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taken into account. This article investigatesthe objectives and methods of seismic sur-vey design and reviews field examples ofstate-of-the-art techniques.

The ideal 3D survey serves multiple pur-poses. Initially, the data may be used toenhance a structural interpretation based ontwo-dimensional (2D) data, yielding newdrilling locations. Later in the life of a field,seismic data may be revisited to answerquestions about fine-scale reservoir architec-ture or fluid contacts, or may be comparedwith a later monitor survey to infer fluid-front

movement. All these stages of interpretationrely on satisfactory processing, which in turnrelies on adequate seismic signal to process.The greatest processing in the world cannotfix flawed signal acquisition.

19April 1994

Theres more to designing a seismic survey than just choosing sources and receivers and shooting away. To

get the best signal at the lowest cost, geophysicists are tapping an arsenal of technology from integration of

borehole data to survey simulation in 3D.

3D Seismic Survey Design

For help in preparation of this article, thanks to JackCaldwell and Greg Leriger, Geco-Prakla, Houston, USA;Mandy Coxon and Dominique Pajot, Geco-Prakla,Gatwick, England; Jacques Estival, Elf Petroleum Nigeria,Lagos, Nigeria; Dietmar Kluge, Geco-Prakla, Hannover,Germany; Lloyd Peardon, Schlumberger CambridgeResearch, England; Lars Sonneland, Geco-Prakla,Stavanger, Norway; and Tim Spencer, British Gas,Reading, England.

Appreciation is expressed to Qatar General PetroleumCorporation (QGPC) for its consent to the release of data.

QUAD-QUAD is a mark of Geco-Prakla. TWST(Through-Tubing Well Seismic Tool) is a mark of Schlum-berger.

1. For the most recent worldwide figures:

Riley DC: Special Report Geophysical Activity in1991, The Leading Edge12, no. 11 (November1993): 1094-1117.

2. Personal communication: Thor Sinclair.

C. Peter AshtonMrsk Olie og Gas AS

Copenhagen, Denmark

Brad BaconAngus MannNick MoldoveanuHouston, Texas, USA

Christian DplantElf AquitainePau, France

DickiIresonThor SinclairGatwick, England

Glen RedekopMaersk Oil Qatar ASDoha, Qatar

nsn Cost of marine 3Dseismic surveys forone oil company.Since 1990, the costof a marine 3D sur-vey has decreasedby more than 50%.(Courtesy of Ian Jack,

BP Exploration, Stock-

ley Park, England.)

Increased efficiency has brought the cost ofmarine three-dimensional (3D) seismic datato its lowest level ever, expanding the popu-larity of 3D surveys (above). In the past fiveyears, oil companies have increased expen-ditures on seismic surveys by almost 60%,to $2.2 billion.1 However, an estimated10% of surveys fail to achieve their primaryobjectivesome because the technologydoes not exist to process the data, somebecause the surveys are improperlyplanned.2 Careful planning can result inmore cost-effective acquisition and process-

ing, and in data of sufficient quality to bene-fit from the most advanced processing.

But before the first shot is fired or the firsttrace recorded, survey designers must deter-mine the best way to reveal the subsurfacetarget. As basics, they consider locationsand types of sources and receivers, and thetime and labor required for acquisition.Many additional factors, including health,safety and environmental issues, must be

Dollars,

inthousands

Cost of Marine 3D Seismic Survey per km2

40

35

30

25

20

10

5

0

15

1990 1991 1992 1993

Year

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20

nsn Temporal andspatial aliasingcaused by sam-

pling less thantwice per cycle.Temporal aliasing(top)occurs wheninsufficient sam-

pling renders a 50-Hz signal and a200-Hz signal indis-

tinguishable(arrows representsample points). The50-Hz signal is ade-quately sampled,but not the 200-Hz.(Adapted from Sheriff,

reference 4.)Spatialaliasing(bottom)occurs whenreceiver spacing ismore than half thespatial wavelength.With minor aliasing(left)arrivals can betracked at near off-sets as time

increases, butbecome difficult tofollow at far offsets.With extreme alias-ing(right)arrivalseven appear to betraveling back-wards, toward nearoffsets as timeincreases. (Adaptedfrom Claerbout, refer-

ence 6.)

nsn Better stacking from a wide and evenly spaced set of offsets.Reflection arrival times from different offsets are assumed to fol-low a hyperbola. The shape of the hyperbola is computed fromthe arrivals. Traces are aligned by flattening the best-fittinghyperbola into a straight line, then summed, or stacked. Perfectalignment should yield maximum signal amplitude at the timecorresponding to zero offset. A wide range of evenly spaced off-

sets gives a better-fitting hyperbola, and so a better stack.

200 Hz50 Hz

Time, msec

0 8 16 24 32

Temporal Aliasing

Stackingvelocity

+ =

Hyperbolic

moveout

Offset

Two-way

time

Offset

CMP gather CorrectedCMP gather

StackedCMP trace

+ + =

Elements of a Good Signal

What makes a good seismic signal? Process-ing specialists list three vital require-mentsgood signal-to-noise ratio (S/N),high resolving power and adequate spatialcoverage of the target. These basic elements,along with some geophysical guidelines (seeGuidelines from Geophysics, page 22),form the foundation of survey design.

High S/N means the seismic trace hashigh amplitudes at times that correspond toreflections, and little or no amplitude atother times. During acquisition, high S/N isachieved by maximizing signal with a seis-mic source of sufficient power and directiv-ity, and by minimizing noise.3 Noise caneither be generated by the sourceshot-generated or coherent noise, sometimesorders of magnitude stronger than deep seis-mic reflectionsor be random. Limitationsin the dynamic range of acquisition equip-ment require that shot-generated noise beminimized with proper source and receiver

geometry. Proper geometry avoids spatialaliasing of the signal, attenuates noise andobtains signals that can benefit from subse-quent processing. Aliasing is the ambiguitythat arises when a signal is sampled lessthan twice per cycle (left). Noise and signalcannot be distinguished when their sam-pling is aliased.

A common type of coherent noise thatcan be aliased comes from low-frequencywaves trapped near the surface, called sur-face waves. On land, these are known asground roll, and create major problems forprocessors. They pass the receivers at a

much slower velocity than the signal, andso need closer receiver spacing to be prop-erly sampled. Planners always try to designsurveys so that surface waves do not con-taminate the signal. But if this is not possi-ble, the surface waves must be adequatelysampled spatially so they can be removed.

During processing, S/N is enhancedthrough filters that suppress noise. Coherentnoise is reduced by removing temporal andspatial frequencies different from those ofthe desired signal, if known. Both coherentand random noise are suppressed by stack-ingsumming traces from a set of source-

receiver pairs associated with reflections ata common midpoint, or CMP.4 The source-receiver spacing is called offset. To bestacked, every CMP set needs a wide andevenly sampled range of offsets to define thereflection travel-time curve, known as thenormal moveout curve. Flattening thatcurve, called normal moveout correction,will make reflections from different offsetsarrive at the time of the zero-offset reflec-tion. They are then summed to produce astack trace (left). In 3D surveys, with the

Two

-waytime

Increasing offset

Minor Aliasing Extreme Aliasing

Increasing offset

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advent of multielement marine acquisi-tionmultistreamer, multisource seismicvesselsand complex land acquisitiongeometries, reflections at a CMP come froma range of azimuths as well as a range ofoffsets (right).5 A 3D CMP trace is formed bystacking traces from source-receiver pairswhose midpoints share a more or less com-mon position in a rectangular horizontal

area defined during planning, called a bin.The number of traces stacked is calledfoldin 24-fold data every stack trace rep-resents the average of 24 traces. Theoreti-cally, the S/N of a survey increases as thesquare root of the fold, provided the noise israndom. Experience has shown, however,that for a given target time, there is an opti-mum fold, beyond which almost no S/Nimprovement can be made.

Many survey designers use rules of thumband previous experience from 2D data tochoose an optimal fold for certain targets orcertain conditions. A fringecalled the fold

taper or haloaround the edge of the sur-vey will have partial fold, thus lower S/N,because several of the first and last shots donot reach as many receivers as in the centralpart of the survey (below, right). Getting fullfold over the whole target means expandingthe survey area beyond the dimensions ofthe target, sometimes by 100% or more.Many experts believe that 3D surveys do notrequire the level of fold of 2D surveys. Thisis because 3D processing correctly positionsenergy coming from outside the plane con-taining the source and receiver, which in the2D case would be noise. The density of data

in a 3D survey also permits the use of noise-reduction processing, which performs betteron 3D data than on 2D.

Filtering and stacking go a long waytoward reducing noise, but one kind ofnoise that often remains is caused by multi-ple reflections, multiples for short. Multi-ples are particularly problematic wherethere is a high contrast in seismic propertiesnear the surface. Typical multiples are rever-berations within a low-velocity zone, suchas between the sea surface and sea bottom,

21April 1994

nsn Reflections from source-receiver pairs bounce in a bin, a rectan-gular, horizontal area defined during planning. In a 3D survey aCMP trace is formed by stacking traces that arrive from a range ofazimuths and offsets(top). The distribution of offsets is displayed ina histogram within each bin(bottom). The vertical axis of the his-togram shows the amount of offset, and the horizontal axis indi-cates the position of the trace in offset.

nsn A fold plot showing 40-fold coverage over the heart of the survey.The edge of the survey has partial fold because several of the firstand last shots do not reach as many receivers as in the central partof the survey.

3. Directivity is the property of some sources wherebyseismic wave amplitude varies with direction.

4. For a full description of terms used in seismic dataprocessing see Sheriff RE: Encyclopedic Dictionary ofExploration Geophysics. Tulsa, Oklahoma, USA: Soci-ety of Exploration Geophysicists, 1991.

5. Streamers are cables equipped with hydrophonereceivers. Multistreamer vessels tow more than onereceiver cable to multiply the amount of data acquiredin one pass. For a review of marine seismic acquisitionand processing see Boreham D, Kingston J, Shaw Pand van Zeelst J: 3D Marine Seismic Data Process-ing, Oilfield Review3, no. 1 (January 1991): 41-55.

1 2 3

4 5 6

1 2 3

4 5 6

Offsets and Azimuths in a CMP Bin

Offset DistributionSource ReceiverBin

130

160

190

220

250

Shotpoint number

130 160 190 220

Fold

3

7

11

14

18

22

25

29

33

36

40

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nsn Seismic section with strong multiple noise. Multiples canappear as a repetition of a shallower or deeper portion of theseismic image. [Adapted from Morley L and Claerbout JF: Predic-

tive Deconvolution in Shot-Receiver Space,Geophysics 48 (May 1983):515-531.]

Guidelines from Geophysics

1. Normal moveout stretch is the distortion in wave-shape caused by normal moveout correction.

Many of the rules that guide 3D survey design are

simple geometric formulas derived for a single

plane layer over a half-space: the equation

describing the hyperbola used in normal moveout

correction is one example. Others are approxima-

tions from signal processing theory. Sometimes

survey parameters are achieved through trial and

error. The following formulas hold for some sim-

ple 3D surveys:

Bin size, xy, is calculated to satisfy vertical

and lateral resolution requirements. For a flat

reflector, bin length,x, can be the radius of the

Fresnel zone or larger. The Fresnel zone is the

area on a reflector from which reflected energy

can reach a receiver within a half-wavelength of

the first reflected energy. For a dipping reflector

where Vrm s is the root mean square average of

velocities down to the target, fmax is the maxi-

mum nonaliased frequency required to resolve

the target, and is the structural dip. Normally

y= x.

3D fold is determined from estimated S/N of

previous seismic data, usually 2D. 3D fold must

be greater than or equal to

where Rf is the radius of the Fresnel zone and dx

is the CMP interval in the 2D data.

Maximum offset, Xmax, is chosen after consid-

ering conflicting factorsvelocity resolution,

normal moveout stretch and multipleattenuation.1 For a velocity resolution v/ v

required to distinguish velocities at time T,

where fis fmax fmin, or the bandwidth. As Xmax

increases,v/vincreases, or improves. But with

long offsets, normal moveout stretch increases

and multiples can become worse.

or between the earths surface and the bot-tom of a layer of unconsolidated rock(below, left). Multiples can appear as laterarrivals on a seismic section, and are easy toconfuse with deep reflections (left).6 Andbecause they can have the same character-istics as the desired signalsame frequencycontent and similar velocitiesthey areoften difficult to suppress through filtering

and stacking. Sometimes they can beremoved through other processing tech-niques, called demultiple processing, butresearchers continue to look for better waysto treat multiples.

The second characteristic of a good seis-mic signal is high resolution, or resolvingpowerthe ability to detect reflectors andquantify the strength of the reflection. This isachieved by recording a high bandwidth, orwide range of frequencies. The greater thebandwidth, the greater the resolving powerof the seismic wave. A common objective ofseismic surveys is to distinguish the top and

bottom of the target. The target thicknessdetermines the minimum wavelengthrequired in the survey, generally consideredto be four times the thickness.7 That wave-length is used to calculate the maximumrequired frequency in the bandwidthaverage seismic velocity to the targetdivided by minimum wavelength equalsmaximum frequency. The minimum fre-quency is related to the depth of the target.Lower frequencies can travel deeper. Someseismic sources are designed to emit energyin particular frequency bands, and receiversnormally operate over a wider band. Ideally,

sources that operate in the optimum fre-quency band are selected during surveydesign. More often, however, surveys areshot with whatever equipment is proposedby the lowest bidder.

Primaryreflection Ghost

Near-surfacemultiples

Long-pathmultiple nsn Multiple reflec-

tions. After leav-ing the source,seismic energycan be reflected anumber of timesbefore arriving atthe receiver.

22

x=Vrms

4fmaxsin ,

Xmax= 2Tv2

f vv

,

2D fold xy2Rfdx

,

Time,sec

Seafloor reflection

Seafloor multiple

Seafloor multiple

Primary reflection

Multiple

Multiple4.0

3.0

2.0

1.0

0

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Another variable influencing resolution issource and receiver depthon land, thedepth of the hole containing the explosivesource (receivers are usually on the surface),and at sea, how far below the surface thesources and receivers are towed. Thesource-receiver geometry may produceshort-path multiples between the sources,receivers, and the earth or sea surface. If the

path of the multiple is short enough, themultiplesometimes called a ghostwillclosely trail the direct signal, affecting thesignals frequency content. The two-waytravel time of the ghost is associated with afrequency, called the ghost notch, at whichsignals cancel out. This leaves the seismicrecord virtually devoid of signal amplitudeat the notch frequency. The shorter the dis-tance between the source or receiver andthe reflector generating the multiple, thehigher the notch frequency. It is important tochoose a source and receiver depth thatplaces the notch outside the desired band-

width. It would seem desirable to plan asurvey with the shallowest possible sourcesand receivers, but this is not always optimal,especially for deep targets. On land, short-path multiples can reflect off near-surfacelayers, making deeper sources preferable. Inmarine surveys, waves add noise and insta-bility, necessitating deeper placement ofboth sources and receivers. In both cases,survey design helps reach a compromise.

The third requirement for good seismicdata is adequate subsurface coverage. Thelateral distance between CMPs at the targetis the bin length (for computation of bin

length, see Guidelines from Geophysics,previous page). Assuming a smooth hori-zontal reflector, the minimum source spac-ing and receiver spacing on the surfacemust be twice the CMP spacing at the tar-get. If the reflector dips, reflection points arenot CMPs (above, right). Reflected wavesmay be spatially aliased if the receiver spac-ing is incorrect. A survey designed with goodspatial coverage but assuming flat layersmight fail in complex structure. To recordreflections from a dipping layer involvesmore distant sources and receivers thanreflections from a flat layer, requiring expan-

sion of the survey areacalled migrationapertureto obtain full fold over the target.

In general, survey planners use simpletrigonometric formulas to estimate optimalCMP spacing and maximum source-receiveroffset on dipping targets. As geophysicistsseek more information from seismic data,making the technique more cost-effective,simple rules of thumb will no longer pro-vide optimum results. Forward modeling of

seismic raypaths, sometimes called raytracemodeling, provides a better estimate of sub-surface coverage, but is not done routinelyduring survey planning because of cost andtime constraints. An exception is a recentevaluation by Geco-Prakla for a survey inthe Ship Shoal South Addition area of theGulf of Mexico (page 31).

Balancing Geophysics with Other

Constraints

Acquiring good seismic signal is expensive.On land or at sea, hardware and labor costsconstrain the survey size and acquisition

time. The job of the survey planner is to bal-ance geophysics and economy, achievingthe best possible signal at the lowest possi-ble cost.8 On land, source lines can bealigned with receiver lines, or they can be atangles to each other. Different source-receiver patterns have different cost and sig-nal advantages, and the planner must

nsn Effect of reflector dip on the reflection point. When the reflector isflat(top)the CMP is a common reflection point. When the reflectordips(bottom)there is no CMP. A dipping reflector may requirechanges in survey parameters, because reflections may involvemore distant sources and receivers than reflections from a flat layer.

6. Claerbout JF: Imaging the Earths Interior. Boston,Massachusetts, USA: Blackwell Scientific Publications(1985): 356.

7. This is the criterion for resolving target thickness visu-ally. By studying other attributes of a seismic tracesuch as amplitude or signal phase, thinner layers canbe resolved.

8. Survey design and survey planning are sometimesused interchangeably, but most specialists prefer tothink of planning as the part of the design process thatconsiders cost constraints and logistics.

Horizontal Reflector

Dipping Reflector

Shotpoint

Receiver

23April 1994

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Theoretical Grid

Final Grid

Random Technique

Source

Receiver

Source line

Receiver line

Checkerboard Pattern

Brick Pattern

Zigzag Pattern

Receiver

Source

choose the one that best suits the survey(right). Once a survey pattern is selected,subsurface coverage can be computed interms of fold and distribution of offset andazimuth. If the coverage has systematicholes, the pattern must be modified.iIn com-plex terrain, planned and actual surveysmay differ significantly (left).9

Land acquisition hardware can cost $5

million to $10 million for recording equip-ment and sourcesusually vibrating trucksor dynamitebut labor is the major surveycost. Cost can be controlled by limiting thenumber of vibrator points or shotpoints, orthe number of receivers. But limitingreceivers limits the area that can be shot atone time. If a greater area is required,receivers must be picked up and moved,increasing labor costs. The most efficientsurveys balance source and receiverrequirements so that most of the time isspent recording seismic data and not wait-ing for equipment to be moved. Land prepa-

ration, such as surveying source andreceiver locations and cutting paths throughvegetation or topography, must be includedon the cost side of the planning equation. Incountries where mineral rights and land sur- nsn Common source-receiver layouts for land

acquisition. The checkerboard pattern(top), sometimes called the straight-line orcross-array pattern, is preferred when thesource is a vibrator truck, because itrequires the least maneuvering. The brick

pattern, (middle)sometimes called stag-

gered-line, can provide better coverage atshort offsets than the checkerboard, but ismore time-consuming, and so costlier. Thezigzag pattern(bottom)is highly efficient inareas of excellent access, such as deserts,where vibrator trucks can zigzag betweenreceiver lines.nsn Planned versus actual surveys. A survey planned in West Texas,

USA(top, left)calls for a checkerboard of receiver lines(blue)andsource lines(red). The actual survey shot(bottom, left)came veryclose to plan. Other cities present acquisition challenges. A surveyin Milan,iItaly(right)used a random arrangement of sources andreceivers. (Adapted from Bertelli et al, reference 9.)

24 Oilfield Review

face rights are separately and privately held,such as in the US, landowners must givepermission and can charge an access fee.Other constraints that can affect surveyplanning include hunting seasons, per-mafrost, population centers, breeding sea-sons, animals migrating or chewing cables,

and crops that limit vibrator source trucks tofarm roads.

Marine survey planners consider differentconstraints. Hardware is a major cost;sources and recording equipment are a siz-able expense, but additionally, seismic ves-sels cost $35 to $40 million to build, and

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tens of thousands of dollars per day to oper-ate. Sources are clusters of air guns of differ-ent volumes and receivers are hydrophonesstrung 0.5 m [1.6 ft] apart in groups of up to48, on cables up to 6000 m [19,680 ft]long. Sources and receivers are almostalways towed in straight lines across the tar-get (below, right), although other geometriesare possible. Circular surveys have been

acquired with sources and receivers towedby vessels running in spirals or concentriccircles.10 Geco-Praklas QUAD-QUAD sys-tem tows four receiver cables and foursource arrays simultaneously, acquiring 16lines at a time. Currents and tides can causethe long receiver cables to deviate by calcu-lable amountsup to 30from the towingdirection. Spacing between shotpoints is afunction of vessel speed, and can be limitedby how quickly the air guns can recover fullpressure and fire again. Access is usuallylimited only by water depth, but drillingrigs, production platforms and shipping

lanes can present navigational obstacles.Environmental constraints also influencemarine surveys: the commercial fishingindustry is imposing limits on location of,and seasons for, marine acquisition.11 Forexample, planning in the Caspian Sea mustavoid the sturgeon breeding season or seis-mic surveys would wipe out caviar produc-tion for the year.

Transition zonesshallow water areashave their own problems, and require spe-cialized equipment and creative planning.12

Transition zones are complex, involvingshorelines, river mouths, coral reefs and

swamps. They present a sensitive environ-ment and are influenced by ship traffic,commercial fishing and bottom obstruc-tions. Survey planners have to contend withvarying water depths, high environmentalnoise, complex geology, wind, surf andmultiple receiver typesoften a combina-tion of hydrophones and geophones.

One thing all surveys have in common isthat planning must be done quickly. The

clock starts ticking once acreage is licensed.Exploration and development contractsrequire oil companies to drill a certainnumber of wells, spend a certain amount ofmoney, or shoot a certain amount of seis-mic data before a given date. There is oftenlittle time between gaining approval toexplore or develop an area and having todrill. In some cases, oil companies plan

every detail of the acquisition before puttingthe job out to bid. In other cases, toincrease efficiency, oil companies and seis-mic service companies share the planning.In many cases, service companies plan thesurvey from beginning to end based onwhat the oil company wishes to achieve. Inthe quest for cost savings, however, seismicsignal is often compromised.

Cost-Effective Seismic Planning

How would 3D seismic acquisition, pro-cessing and interpretation be different if alittle more emphasis were given to surveydesign? Geco-Praklas Survey Evaluationand Design team in Gatwick, England, hasshown that by taking a bit more care, signalcan be improved, quality assured and costoptimized simultaneously. There are three

parts to the process as practiced by Geco-Praklaspecification, evaluation and design(next page). Specification defines the surveyobjectives in terms of a particular depth ortarget formation, and the level of interpreta-tion and resolution required. The level ofinterpretation must be defined early; data tobe used solely for structural interpretationcan be of lesser quality, leading to lower

25April 1994

nsn Marine acquisi-tion geometryshowing seismicvessels looping inoblong circuits.The length ofstraight segments iscalculated fromfold plots, and mustinclude additionallengthrun inand run outtoallow cable tostraighten after

each turn.

9. Bertelli L, Mascarin B and Salvador L: Planning andField Techniques for 3D Land Acquisition in HighlyTilled and Populated AreasTodays Results andFuture Trends, First Break11, no. 1 (January 1993):23-32.

10. Hird GA, Karwatowski J, Jenkerson MR and Eyres A:3D Concentric Circle SurveyThe Art of Going inCircles, EAEG 55th Meeting and Technical Exhibi-tion, Stavanger, Norway, June 7-11, 1993.

11. Gausland I: Impact of Offshore Seismic on MarineLife, EAEG 55th Meeting and Technical Exhibition,Stavanger, Norway, June 7-11, 1993.

12. Petersen C, Brakensiek H and Papaterpos M:Mixed-Terrain 3D Seismics in the Netherlands,Oilfield Review 4, no. 3 (July 1992): 33-44.

Bin

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V

SP

Logsor

1DModels

2Dor3D

SurfaceSeismic

DataType

Process or Output

Source signaturefor various depths

Target wavelet

Bandwidth at target

Mute, stack,fold tests

Means toDetermine Parameters

Parametersto be Determined

Maximum frequenciesattainable

Resolution attainable

Estimate spatial andtemporal resolution

Establish noisemechanisms

Near trace offset

Useful offset withtime, stack andS/N relationship

Reflection responseof target

Identificationof multiples origin

Noise levels

Shooting direction

Synthetic shots

Migration aperture

Long-offset analysis

Normal incidence

stacks

Statics model

Signal-to-noise ratio

Noise records

Amplitude versustime plots

VSP processing

Source modeling

Apply losses tosource signatures

Build geological2D model andapply appropriatetarget wavelet

Analysis of2D syntheticCMP gathers

Analysis of existingsurface seismic

Analysis ofmigrationrequirements

Define surveyobjectives

Specification

Evaluation

No

YesNo Yes

Planning

Resolutionanalysis

Operational,cost and safety

constraints

Resolution, noise

and coverageanalysis

Source,templateand array

design

Objectivesachieved?

Prospectdescription

Requiredequal

obtainable?

Obtainable

geophysicalparameters

Design

Final surveydesign

Analysis ofexisting data

Preferredsurvey

parameters

Requiredgeophysicalparameters

Loss modeling

Frequencydependent losses

Primary/multiplevelocity discrimination

Required streamer length

Stack fold, offset and

group length foroptimum multiplemoveout discrimination

Crossline spacing

Spatial frequency

Spatial resolution

Group interval

Shotpoint interval

Migration aperture

Shooting direction

Record length

Migration ofsynthetic

zero-offset data

Migration ofexisting 2D data

FK plots, filter tests

Refraction velocities(near surface)

Ambient noiseestimation

Source peak amplitude

Peak-to-bubble ratio

Source volume

Source depth

Modeled section

SyntheticCMP gathers

costs, compared to data used for strati-graphic interpretation, analysis of amplitudevariation with offset (AVO) or seismic moni-toring.13 Specification quantifies the geo-physical parameters needed to meet theinterpretation objectives: frequency contentand signal-to-noise ratio of the recorded sig-nals, and spatial sampling intervalthefamiliar requirements for good signal.

Evaluation of existing data, which can bedone independently and concurrently, tellswhich geophysical parameters are obtain-ablesometimes different from those stipu-lated by specification. The types of dataevaluated include logs, vertical seismic pro-files (VSPs) and 2D or existing 3D data.Existing data can provide models for simu-lating the effects of the geophysical parame-ters on new seismic data. If the requiredparameters are not obtainable, the surveyobjectives are reexamined, or respecified.The loop is repeated until a set of geophysi-cal parameters is found that is both desired

and obtainable.In the third step, design, the geophysicalparameters are weighed against other con-straints. Keeping in mind the understandinggained from evaluation of existing data, sur-vey planners select the source and receiverconfiguration and choose the shootingsequence and type of seismic source. Thesepreferred survey parameters are tempered bycost, safety and environmental constraints.

26 Oilfield Review

nsn Survey evaluation and design scheme.

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nsn Tests with dyna-mite sources at dif-ferent depths.Traces recordedfrom the shot at 28m [92 ft](left)showless low-frequencynoisegroundrollthan from theshot at 9 m (right).In general, the

deeper the source,the less ground rollgenerated.

nsn Original roll-along geometry proposed forElf Petroleum Nigeria survey. Four receiverlines would be laid at 300-m intervals. Eachline would have 144 receivers with 50-mspacing. Shots would be fired at 50-m inter-vals in a line perpendicular to the receiverlines, and then the four receiver lines wouldbe rolled along to the next position.27April 1994

13. For a review of AVO see:

Chiburis E, Franck C, Leaney S, McHugo S and Skid-more C: Hydrocarbon Detection With AVO, Oil-field Review5, no. 1 (January 1993): 42-50.

For more on seismic monitoring see:

Albright J, Cassell B, Dangerfield J, Deflandre J-P,Johnstad S and Withers R: Seismic Surveillance forMonitoring Reservoir Changes, Oilfield Review6,no. 1 (January 1994): 4-14.

14. Source patterns are groups of dynamite charges inseparate holes at the same depth, fired simultane-ously. The goal is to cancel low-frequency noise thattravels laterally, called ground roll.

300 m

Receiver

Source

Putting Planning into Practice

In 1991 Elf Petroleum Nigeria Limited putout for tender a 160-km2 [62-sq mile] landsurvey in the Niger Delta. Working with theSeismic Acquisition Service of Elf AquitaineProduction in Pau, France, the Survey Eval-uation and Design group evaluated sourcesand geometries for optimal acquisition. Theprimary target is the structure of the Ibewa

oilfield at 3500 m [11,480 ft], at or below 3sec two-way time, with secondary deeperobjectives. Signal-to-noise requirements,based on previous experience, suggestedthe data should be 24-fold. Resolution ofthe target required signal bandwidth of 10 to60 Hz and 25 m by 25 m [82 ft by 82 ft]bins. The source was specified to be dyna-mite, which would be fired in shotholesdrilled and cased or lined to 25 m, againbased on previous experience. Constraintson the survey included the high populationdensity, potential damage to personal prop-erty and the many oil pipelines that cross

the area. A roll-along acquisition patternsimilar to a checkerboard was suggested inthe bid, with four receiver lines to be movedas the survey progressed (below, right).

Evaluation of existing data2D seismiclines and results from seismic sourcetestswarned of potential problem areas.Source tests compared single-source dyna-mite shots to source patterns, and tested sev-eral source depths.14 The tests indicated thepresence of ghost notches at certain depths,leading to a reduction in signal energywithin the desired frequency band of 10 to60 Hz (above, right). The source tests also

indicated source patterns were ineffective incontrolling ground roll in this prospect area.Deployment of the source at 9 m [30 ft]gave a good S/N ratio at 25 to 60 Hz, butproduced very high levels of ground roll.Deployment of the source below 40 m [130ft] gave a good S/N ratio from 10 to 60 Hzand low levels of ground roll. However,such deep holes might be unacceptablytime-consuming and costly.

Evaluation of existing 2D lines revealedthe frequency content that could be

Time,sec

Minimal ground roll

Shot Depth 28 m Shot Depth 9 m

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nsn Filtered 2D datashowing frequencycontent variationwith depth. Each

panel has been fil-tered to allow a dif-ferent band of fre-quencies, called the

passband, to pass.As the passbandrises, the maximum

depth of penetrationof seismic energydecreases. Lowerfrequencies(left)

penetrate deeper.Higher frequencies(right)do not propa-gate to deeper lev-els. At the targetlevel of 3.0 sec thereis still some 50 Hzenergy left.

expected from seismic data in the area(above). Resampling along the 2D line atthe sampling interval planned for the 3Dsurvey confirmed that the 50-m [165-ft]receiver and shot spacings initially recom-mended were appropriate. Fold-reductionsimulations performed on the 2D sectionsshowed that 24-fold would be appropriatefor the survey. However, a brick patternwould give better fold and offset distributionthan the roll-along pattern, potentiallyimproving the survey results. The brick pat-tern would also reduce the lateral offset

between source and receiver line, thusreducing the potential for ground roll arriv-ing at the same time as the reflection fromthe target and making the ground roll easierto handle in processing.

The complete survey evaluation anddesign took two months and reached thefollowing conclusions.1. A target bandwidth of 10 to 60 Hz is a

reasonable acquisition objective.2. Placement of sources deeper than 40 m

would avoid complex processing prob-lems and high levels of ground roll in the3D data set. If logistics prevent locatingthe sources at this depth, then a fallbackdeployment of sources at 9 m wouldmeet the target bandwidth criterion withminimal notching but higher levels of

ground roll. Field quality control shouldverify there is no notch between 10 and60 Hz.

3. A 144-trace brick pattern with 300-m[984-ft] receiver line spacing and 300-mshot line spacing would give the best off-set distribution.

4. Shot and receiver intervals should be nomore than 50 m.

Drilling 40-m holes for each source locationwas deemed impractical. Optimizing costsand logistics, the company obtained satis-factory results with a 24-m [79-ft] sourcedepth, single-shot dynamite, and brickwork

acquisition pattern.Evaluation and design can be different in

the marine setting. A case in point is the AlShaheen location in offshore Qatar, underdevelopment appraisal by Maersk Oil QatarAS, according to an agreement with QatarGeneral Petroleum Corporation (QGPC).Maersk Oil had only eight months to design

and acquire a 3D survey that would providea 25 km2 [9.6 sq mile] image, requiringabout 49 km2 [18.8 sq mile] of full fold data,and to spud a vertical developmentappraisal well. Given the tight scheduleprocessing alone normally takes a yearMaersk Oil contracted a survey evaluationand design study based on existing VSPs and2D surveys. This study was more extensivethan the previous example, with more pre-existing data, particularly well data.

The objective of the 3D survey was toproduce a stratigraphic image of the

Kharaib limestones and a thin 13- to 15-ft[4- to 4.6-m] thick overlying oil-filled sand.The seismic data were to be analyzed forporosity-related amplitude variations alongwith small-scale faulting and fracturing tohelp in planning the trajectory of future hor-izontal wells. The acquisition vessel hadalready been contracted, limiting the seis-mic source to a 1360- or 1580-in.3 [22,290-or 25,900-cm3] air gun.

Evaluation of existing data indicated areaswhere special care had to be taken toensure a successful survey. For example,high-velocity beds at the seafloor promised

to cause strong multiples, reducing theenergy transmitted to deeper layers and

28 Oilfield Review

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leading to strong reverberations in the waterlayer. A bandwidth of 10 to 90 Hz wasrequired to resolve the thin sands above thetarget and the small faults within it.

Evaluation of existing borehole dataoffered valuable insight into the transmis-sion properties of the earth layers above thetarget and the geophysical parameters thatcould be obtained at the target. Comparisonof formation tops inferred from acoustic

impedance logs with reflection depths onthe two VSPs allowed geophysicists to dif-ferentiate real reflections from multiples.Identification of the origin of multiplesallowed the acquisition and processingparameters to be designed to minimize theireffect. Analysis of the amplitude decrease ofthe VSP downgoing first arrivals quantifiedtransmission losses (right). Bandwidth stud-ies on the VSPs showed that frequencies inthe 80- to 100-Hz range were present andbeing reflected at the depth of the target(above). This meant the frequencies requiredfor thin-bed resolution might be obtainable

by the 3D survey.The study also looked into quantifying the

seismic resolution of small-scale faulting(next page, top) and analyzed five different nsn Vertical seismic profile (VSP) traces(left)analyzed for amplitude loss with depth(right).Amplitudes of first arrivals recorded in a 92-level VSP are calibrated with amplitudes of asurface reference signal to account for changes in source amplitude from level to level.The amplitude ratio from one level to the next is plotted in decibels (dB). One dB is 20times the log of the amplitude ratio. An amplitude ratio of 100 is equivalent to 40 dB.Amplitudes expected from a surface seismic survey would normally be 3 dB less thanthose from a VSP, and scaled by a reflection coefficient.

nsn Bandpass filters on VSP data showing energy present up to 80 to 100 Hz at target.Each panel passes a different band of frequencies. Coherent energy up to 80 to100 Hz reflects from the survey objective at 0.8 sec.

29April 1994

Measuredd

epth,

ft

Levelnumber

Time, sec Amplitude loss from surface, dB

8875

7950

7025

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3325

2400

9800

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nsn Resolution of thin beds and small-scale faulting. Each panel shows the modeledresponse of a seismic wave of 48-m [160-ft] wavelength()to a different vertical fault dis-

placing a series of thin beds of thicknesses 12 m, 24 m and 36 m. From left to right, faultswith 3-m [10-ft], 6-m [20-ft], 12-m [40-ft] and 24-m [80-ft] throws correspond to/16, /8,/4and/2, respectively. A fault throw of at least 12 m, corresponding to/4, can beresolved quantitatively. At less than that, existence of a fault can be detected, but itsthrow resolved only qualitatively. nsn A time slice fromMaersk Oil Qatar3D cube showingfractures and faults.

energy sources, source and streamer depth,spatial sampling and minimum and maxi-mum offsets. Some of the early 2D lineswere reprocessed to evaluate migrationrequirements and techniques for removingmultiples.15 Five recommendations wereoffered for survey acquisition:1. A target frequency of 90 Hz is a reason-

able objective and can achieve the

desired resolution.2. Multiples reverberating in the water willcreate severe problems. Offsets longerthan about 1000 m [3280 ft] may not beuseable because they will contain multi-ples indistinguishable from the targetsignal.

3. Of the available sources, the 1580-in.3

source would be preferred to the 1360-in.3 source because of its higher energyoutput at the important higher frequen-cies. This, however, is subject to theability of the larger source to be cycledat a 12.5-m [41-ft] shotpoint interval.

4. Receiver intervals of 12.5 m and shot-point intervals of 12.5 m should suffi-ciently sample the signal and theexpected noise, allowing further reduc-tion of noise during processing. Theseintervals provide sufficient fold toachieve the desired S/N within the 10- to90-Hz bandwidth.

5. Because the primary reflection and multi-ples cannot be discriminated by differ-ences in their velocities, stacking maynot adequately attenuate multiples.Additional demultiple processing maybe necessary.

All the survey design recommendationswere implemented except the larger source,which for technical reasons could not betowed as planned.

The survey acquired superb data. MaerskOil Qatar drilled the vertical well on timeand based on interpretation of the new seis-mic data, spudded two horizontal wellsone with a 10,200-ft [3120-m] long horizon-tal section. The 3D data show fine-scalefaulting and two fracture sets (left). Faultlocation prediction based on interpretationof the 3D data was confirmed during

30 Oilfield Review

Two-waytime,sec

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3-m throw 6-m throw 12-m throw 24-m throw

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thick

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drilling. Faults with throws as little as 8 to 10ft [2.5 to 3 m] interpreted in the seismic datawere verified by on-site biostratigraphicevaluation of the reservoir limestones.

In addition to these two surveys, Geco-Prakla has conducted more than 30 othersurvey evaluation and design studies, some-times with surprising results. In one case,analysis of tidal currents led the team to pro-

pose a change of 120 in shooting direction,which would add $150,000 to the process-ing cost, but cut 45 days and $1,500,000 offthe acquisition cost, for a savings of $1.35million. In another study, analysis of previ-ous seismic data showed that coherent shot-generated noise was aliased at shot intervalsof 37.5 m [123 ft]. Although it wouldincrease acquisition and processing costs, adenser shot interval of 25 m would samplethe noise sufficiently to allow removal dur-ing processing. The 37.5-m shot spacingwas used in the survey, giving data thatrequired extra prestack processing costs,

which did not entirely eradicate the noise.In a study with Schlumberger TechnicalServices in Dubai, UAE, data from a VSPacquired just before a marine 3D surveyhelped optimize planning.16 In a deviatedproduction well near the center of the sur-vey, a slimhole TWST Through-Tubing WellSeismic Tool was run through tubing to thereservoir to record shots fired from the seis-mic source to be used in the 3D survey. Theshot records allowed geophysicists to deter-mine the effects at the depth of the target ofsource parameters such as air-gun volume,depth and pressure. The records also

showed that at far offsets, high amplitudeshear waves contaminate the traces. With ashorter receiver cable, a better survey wasacquired in less time, and so for lower cost,than originally planned.

For the Future

Some of the advances to be made in 3D sur-vey design have origins in other fields. VSPdesign routinely models seismic raypathsthrough complex subsurface structure, butrarely does surface seismic design accountfor structure. Despite considerable sophisti-cation in 3D data processing, most 3D sur-vey design assumes plane layer geometry inthe subsurface to calculate midpoints andtarget coverage. But to estimate subsurfacecoverage adequately in complicated struc-

31April 1994

nsn Raytrace modeling showing strong changes in reflection paths through salt. Traces thatwould have a common midpoint in a flat-layered earth no longer bounce in the samebin. Salt, with its ability to deform and its high seismic velocity, creates complex structureand strong refraction, or ray bending.

nsn Ship Shoal South Addition in the Gulf ofMexico.

15. Migration, sometimes called imaging, is a processingstep that rearranges recorded seismic energy back tothe position from which it was reflected, producingan image of the reflector.

16. Poster C: Taking the Pulse of 3D Seismics, MiddleEast Well Evaluation Review, no. 13 (1992): 6-9.

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T E X A S L O U I S I A N A

Ship ShoalSouth Addition

G U L F O F M EX I C Okm

miles0 100

0 161

ture, survey designers recognize the need to

model raypaths, and some are beginning todo this. Geco-Prakla has used raytracemodeling to determine coverage in a surveyto image below salt in the Ship Shoal SouthAddition in the Gulf of Mexico (left).

Salt introduces large contrasts in seismicvelocity, bending and distorting seismic raysalong complex paths (top). Survey designersanticipated that a super-long receiver cablewould be required to provide adequate cov-erage of the subsalt layers. They tested vari-ous cable lengths by shooting raypathsthrough a geologic model derived from 2D

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seismic data (above). Surprisingly, a stan-dard 5425-m [17,794-ft] cable providescoverage similar to that of the proposed8075-m [26,500-ft] cable.

Another advance may come through inte-gration of survey design with acquisition,processing and interpretation into a singlequality-assured operation. The aim is tomaximize cost-effectiveness of the overallseismic survey, to supply quality-assuredprocessed data with minimum turnaroundtime and optimal cost. Within Geco-Prakla,this idea is called Total Quality 3D, or

TQ3D. Such surveys may be acquired on aproprietary (exclusive) or a speculative(nonexclusive) basis, or a combination ofthe two. For example, 75% of a 700-km2

[271-sq mile] TQ3D survey in the southernUK continental shelf will be delivered as

proprietary data to three oil companies. Theremaining 25% is nonexclusive, andalthough sponsored in part by the currentplayers in this area, the data will also beavailable to new players.

Defining the objectives of a TQ3D surveycan be a difficult process. Rather than haz-arding a guess at which reflectors in an areaare the sought-after targets, Geco-Praklaplanners involve proprietary and nonexclu-sive clients at early stages of the project.Over open acreage they examine a database of nonexclusive 2D seismic surveys to

learn about the targets.Choosing acquisition parameters that will

be optimal over the entire survey is also achallenge. It is not always practical to followall the recommendations proposed by a sur-vey evaluation and design study, but a judg-ment can be made of the impact that anydecision will have on the quality of the data.Then, other options can be explored. For

example, in a recent TQ3D survey, steeplydipping reflectors in 20% of the area wouldhave been optimally sampled if the receiverspacing had been reduced from 25 m to 20m [66 ft], but the 25% additional cost wasunacceptable to clients. Having flagged thisas an area where data quality could beimproved, attention will be paid to process-ing that may help imaging of steep dips.

As oil companies and service companiesstrive for efficiency and acquisition of high-quality, cost-effective seismic data, moreemphasis is being placed on survey design.

The other pieces of the seismic puzzleacquisition, processing and interpreta-tionhave all benefited from advances intechnology, and survey design is followingthe trend. Through powerful modeling andintegration of log, VSP and surface seismicdata, 3D survey design will become thefoundation for all that follows. LS

32 Oilfield Review

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12,000 16,000 20,000 24,000 28,000nsn Raytrace modeling to optimize cable length. Refraction through salt may mean a longercable is required to image structure below. Two cable lengths, 8075 m (top)and 5425 m(bottom)were tested using the model on the previous page. Surprisingly, in this case bothcables give similar coverage of subsalt horizons.