a 3-D volumecan be a labour intensive task, and so most softwarepackages have an autotracking application that canbe employed to automate the process. The grid ofmanual horizon picks forms a network of seed points,from which the software will attempt to track a pickof similar phase and amplitude throughout the seis-mic volume. Under ideal conditions, such as a con-tinuous reflection that has significantly higher ampli-tude than surrounding events, it might be possible toautotrack a horizon based on a single seed point.Conversely, in areas of high noise or geologic com-plexity it may not be possible to autotrack a horizonat all. In any case, the results of the autotrackingneed to be checked and manually edited where nec-essary. The finished horizon pick should be bothgeologically and geophysically defensible. Once timestructure maps have been derived, the horizons are

Ž .converted to true depths e.g., meters using avail-able velocity data.

Once a stratigraphic framework has been estab-lished, such as by defining and mapping floodingsurfaces, unconformities or other significant and de-finable horizons, detailed stratigraphic analysesŽ .seismic facies analysis, reflection character analysisare conducted on those intervals that are judged to beof particular stratigraphic importance. Clinoforms,channels, parasequences, reef complexes or otherstratigraphic entities are studied using conventional

Žseismic stratigraphic criteria e.g., Mitchum et al.,.1977; Sarg, 1987 and by integrating all available

Žlog, core and biostratigraphic data e.g., Hart et al.,.1997 . Where line or trace orientations are oblique to

stratigraphic trends, arbitrary lines through a seismicvolume will be selected to examine the true longitu-dinal and cross-sectional geometries of clinoforms,channels and other features.

With most software packages, it is possible tosuperimpose wireline logs directly over the seismicdata in vertical transects in order to help merge

Ž . Ž .geologic logs and geophysical seismic data andŽ .concepts Fig. 12 . To do so, some time-depth con-

version information is required. Depending on the


Ž .Fig. 12. Example of a seismic view with well log overlay. Log curve shows g-ray increasing to the right with true well position indicatedŽby vertical white lines. Note good correspondence between lithology contrasts as indicated by logs low g-ray, clean carbonates; higher

.g-ray, dolomitic sandstones and siltstones and the location of prominent reflections. This type of display is used to help verify picks, bothŽ .log and seismic. Seismic transect shows basinward progradation to left of mixed siliciclasticrcarbonate Permian shelfrslope in Delaware

Basin, SE New Mexico.

types of logs employed, these displays can help toguide correlations from well to well, identify faciesassociations or stratal surfaces, identify fluid con-tacts, etc.

Time and horizon slices can help the interpreter toidentify and map features such as fluvial channels,

Ž .sinkholes, e.g., Hardage et al., 1994; Brown, 1996a ,

Ž .deltaic lobes Hart et al., 1997 and even meteoriteŽ .impact structures Isaac and Stewart, 1993 . In the

petroleum industry, knowledge of the distribution ofthese depositional features can help to identify orpredict sedimentary facies distributions, and thus thelocation of reservoir quality rock or barriers or baf-fles to subsurface fluid flow that might compartmen-

Ž . ŽFig. 13. Structure map lower left of a horizon suggests the presence of a small NW–SE trending graben darker greys are structurally. Ž X .lower areas . A seismic transect in the inline direction A–A does not clearly show the subtle fault on the southwest. This might be the

Ž X .orientation of a 2-D seismic line. By viewing an arbitrary line that is perpendicular to the fault orientation B–B , the fault geometrybecomes clearer. Although the fault is readily apparent, it may not be clear from this view how the horizons correlate from one fault block

Ž X Y .to another. As such, a multipanel display was chosen that goes around the fault pinchout to the north C–C –C . This latter display clearlyshows reflection continuity from one block to the other, thus, confirming the interpretation shown in B–BX. Example from New York StateŽ .see Hart et al., 1996 .



Ž .Fig. 14. Two different horizon attribute maps for the same seismic horizon. a Dip map, showing variability in dip amount for the surfaceŽ . Ž . Ž .darkersgreater dip . b Azimuth map, showing which way the horizon is dipping. Light source is from the upper right NE , so thatsurfaces dipping to the SW appear dark. These maps show linear trends that indicate the presence of subtle faults which were not evidentwhen interpreting vertical transects through this data volume.


talize reservoir. Typically, vertical sections, timestructure maps, and horizon displays will be evalu-ated simultaneously to assess a given prospect.

4.2. Structural interpretation

Structural and stratigraphic interpretations neces-sarily feed off one another. For example, it is notpossible to calculate throw on a fault without beingable to identify common horizons on either side ofthe structure. Conversely, to correlate a horizon fromone side of a fault to the other, the interpreter needs

Žto understand the fault geometry normal, reverse,

.etc. . As with stratigraphic interpretation, verticaltransects, time slices, and other displays will all beutilized together during the structural interpretationprocedure. Faults can be interpreted on both timeslices and vertical transects, and the results of inter-pretation on one display can be viewed and used toguide fault picking on the other. The ability to viewarbitrary lines through the seismic volume can, aswith stratigraphic interpretation, have a significant

Žbeneficial impact on structural interpretations Fig..13 .As with a stratigraphic interpretation, the struc-

tural interpretation begins by identifying the large

Ž . Ž .Fig. 15. Continuity cube similar to a Coherency Cubee showing subtle faulting indicated by curvilinear trends of low coherence darkand poor data quality area. As with the horizon attribute maps, these cubes help interpreters to recognize subtle structural features thatotherwise might be undetected in vertical sections and time slices. Stratigraphic features, such as channels and reefs, can also sometimes bedelineated with continuityrcoherency cubes.


scale faults, then successively mapping finer details.Faults can generally be detected when the throw is

Žgreater than 1r4 the wavelength Sheriff and Gel-.dart, 1995 . Subtle faults that are not easily recog-

nized on vertical transects can sometimes be detectedŽby generating and examining horizon attributes e.g.,

Dalley et al., 1989; Hoetz and Watters, 1992; Hes-.thammer and Fossen, 1997a; Fig. 14 . These can

Ž . Žinclude dip in msrm , azimuth i.e., the direction.that the surface is pointing, ranging from 08 to 3608 ,

Ž .edge detection emphasizing discontinuities andother properties. Depending on the orientation anddip of the fault with respect to stratigraphic horizons,any particular one of these displays might help todetect subtle structures that might have a significantimpact on subsurface fluid flow.

ŽCoherency Cubee processing and similar tech-.niques generates a seismic attribute that quantifies

the similarity between a given seismic trace and itsŽ .neighbours Bahorich and Farmer, 1995 . This nu-

merical measure is somewhat analogous to the ‘re-flection continuity’ that seismic interpreters havebeen employing qualitatively for many years. Whenthe waveshape for a trace in a given time window issimilar to that for adjacent traces, as might be ex-pected when the stratigraphy is continuous across anarea, the coherency attribute calculated at that posi-tion is high. When there are significant differencesbetween traces, as might be expected where thestratigraphy is offset by faulting, the coherency islow. This type of data is derived from a 3-D seismicvolume, and can be viewed in the same way; typi-

cally cube displays or time slices are considered toŽ .be most revealing Fig. 15 . This attribute can very

precisely and quickly reveal the location of subtlefaults or stratigraphic features that might be other-wise missed.

3-D seismic analyses can often result in structuremaps that are significantly different from structuremaps based on 2-D seismic andror well control.That these maps truly are more accurate than the

Ž .original maps has been empirically and frequentlydemonstrated by drilling results, and by integration

Žwith other data types e.g., Badgett et al., 1994;.Brown, 1996a; Weimer and Davis, 1996 .

4.3. Rock properties

Definition of subsurface rock properties, such asporosity or fluid saturation, directly from reflectionseismic data continues to be a field of significantinterest. Seismic inversion is a technique that at-tempts to reconstruct the subsurface physical proper-ties distribution, usually directly from the processed

Ž .seismic traces e.g., Lindseth, 1979 . Many inversionalgorithms have been developed, but the inversionprocess itself provides non-unique solutions —sometimes many different stratigraphic successionscould have produced a given seismic section. Ac-cordingly, interpreters generally attempt to constrainthe inversion process with physical property informa-

Ž .tion density, velocity derived from well control.Acoustic impedance volumes are generated for inter-pretation in this way.

Ž .Fig. 16. Empirical, quantitative derivation of rock properties from seismic attributes. a Values of selected attributes are extracted from thebins that correspond to well locations, and crossplotted against well-derived measurements. In some cases, no correlation is presentŽ . Ž .Attribute 1 . In other cases, there might be a negative correlation between attributes and log properties Attribute 2 or a positive correlation

Ž . Ž .between the two Attribute 3 . Linear and polynomial regression approaches might be tried. b Relationships might be sought out between areservoir property and several attributes. Here, the 3-D graph, which can be interactively rotated, allows the interpreter to view statisticalrelationships between three variables. The size of the data point is proportional to its closeness to the observer. This type of interactive dataexploration can help the interpreter to seek out correlations between seismic attributes and log-based physical properties. Multiple regression

Ž .techniques can be used to improve the correlation between seismic attributes and reservoir properties. c Once an empirical, numericalrelationship between seismic attributes and rock properties has been established, it is used to assign rock properties to other areas within the

Ž Ž ..3-D survey area that lack well control. Here, a 2nd order multiple regression based on three attributes not the three shown in a has beenŽ .employed to derive the thickness of the reservoir interval having a porosity greater than 12% contours . The underlying grey scale shows

structure, with structurally high areas being the lightest. Structure generally shows a dip from upper right to lower left. The thickest porousŽ . Ž .section )20 m is located beneath the structural culminations in this Jurassic shelf margin carbonate buildup center of map , although

Ž . Ž .some porosity also appears to be present on the seaward flank bottom — possibly as talus accumulations. See Hart and Balch 1998 forfurther discussion.



Complex trace attributes, such as amplitude, in-stantaneous frequency, reflection strength and instan-

Žtaneous phase and many others Tanner and Sheriff,.1977; Brown, 1996b are currently being analyzed

and exploited qualitatively in the hopes that theycontain information about the physical properties ofthe rocks being imaged. Although the analysis ofthese attributes is not new, the degree of vigour withwhich 3-D seismic interpreters are currently deriving

Ž .and exploiting them Hart, 1997 can be related to:Ž .a the direct way in which large amounts of digital

Ž .data can be analyzed, and b the ability to linklog-derived physical properties from individual wellsto a specific traces in a spatially continuous 3-Dseismic volume. Seismic amplitudes are the mostreadily imaged and qualitatively interpreted attributeŽ .Enachescu, 1993 , although other attributes are ex-

Žploited in a qualitative way as well e.g., Hardage et.al., 1996 , either individually or collectively. Non-

Žuniqueness of response e.g., seismic amplitudes canbe affected by changes in porosity, bed thickness,reflector geometry, fluid content, processing and

.other variables should be an important considerationwhen interpreting such data.

Using a relatively new technique, growing num-bers of interpreters are attempting to correlate seis-mic attributes empirically with reservoir physical

Žproperties measured by borehole logs Schultz et al.,.1994 . The complex trace attributes potentially con-

tain information about the physical properties of therocks being imaged seismically, but the direct rela-tionship between the rock properties and seismicattributes may be practically impossible to derivefrom first principles. The objective is to try to corre-late physical properties, as measured from boreholelogs, with seismic attributes derived from the tracesthat correspond to the boreholes. Different methodsare being utilized or developed, including multipleregression, geostatistics, and neural networks first toderive the relationships, and then to distribute prop-

Žerties throughout the area of the seismic survey Fig..16 .

Ž .Matteucci 1996 and others have identified sev-eral aspects that need to be considered when adopt-ing this approach. First and foremost, the correlationbetween the attributes and physical properties mustbe statistically significant. A prediction of reservoirproperties based on a quantitative, empirical relation-

ship is of limited value if the correlation coefficientis too low. Second, the relationship should be statis-tically robust and take into account uncertainties, forexample, in the exact borehole location or seismicnoise. The location of boreholes might be knownonly to within a range of bins, especially if the wells

Ž .are old and poorly surveyed or large offsets indeviated wells are present. Using several adjacentbins in the correlation exercise can, provided that thereservoir is homogeneous enough, help to determinethe robustness of the correlation. Finally, the numberof attributes that can be generated is great, increasingthe probability that there will be at least one statisti-cally significant, but possibly spurious, correlationŽ . Ž .Kalkomey, 1997 . Additionally, Hirsche et al. 1997pointed out that limited well control or biased sam-

Ž .pling only specific facies might be drilled canmake it difficult to assess whether basic statisticalassumptions that underpin the utilization of thesemethods are violated.

Ideally, the interpretation team might have a largenumber of wells to work with. From these wells,they can randomly exclude some from the calibrationprocess, then test the predictions of their work against

Žthe data from the excluded wells e.g., Schultz et al.,.1994 . This approach may not be feasible in areas of

Ž .limited well control e.g., new or small fields . Oneof the fundamental questions that should be asked ofany rock properties prediction is whether the resultmakes geologic sense. This is true regardless of howthe prediction is derived, or the strength of thestatistical correlation. The most prudent approach toassessing these predictions is to view them as work-

Ž .ing hypotheses that: a will help to assess the riskŽ .associated with drilling a specific prospect, and b

will need to be revised as new information becomesavailable.

4.4. Integration

As is the case with any subsurface data, there is acertain amount of ambiguity in the interpretation of

Ž .seismic data 2-D or 3-D that cannot be removed byworking with it alone. These limitations are theproduct of many factors, including the vertical reso-lution and non-unique response of seismic data, ac-quisition and processing programs, and interpreters’


skills or biases. As such, most interpreters recognizethat their seismic interpretations need to be inte-grated with geologic and engineering data and con-cepts in order to maximize the benefit that they

Ž .derive from a 3-D seismic volume Hart, 1997 .As noted previously, the integrated study might

include paleontologic, core, wireline log, production,and other data types. Case studies presented by

Ž . Ž .Badgett et al. 1994 , Hardage et al. 1994 ,Ž . Ž .Rafalowski et al. 1996 and Hart et al. 1997

illustrate how 3-D seismic, core, wireline log, pres-sure and production data are integrated with se-quence stratigraphic, seismic attribute, productionand other analyses to generate holistic reservoirmodels. Detailed analyses of the seismic data them-selves, possibly including wavelet extraction, for-ward modeling, phase correction and other steps, canbe employed to add confidence to the ties between

Ž .seismic and well data e.g., Dorn et al., 1996 .Ideally, it would be possible to export a 3-D reser-voir model populated with physical properties di-rectly from the seismic analyses into a reservoirsimulator, but this type of activity is not yet com-

Ž .monplace Hart, 1997 .Integration is a key component in the developing

field of time-lapse or 4-D seismic analyses. Thistype of analysis seeks to find differences in ampli-

Ž .tude or other attributes from a given reservoir thatmight be visible in successive 3-D seismic surveyscovering the same area, and then to relate thesedifferences to changes in pore fluids that are due to

Žproduction or enhanced recovery operations e.g.,.Greaves and Fulp, 1987; Anderson et al., 1996 . This

approach is most widely used where amplitudesŽ .bright spots provide direct hydrocarbon indicators,although applications of the technique to monitorsteamfloods or CO injection programs have also2

Žbeen undertaken D. Lumley, personal communica-.tion, 1998 .

5. Discussion

First conceived within large petroleum companiesin the early 1960s, it was not until the 1970s that 3-D

Žseismic concepts were publicly presented Walton,.1972; French, 1974 . Documentation of 3-D seismic

Ž .success stories in the late 1970s e.g., West, 1979 to

middle 1980s fueled interest in the technology. Al-though much, if not most, of the ensuing drillingsuccess attributable to 3-D seismic has gone unre-

Žported in the scientific literature there are many case.histories in trade journals , the worth of the technol-

ogy is empirically demonstrated by a single statisticthat shows the extent to which the petroleum indus-try has begun to focus on the technology: by the endof 1996, 3-D surveys accounted for nearly 75% of all

Žseismic acquisition Society of Exploration Geo-.physics, 1997 . The application and development of

this technology has had a tremendous impact on thepetroleum industry, largely due to the precision andaccuracy with which stratigraphic and structural ele-

Žments can be identified, mapped and drilled e.g.,Haldorsen and Damsleth, 1993; Sibley and Mastoris,

.1994 . These same types of benefits should be realiz-able in any geoscience discipline where the objectiveis to characterize properly subsurface structure,

Ž .stratigraphy and sediment or rock properties.

5.1. Non-petroleum applications

The cost of acquiring and processing 3-D seismicdata is no doubt the greatest impediment to thedevelopment of more widespread application of thetechnology. Additionally, relatively inexpensive PC-based data visualization and interpretation packages

Žare making interpretation capabilities at least the.more commonly used applications accessible to

greater numbers of potential users.Ž .Eaton et al. 1997 performed cost–benefit analy-

ses to examine when the technology can be cost-ef-fective in the mining industry, and also examinedsome of the technical considerations related to seis-mic imaging in plutonic environments, rather thanlayered sedimentary successions. For example, theynoted that while most reflection seismic processingis geared towards enhancing continuous features suchas bedding, in crystalline terranes scattering effectsfrom localized bodies are of paramount importance.Unmigrated 3-D seismic volumes can help inter-preters to recognize scattering anomalies producedby features such as ore bodies, and may therefore beof greater interest in the mining industry than mi-

Ž .grated volumes Eaton et al., 1997 .Cost was initially considered to be an obstacle to

the application of 3-D seismic in the environmentalŽ .industry House et al., 1996 , although recent experi-


Žmental studies are suggesting otherwise Siahkoohi.and West, 1998 . Cost–savings realized by techno-

Žlogical improvements e.g., more cost-efficient ac-.quisition layouts are likely to overcome this barrier,

especially in hydrogeology where aquifers are struc-turally or stratigraphically complex, and the eco-nomic considerations associated with water availabil-ity or contamination are great. Problems associatedwith obtaining high quality shallow seismic dataŽ .especially in the vadose zone are also currently animpediment.

As an ‘academic’ discipline, structural geologycould benefit by more widespread application of 3-Dseismic data. Experience in the petroleum industryhas shown that many structural interpretations based

Žon 2-D seismic are wrong, to varying degrees typi-cally, fault geometries are oversimplified; e.g.,

.Brown, 1996a; Mansfield, 1996 . Since 2-D seismicbased interpretations are used as input into kinematicmodels, it may be desirable or even necessary torevise some of the models to take into account newdetails that could be provided by 3-D seismic map-ping. In some cases, it will not be possible to derive

Ž .the true 3-D geometry and evolution of these struc-tures without 3-D seismic data. For example, Mans-

Ž . Ž .field 1996 and Rowan et al. 1998 demonstratedhow 3-D seismic data can be employed to under-stand the spatial and temporal development of agrowth fault arrays. These types of analyses tradi-

Žtionally have been based on 2-D analyses seismic or.outcrop , either in section or plan, and case studies

that document the true 3-D geometry and evolutionof real fault arrays are rare.

Beginning in the 1970s, the development of seis-Žmic stratigraphy and the offshoot of sequence

.stratigraphy as a mature science did much to revolu-tionize and reinvigorate the field of stratigraphy. Thefirst order controls on depositional sequence archi-

Žtecture sea-level change, subsidence and sediment.supply are fairly well established, although the rela-

tive importance of each and the nomenclature usedto describe successions of sedimentary rocks remaintopics of considerable debate. By providing a contin-uous and accurate image of the subsurface, 3-Dseismic data have the potential to improve our under-standing of some of the 2nd or higher order controlson stratigraphic architecture. Although 3-D seismicdata are often collected over smaller areas than 2-D

seismic surveys, limiting their usefulness for regionalstratigraphic interpretations, the lateral continuityprovided by 3-D seismic will help stratigraphers tobetter understand the controls of local processes suchas reactivation of basement tectonic elements, andautocyclic lobe switching on depositional architec-ture. Additionally, many studies have shown thatstratal geometries derived from 2-D seismic profilescan be misleading, possibly leading to erroneous

Žreconstructions of depositional histories e.g., Hart.and Long, 1996 . The integration of 3-D seismic data

into sequence stratigraphic studies will help to re-duce these potential errors.

5.2. Limitations of 3-D seismic technology

Experience in the petroleum industry has shownthat, despite its general applicability, 3-D seismic

Ž .technology like any technology has its limitations.These limitations can influence how a survey iscollected, processed and interpreted.

There are areas where good quality seismic dataŽ .2-D or 3-D are impossible or very difficult toobtain. For example, velocity-related problems have,until recently, prevented geophysicists from obtain-ing clear subsurface images below salt bodies in theGulf of Mexico or beneath thrust sheets. New pro-cessing flows, for example, pre-stack depth migra-tion, are helping in some of these areas, however,there remain areas where seismic acquisition is notŽ .?yet feasible. Portions of North America’s PermianBasin region fall into this category. In some areas ofthis basin, unconsolidated Tertiary sediments overlieand bury a dissolution surface developed on a Per-mian aged salt zone. The thickness of the Tertiaryfill changes abruptly and there is a strong velocitycontrast between the fill and the underlying Paleo-zoic rocks. For this reason, much energy is scatteredat this contact and the implementation of certain keyprocessing steps becomes problematic. As such, it isnot possible to obtain useable images of much of thePaleozoic section.

In shallow earth applications, it is generally diffi-cult to obtain good quality seismic data from uncon-solidated or poorly consolidated soils that are abovethe water table. These, and some other settings, are

Žconsidered to be ‘‘lossy’’ media i.e., much energyis lost through attenuation as the acoustic pulse


.propagates where it may be difficult or impossibleto obtain interpretable seismic images.

In other areas, noise generated by waves, wind, orŽ‘‘cultural’’ features e.g., working pumpjacks, road

Fig. 17. Example showing the effects of seismic processing on data interpretability. The images show a common vertical transect throughtwo different versions of a 3-D seismic volume. Both data versions began with the same field data input, but different processing flows were

Ž . Ž .applied discussion and analysis of the processing differences is beyond the scope of this paper . The upper original image is difficult toŽ . Ž .interpret above 600 ms TWT , but after reprocessing lower image the stratigraphy and structure in that part of the section become clearer.

Ž .Conversely, the reprocessed volume lower has some of the higher frequencies removed, making stratigraphic details somewhat harder tointerpret in the lower part of the section.


traffic, electromagnetic emissions from power ca-.bles can cause low signal-to-noise ratios that make

data difficult to interpret. Source testing, whereindifferent types of source are tested to determinewhich provides the best combination of frequencyand energy characteristics for a particular applica-tion, and noise testing, looking at ambient and sys-tem noise levels, can be used to help design surveyacquisition parameters or even determine whether itis possible to collect usable seismic data.

Other concerns are related to acquisition parame-Ž .ters such as survey design , processing parameters,

the subsurface geology, non-uniqueness of the seis-mic response and, perhaps, the way that these ele-ments interact. For example, the acquisition footprintis an artifact characterized by patterns of noise in3-D data that are related to the geometric distributionof sources and receivers on the earths surfaceŽ .Marfurt et al., 1998 . This, and noise related to

Žother sources e.g., multiples, diffractions, low fold.areas , can obscure stratigraphic and structural fea-Ž .tures e.g., Hesthammer and Fossen, 1997b and

Ždisrupt seismic attribute studies e.g., Marfurt et al.,.1998 .

As illustrated in Fig. 17, choices made during theprocessing phase can significantly impact seismic

Ždata interpretability. Older seismic data sets both.2-D and 3-D are sometimes reprocessed using dif-

Žferent parameters to enhance interpretability e.g.,.Hesthammer and Fossen, 1997a . Processing can

affect the quality of the final data volume for anumber of reasons. Two of the more important as-pects include the experience of the processors in

Žworking with data from a particular area e.g., theremight be velocity problems or multiples that a pro-cessor with experience from that area might know

.how to handle , and the choice of processing algo-Žrithms often the better algorithms take more com-

.puter time and are therefore more costly .Assuming that the data set has been satisfactorily

acquired and processed, there are still aspects of theinterpretation phase that can affect the validity of theresults. The most obvious of these are the inter-preters capabilities and experience working with 3-Dseismic data and the software used in the interpreta-tion. Various types of pitfalls can confront even anexperienced interpreter. Velocity related problemsŽe.g., a horizontal layer might appear to be ‘‘pulled

up’’ on a seismic transect beneath a region that has.fast velocities are a common type of pitfall, and can

be most problematic when available velocity controlis limited and lateral lithologic changes and depthsare great. Depth migration converts the z axis of the

Žseismic volume from time to depth either pre- or.post-stack , but the quality of the result depends on

the accuracy of the velocity model used during themigration. Experience, and an understanding of theprinciples of geology and geophysics can help theinterpreter to watch out for these and other types ofinterpretation problems.

Finally, within the petroleum industry there isgeneral recognition of the limitations of 3-D seismictechnology, and these limitations need to be remem-bered if, or when, the technology is applied in otherfields. For example, in addition to the artifacts andpitfalls just described, practical limits on vertical andlateral resolution can make targets impossible toidentify in seismic data. Improper survey design andexcessive cost cutting during acquisition and pro-cessing have been known to lead to poor data qualityand failure in the petroleum industry. The geology ofan area and the project economics need to be charac-terized up front, in order to properly design a 3-Dsurvey or, indeed, to decide whether a 3-D seismicsurvey is worth acquiring. Likewise, although 3-Dseismic data can provide some valuable insightscompared to 2-D seismic or well data, it is onlythrough the integration of multidisciplinary data sets

Žand concepts e.g., pressures, borehole logs, core,.geochemical analyses that the full benefits of 3-D

seismic technology are realized. No matter howwidespread the technology has become in thepetroleum industry, economic, technical or other ob-stacles can cause 3-D seismic to be an impracticaltool for studying the subsurface. Overcoming theseobstacles will continue to be a topic of considerableinterest.

6. Conclusions

This summary has endeavoured to illustrate how3-D seismic technology is applied in the petroleumindustry and to suggest that similar approaches mightbe undertaken in other branches of the earth sci-ences. Although a 3-D seismic data volume providesa tremendous amount of information about the sub-


surface structure, stratigraphy and rock properties, itis only through integration of these geophysical datawith other geologic and engineering data and con-cepts that the true potential of the technology isunlocked. The quality and continuity of the subsur-face image obtained with a properly acquired 3-Dsurvey, combined with the flexible data visualizationand interpretation capabilities of interpretation soft-ware and data integration, help petroleum geoscien-tists to produce the world’s hydrocarbon resourcesmore economically and efficiently. These, or similarbenefits may be realizable in other applied and fun-damental branches of the geosciences.

Acknowledgements

The material presented in this paper is derivedfrom the author’s own published and unpublishedresearch, and from examples and concepts presentedin the literature. Geographic coordinates for some ofthe illustrations have been deliberately disguised oromitted to conserve the confidentiality of the data.Support for the author’s current research comes fromthe AdÕanced ReserÕoir Management Project of LosAlamos National Laboratory, the Southwest Sectionof the Petroleum Technology Transfer Council, andthe New Mexico Bureau of Mines and Mineral Re-sources. Data sets and technical guidance have beenprovided by Amoco, Ardent Resources, Cross Tim-bers Oil, Harvey E. Yates, Marathon, and SmackoOperating. Interpretation software has been providedto the New Mexico Institute of Mining and Technol-ogy by Landmark Graphics Corporation.

Appendix A. Glossary of some commonly usedterms in 3-D seismic interpretation

This Appendix provides definitions for some termsin 3-D seismic technology based on common usageby interpreters. Some of these terms have othermeanings in the field of reflection seismology.

Arbitrary liner transect — A vertical seismictransect through a 3-D seismic volume, the location,orientation and length of which is defined freely bythe interpreter.

Autotracking — Automated picking of a seismichorizon throughout a 3-D seismic volume based onseed points provided by the interpreter. Picking pa-rameters are set by the interpreter. This process isused to provide a continuous horizon pick morerapidly than could be achieved through manual pick-ing. Despite the time efficiency, results of autotrack-ing applications need to be quality checked by inter-preters, especially in areas of complex geology orpoor data quality.

Bin — A rectangular area in the x, y planeŽ .horizontal that is represented by a single seismictrace in a 3-D volume. Bin dimensions are deter-mined by acquisition parameters, and each bin canbe identified by a specific combination of line andtrace numbers.

Coherency attribute — An attribute defined bycomparing a seismic trace with its neighbours over asliding time window in order to numerically definethe lateral trace continuity at that location. Thisattribute is commonly used to define discontinuitiesthat can be due to faulting or stratigraphic featuresŽ .e.g., channel or reef margins . The term CoherencyCubee refers to a technology that has been patentedby Amoco, but other companies have developed

Ž .similar attributes most of which are proprietary .Complex trace attribute — A seismic attribute

Ž .e.g., instantaneous phase, instantaneous frequencythat is derived from the Hilbert transform.

( )Crossline trace — One of the two sequentiallynumbered orthogonal reference coordinates for 3-D

Ž .seismic surveys the other being the linerinline . Forland surveys, the crossline orientation is typically thedirection in which source lines were laid out.

Fault slice — Amplitudes extracted along theplane of a fault, and viewed projected onto a verticalplane.

( )Fold multiplicity — The number of field tracessharing a common midpoint that are stacked togetherduring data processing to produce a single trace inthe final data volume. All else being equal, thehigher the fold, the better the data quality. The foldmay not be constant throughout the entire area of a3-D survey.

Horizon — A seismic pick that typically corre-Žsponds to a particular stratigraphic level e.g., the top

.of a formation .


Horizon attributes — Attributes that are derivedfrom and define geometric properties of a picked,continuous horizon, such as dip, azimuth, edge de-tection, etc.

Horizon slice — Instantaneous amplitudes ex-tracted along a horizon and displayed in a map view.

( )Inline line — One of the two sequentially num-bered orthogonal reference coordinates for 3-D seis-

Ž .mic surveys the other being the tracercrossline .For land surveys, the inline orientation is typicallythe direction in which receiver cables were laid out.

ŽInterÕal attribute — A seismic attribute e.g.,.average frequency, average amplitude that is de-

rived for an interval that is defined either by twohorizons or a user selected time window definedwith respect to one horizon.

Migration — A seismic processing step which isused to reposition reflected energy to its true subsur-

Ž .face location thus, eliminating sideswipe , collapsediffractions and shrink the Fresnel zone. 3-D migra-tion produces a seismic image that is more accuratethan an equivalent 2-D image.

Multipanel display — A display that consists ofŽtwo or more contiguous vertical transects typically

.arbitrary lines through a 3-D seismic volume.Patch — In land 3-D seismic acquisition, a rect-

angular series of geophones that record reflectionsfrom a shotpoint that is typically located near thecenter of the patch.

PerspectiÕe display — A display that shows ob-jects from a seismic survey, typically interpretedhorizons and faults, in pseudo 3-D form. These

Ž .displays can be rotated i.e., viewed from any angleand are useful visualization tools for quality check-ing interpretations or presenting results.

Sideswipe — Reflected energy that comes fromobjects to the side of the vertical plane that isintended to be imaged in a 2-D seismic transect.Sideswipe is eliminated during 3-D migration.

Synthetic seismogram — Seismic traces gener-ated by mathematically convolving a seismic waveletwith a time series of reflection coefficients that has

Žbeen derived from well log data velocity and den-.sity logs . These ‘‘synthetics’’ are used to predict the

seismic response at a borehole location and thus tielog-derived geologic information to the seismic data.

( )Time lapse 4-D seismic — The use of differentvintages of 3-D seismic data covering a constant

area to monitor changes in subsurface conditions. Acommon example is the use of changes in seismicamplitudes through time to monitor changes in thelocation of an oilrwater contact that are due toproduction.

Timeslice — A slice through a 3-D seismic vol-ume at a constant TWT. Since subsurface velocitiesmay vary laterally, a constant TWT does not neces-sarily represent a constant subsurface depth.

Velocity surÕey — Determination of the subsur-face velocity field, usually by lowering a receiverdown a borehole to different depths, generating anacoustic pulse at the surface, then measuring thevertical traveltime to the receiver.

( )Vertical seismic profile VSP — A seismic pro-file that is collected in a manner somewhat analo-gous to a velocity survey, but with more recordingdepths. Longer recording times are analyzed in orderto detect reflected energy from subsurface interfaces,and not just first arrivals. Processing transforms the

Ž .raw data into seismic traces that: a show the seis-Ž .mic response in the vicinity of the borehole, b canŽbe directly tied to other borehole information e.g.,

. Ž .wireline logs , and c can be displayed in either timeor depth.

Voxel — A ‘‘volume element’’ defined by theŽ .bin size in the x, y plane and the sampling interval

Ž .in the z direction . For conventional 3-D seismicvolumes, each voxel stores a numerical amplitudevalue.

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Seismic Stratigraphy