January 1995

For help in preparation of this article, thanBiro, Geco-Prakla, Dallas, Texas; Adrian BBrook and Colin Hulme, Geco-Prakla, Galand; Helge Bragstad, Peter Canter, Olav LOdd Olav Vatne, Geco-Prakla, Sandvika, Chapman, Conoco Inc., Ponca City, OklahKim El-Tawil, Tom Neugebauer and Mike Geco-Prakla, Houston, Texas; Bill Fraser aton, Hunt Oil Company, Dallas, Texas; JakPer Helgaker, Hans Klaassen, Dietmar KluSchnellbacher, Tony Woolmer and Mike W

Imagine breaking your leg image won’t be ready for interpretation

for a year or more. Until re r delays. But thanks to breakthroughs

in acquisition, processing time—time from the first shot to the

beginning of interpretatio

Chris BeckettTim BrooksGregg ParkerHouston, Texas, USA

Robin BjoroyDominique PajotPaul TaylorGatwick, England

David DeitzUnocalLafayette, Louisiana, USA

Terje FlatenLars Jan JaarvikStatoilStavanger, Norway

Ian JackKeith NunnBP ExplorationStockley Park, England

Alan StrudleyRobin WalkerStavanger, Norway

Reducing 3D Seismic Turnaround

ro-D

ledas isg-hefit.is- inowny

aser-nddeci-ceeyer-ithing

ingona-

tion. Unlike 2D seismic, which grew fromthe exploration market into development,3D seismic has grown in the opposite direc-tion. Companies are discovering that earlyacquisition of 3D data reduces finding costsand overall project costs.2 Interpreted seis-mic data are essential for intelligent biddingon acreage. And some exploration contractsnow require a 3D survey before drilling.This expansion into exploration, along withdecreases in the cost of seismic acquisitionand processing, has raised demand for 3Dseismic data.

This increased demand has forced servicecompanies to reduce turnaround time—without sacrificing quality. This article looksfirst at the dramatic improvements in marineturnaround time, then at the steps beingtaken to significantly reduce turnaround intransition zone and land surveys.

The Marine StoryThree years ago, a marine survey of 500 km2

[193 sq miles] took a year or more to beacquired and processed. Today, through acombination of new technologies, turn-around time for similar surveys can be as lit-

1. For the purpose of this article, 3D turnaround time isdefined as the time from first shot to the end of pro-cessing. Some companies use the term “cycle time.”Oil companies include the survey planning beforeacquisition and the interpretation after processing,

o,

-

.

SEISMICS

ks to Garyligh, Scipiotwick, Eng-indtjorn and

Norway; Bill

and having an X-ray, only to be told that the

cently, seismic surveys suffered from simila

and communication, 3D seismic turnaround

n—has been reduced from years to weeks.

There are two main reasons oil and gas pducers worry about the time spent on 3seismic acquisition and processing, calturnaround time.1 First, in the oil and gbusiness, as in every business, timemoney. The more time spent on drilling, loging and well completion, the longer tdelay in production and the lower the proAdd the time to acquire and interpret semic data before drilling, and the delaybringing reserves to the surface may grbeyond the schedules and budgets of maproduction managers.

Second, and special to the oil and gbusiness, saving time can make the diffence between being able to do business anot. Development contracts worldwirequire oil companies to drill within a spefied time. The clock starts ticking onacreage is licensed. A 3D seismic survplanned, acquired, processed and intpreted in advance arms developers wtools for intelligent well placement, yieldhigher production from fewer wells.

More 3D seismic surveys are also becommissioned for exploration, in additito field development, their initial applic

Geco-Prakla, Hannover, Germany; Hal Harper, ConocMidland, Texas; David Etherington-Brown, JohannesHvidsten and Phil Selley, Geco-Prakla, Stavanger, Norway; Kristian Kolbjørnsen, Saga Petroleum, Sandvika,Norway; Bård Krokan, Norsk Hydro, Stabekk, Norway

23

oma, USA;Spradley,nd Bruce Hin-ob Haldorsen,ge, Clausorthington,

so their turnaround time is from decision to shoot toselection of drillsite. However, planning and interpre-tation are often outside the responsibility of servicecompanies, so they remain outside the definition used here.

2. Chisolm G: “Advances in Delivering 3D Data to Customers,” presented at the PETEX 94 meeting onTechniques For Cost-Effective Exploration & Produc-tion, London, England, November 16-18, 1994.

In this article, Charisma, Digiseis-FLX, LINK, Monowing,Olympus-IMS, TQ3D, TRILOGY, TRINAV, TRIPRO,TRISOR and Voyager are marks of Schlumberger. RISC6000 is a mark of International Business Machines Cor-poration. SPARCstation 20 is a mark of Sun Microsys-tems, Inc.

tle as nine weeks (above). Technologiesresponsible for this dramatic reduction varyfrom faster acquisition capacity to high-speed links with shore-based computers forreal-time, full-scale processing (left).

Today seismic vessels can acquire data 12times faster than they could in the early1980s, thanks to multielement acquisi-tion—multiple air gun sources, multiplereceiver streamers and even multiple ves-sels.3 Prior to 1984, vessels towed onesource array and one 3-km [1.9-mile]streamer (next page, bottom). This configu-ration evolved to two streamers and twosources per vessel by 1986, quadrupling thearea covered with each traverse, anddecreasing the cost per unit area. In 1990,streamer length started to increase, also

24 Oilfield Review

■■Concurrence ofthe three phases ofmarine turnaround—acquisition, navi-gation positioningand processing.Overall turnaroundhas been cut asindividual phaseshave been short-ened and allphases now occurconcurrently. Timecorresponds toturnaround for a500-km2 survey.

■■Geco Gamma towing six streamers. Inset graph shows reduction in 3D marine seismic turnaround for a 500-km2 survey.Turnaround data from smaller or larger surveys are scaled up or down, accordingly, for the purposes of this graph. The last eightsurveys, with dramatically lower turnaround, were processed with only a subset of the data. (Graph courtesy of BP Exploration.)

3. For reviews of the state of marine seismic acquisitionsix years ago: Backshall l, Donohue R, Jamieson G,Kilenyi T, Naylor R, Staughton D, and Walker C:“Marine Seismics in Cameroon,” Oilfield Review 1,no. 1 (April 1989): 26-34.Hansen T, Kingston J, Kjellesvik S, Lane G, l’Anson K,Naylor R and Walker C: “3-D Seismic Surveys,”Oil-field Review 1, no. 3 (October 1989): 54-61.

Aquisition

Positioning

Processing

Year

1987

1991

1993

1994

Time, weeks50403020100

Acquisition

Positioning

Processing

Surveys prior to 1992 1992 1993 1994

25

20

15

10

5

0

Mon

ths

decreasing costs. By 1991, there were twosources firing alternately to three streamers,and by 1992, there were four streamers. In1994, the Geco Gamma acquired theworld’s first survey with six streamers. Andin a continuing quest for greater capacity,contractors are now building or refurbishingseismic vessels to tow 8 to 12 streamers.

A challenge in designing vessels for multi-streamer acquisition is to keep all thestreamers uniformly separated while main-taining vessel speed. Streamers are sepa-rated with a deflector, which steers outerstreamers away from their normal streamlines (right). Most streamers follow angledslabs—paravanes—which deflect thestreamer outward, but also create drag onthe vessel. Each 3-km deflected streamermay exert up to 12 tons of drag, forcing thevessel to consume more fuel to maintainspeed. Eight to twelve streamers, with para-vanes deflecting the outer ones, would actlike a sea anchor, creating enough drag tostop an ordinary vessel. One contractor,PGS Exploration, is designing a more pow-erful vessel to address this problem.

Rather than design a larger, more expen-sive vessel to tow more streamers, Geco-Prakla has designed the Monowing deflector.Acting like an airplane wing flying through

25January 1995

■■Seismic vesseltowing six stream-ers with Monowingdeflectors (top).Monowing towingtechnology steersstreamers andreduces drag forincreased towingefficiency andsafety.

■■Single-streamer and six-streamer acquisition. Single streamer (left, side view) acquires data from a narrow swath beneath the vessel.Six streamers (right, front view) acquire six times as much data in a wide swath.

Monowing

Air gun arrays

water, this “lifts” the streamers apart, andresults in a 500% increase in lift-to-drag ratiocompared to conventional deflectors. Thereduced drag increases acquisition effi-ciency, and also safety. The lower tension inthe lead-in, or tow cables, between the ves-sel and the streamers, reduces the chance ofa tow cable snapping and flapping back tohit the vessel. And unlike other deflectors,orientation of the Monowing can be con-trolled remotely, to act as a rudder for thestreamer. This allows streamer spacing to becontrolled from the vessel, and permitsindividual streamers to be spooled in forrepairs. The Monowing deflector hasalready been deployed in the Irish Sea andWest Africa, to tow six streamers. It is being

tested with five streamers at extra-wide150-m [492-ft] spacing, making the 600-m[1980-ft] swath acquired in a single vesselpass the widest ever.

Streamers themselves have also beenupgraded. In earlier, analog streamers,hydrophones were wired to the streamercables and the analog signal transmitted upthe streamer and then digitized. There mayhave been signal leakage in the streamer, orcross-talk, in which a signal from onehydrophone gets mixed with that fromanother. With digital streamers, the signal isrecorded digitally so cross-talk is elimi-nated. Digital streamers are also more reli-able, resulting in less downtime and betterturnaround.

While multielement acquisition hasplayed the leading role in reducing acquisi-tion time, it has created a new challenge inreducing overall turnaround time. Data canarrive at a staggering 5 MBytes/sec andsome of it must be processed before thenext shot is fired—about every 10 seconds—if the processing is to keep pace. Rising tothe challenge is concurrent processing, acombination of onboard processing andhigh-speed communication with onshorecomputers and decision makers.

To achieve minimum turnaround time,two sets of data—source signature qualityand survey position—must be processedbetween shots. The source is a cluster of dif-ferent-sized air guns. On Geco-Prakla ves-sels the air guns are controlled by theTRISOR module of the TRILOGY integratedacquisition and processing system. Thismodule fires the air guns in a sequence thatis tuned to their sizes. As the size of the gunincreases, so does the time from firing tomaximum pressure. The TRISOR controllersynchronizes the guns’ pressure maxima,giving a stronger source signal.

TRISOR hardware also monitors sourceoutput to check the quality of each shot.

TRISOR sensors, located within one meterof the air guns, communicate with the ves-sel through fiber-optic connections, and arepackaged based on concepts from Anadrill’smeasurements-while-drilling (MWD) tech-nology. In this hostile environment, near ahigh-energy source and sustaining at least500,000 shocks per year, the rugged con-struction that ensures reliable MWD alsohelps reduce seismic turnaround.

To maximize vessel uptime, errors such asa gun going off at the wrong time, or not atall, must be detected immediately. Thenprocessing specialists can determinewhether the shot must be retaken, orwhether the recorded signal satisfies thegeophysical objectives of the survey. If thesignal is sufficient, time is saved. If insuffi-cient, time is still saved, because a seismicline can be quickly reshot while the vessel isstill over the survey area.

The second set of data that must be pro-cessed between shots is survey positioncoordinates, called navigation data. Naviga-tion data describe the position on the earthof every source and receiver point in the 3Dsurvey. The data come from relative positionmeasurements made with every shot as thevessel is in motion. The position of the ves-sel relative to satellites is determined usingthe Global Positioning System (GPS).4 Geo-graphic positioning with GPS is a relativelynew technique, more reliable and availablethan traditional radio positioning, and canfix locations to within two meters. The in-sea positions of the seismic sources andreceivers are computed using directionsfrom compasses mounted on the streamersand distance information—ranges—pro-vided by acoustic sensors and lasers dis-tributed in networks across the ends of thestreamers (left). The TRINAV module of theTRILOGY system collects the compass, laserand acoustic signals, detects transit times,processes them for range, computes the net-work node positions, calculates source andreceiver positions and stores the results in adata base before the next shot is fired. Thenumber of sensor data measurements—including compass data, laser ranges andbearings, satellite and radio position signals—used in such a calculation has grownfrom 15 in the days of single source andsingle streamer, to more than 350 now withdual sources and eight streamers (nextpage, bottom).

■■Front and tailpositioning net-works. Geographicpositions of everyseismic source andreceiver in the sur-vey are deter-mined using floatsinstrumented withGlobal PositioningSystems (GPS),acoustic rangemeasurements,compass data andbearings andranges from lasers.Streamer length isnot to scale.

Oilfield Review

4. For a review of applications of GPS: “Talking Satel-lites,” Oilfield Review 4, no. 4 (October 1992): 70-72.

5. For a review of 3D marine seismic processing: Boreham D, Kingston J, Shaw P and van Zeelst J: “3D Marine Seismic Data Processing,” OilfieldReview 3, no. 1 (January 1991): 41-55.

Source

Tailnetwork

3000-mdistance

Frontnetwork

Streamer

Float

Compass

Gyro

Hydrophone

26

N O R W A Y

Bergen

Stavanger

N O R T H S E A

Area ofsurvey

U. K.

N

■■Evolution of navigation dataturnaround. Since 1994, positioningdata can be fully processed onboard.

■■Location of 3D seismic reduced-turnaround pilot survey for Statoil, Sagaand Mobil. The vicinity of the 3D survey(red outline) had substantial previous 2Dcoverage (black lines).

■■Number of sensormeasurements usedin marine position-ing calculations fordifferent acquisitionscenarios. The cal-culation must bemade betweenshots—about everyten seconds—foronboard processingto keep pace withacquisition. Acqui-sition scenariosrange from 2D todual sources witheight streamers.

27January 1995

Checking that the positions fall within theproject specifications is a daunting task, andone whose automation has further reducedturnaround time. Until recently, this wasdone subjectively by navigation analysts,visually checking plots and position listings.Now, computed positions are qualityassured using position acceptance criteria(PAC), automating the time-consuming taskand slashing weeks off turnaround. The PACare established by comparing the range inquestion to the range of the last shot. If thetwo are within a predefined threshold, therange is accepted. Deviations are flagged bythe computer, making them easy to spot.

As recently as 1993, some contractorsmade range measurements during acquisi-tion and calculated rough initial positions,but waited until their return to shore to ver-ify the calculations and link—merge, in seis-mic-speak—the seismic data traces with thecorresponding source and receiver posi- tions. Three years ago, contracts typically

allowed six to eight weeks for this process,but a difficult job could take six months.Now, the final position data can be madeavailable in three hours (left).

While navigation data are being collectedand processed, the seismic traces are begin-ning their journey through data processing.Essentially any processing offered byonshore processing centers can be suppliedonboard. The entire processing chain is tooelaborate to detail here.5 But a few keysteps, and how they are being streamlinedto help reduce turnaround, are examined inthe following case study.

A Turnaround BreakthroughIn the summer of 1994, Statoil, in partner-ship with Saga and Mobil, conducted a 3Dturnaround pilot project in block 33/6 of the

Norwegian North Sea (above). The area hadalready been traversed with 2D lines. Theacreage covered in the 3D survey was anextension of a play concept that had provenprolific to the south—the oil basin containsthe Statfjord field, estimated at more than 3.5billion barrels of recoverable oil, and theSnorre field. The 33/6 area will be part ofconcession round 15, recently announcedby the Norwegian government. With thissurvey already acquired, processed andinterpreted, the oil companies, acting indi-vidually, can make better decisions abouthow to bid for acreage.

The goal of the pilot project was to turnaround the 313-km2 [120-sq mile] surveyin seven weeks. With conventional tech-nology, such a survey would take 18

1992 1993 19940

2

4

6

8

10

12

Year

Wee

ks

Navigation Processing Turnaround14

Navigation Sensor Data Per Shot

Sen

sor

read

ings

350

300

250

200

150

100

50

02x21x21x12D 2x2 2x3 2x4 2x5 2x6 2x6 2x73x3 2x8

*

*** = Two-vessel acquisition

First number is number of sources per vessel.Second number is number of streamers per vessel.

weeks: 6 for acquisition, then at leastanother 12 for processing. Executing sucha tightly constrained survey requires exactplanning. Survey design, acquisitionparameter selection and choice of process-ing chain were given special attention byStatoil and Geco-Prakla geophysicists. Inaddition to these standard steps, during theplanning phase it was recognized that tominimize turnaround time, both Statoil andGeco-Prakla would have to reevaluateaccepted working practices: Statoil agreedto hold decision-response time to 12hours, and Geco-Prakla agreed to increasecomputer and communication resourcesthat would allow more rapid acquisitionand processing.

The Geco-Prakla vessel, Geco Gamma,was equipped with the latest technology forthe job. Gamma had the TRILOGY systemfor onboard navigation and seismic data pro-cessing, and access to INMARSAT, the inter-national marine satellite system. Three IBMRISC 6000s were installed to handle the nearreal-time processing, reproducing the soft-ware and hardware of an onshore processingcenter. The data would travel directly fromthe acquisition system to the memory of theTRIPRO onboard processing system. Theplan called for crucial data to be transmittedvia satellite and land lines to the Statoiloffice in Stavanger, Norway, where a work-

28 Oilfield Review

■■Noise level of survey data, before (left) and after filtering (right). High-levelnoise related to bad weather appears as red and orange bands along sail lines.Noise concentrated in one area, but spanning several lines (yellow upper left), isgenerated by a change in subsea topography. After filtering (right), the noise isstill apparent, but within acceptable limits.

■■Examples of low-frequency (left)and high-frequencynoise (right) detectedwith onboard pro-cessing. Low-fre-quency noise iscaused by oceanswells during badweather. High-fre-quency noise iscaused by reverber-ations between seasurface and seabottom, enhanced at particular waterdepths.

6000

1000

0

2000

3000

4000

5000

Trace number Trace number

Two-

way

tim

e, m

sec

Low-frequency Noise High-frequency Noise

400 350 300

-128 1270

250 200 150 100 50

10

15

20

25

30

35

40

5

11

10

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Shot number400 350 300 250 200 150 100 50 1

Shot number

Amplitude

Sai

l-lin

e nu

mbe

r

Filtered Root Mean Square NoiseRaw Root Mean Square Noise

29January 1995

station was installed with the same process-ing and interpretation software.

The first shot was fired on June 22, 1994,with the vessel towing two air gun clustersand four 3000-m [9840-ft] streamers spaced75 m [246 ft] apart. The survey was 11 km[6.9 miles] wide and was completed in 38vessel passes, making 293 lines. Some ofthe first lines were shot in bad weather,which created low-frequency swell noise,above the tolerance level set in the presur-vey plan (previous page, top). When thatlevel is exceeded, many oil companieschoose to shut down acquisition, and thevessel stands by, at up to $30,000 per day,waiting for weather to calm. But onboardprocessing showed that the noise could befiltered out, though the filtering would haveto be done prestack (right).6 By monitoringsignal quality onboard, and processing theacquired, subspecification data in real time,Geco-Prakla geophysicists were able todecide that the processing scheme wouldtolerate the noisier data (previous page, bot-tom). This eliminated the need to reshootfive or six lines, saving $70,000. The savingspaid for the added cost of equipping thevessel with the RISC 6000s, and cut twodays off the turnaround.

Early in the planning, the team consideredundertaking onboard processing of reduced-fold data. But tests conducted prior toacquisition indicated that the reduced foldwould give inadequate imaging of subsur-face reflectors, so full, 30-fold data wereprocessed onboard (right).

One of the crucial phases of the surveywas the construction of the earth velocity

■■Testing effect of noise reduction after and before stacking. Stacked section ofunfiltered data (left) shows noisy portion near center. Filtering the section post-stack (middle) retains much of the same noise. Prestack filtering (right) cleans upthe noise and produces an acceptable stacked section.

■■Effects of fold—the number of tracessummed to create one stacked trace—onstack quality. In the survey design stage,Statoil and Geco-Prakla geophysicistsconsidered processing lower-fold data tospeed turnaround, but tests showed thatonly full-fold data would give acceptableresults. Stack processing run on test linesshows that 4-fold stacking gives low sig-nal-to-noise ratio and unclear reflections(top). Increasing the stack to 12-foldimproves the visibility of reflections, butdoes not adequately suppress reverbera-tions, called multiples, in the lower partof the section (middle). Full-fold, or 30-fold stacking, produces a high-qualitysection (bottom).

6. Stacking is the summing of traces with reflections thathave a common subsurface point. The number oftraces summed is called fold. Stacking reduces theamount of seismic data by a factor of the fold andincreases signal-to-noise ratio. Processing takes longerwhen performed on prestack data, because of thegreater data volume.

Two-

way

tim

e, m

sec

Unfiltered Stack Poststack Filtered Stack Prestack Filtered Stack

4500

4000

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600 550600 550 600 550Trace number Trace number Trace number

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600 800 1000 1200 1400

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e, m

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4-fold Stack

12-fold Stack

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model that would be used to stack and laterto migrate the data.7 Geco-Prakla geophysi-cists analyzed velocities on 18 seismic linesselected at 500-m [1640-ft] intervals, andtransmitted their results via satellite to Sta-vanger (above). Statoil geophysicists loadedthe data on workstations in their offices andworked weekends to monitor data qualityand relay decisions on the quality of thevelocity picks back to the vessel. A velocitymodel for the 3D volume was then builtonboard.

The last major step before stacking—3Ddip moveout processing (DMO)—was alsocompleted onboard for the 30-fold data.This process corrects for the reflection pointsmear that results when events from dippingreflectors are stacked (right). The final stackvolume was being built as soon as the lastshot was fired, and inline migration begunwhile the vessel was steaming back to port.

The computers and processing specialistswere flown to Stavanger, where the finalprocessing was completed three weeks later.Data quality was equivalent to that of a nor-mal onshore processing job, and no imme-diate reprocessing was scheduled. Sevenweeks after the first shot was fired, aCharisma workstation-ready tape was pro-duced, waiting to be interpreted (next page).8

Fasttracks and QuicklooksReduced-turnaround surveys are evolvingrapidly, and the amount of processing thatgoes into each survey varies.9 Specialistsdivide reduced-turnaround surveys into twocategories: fasttracks and quicklooks. Fast-tracks are fast, fully processed surveys, likeStatoil’s 33/6. Quicklooks are surveys thatprocess a subset of the full data set—calledlow-fold—or that simplify processing, suchas skipping dip moveout processing.

Quicklooks give interpreters a head starton interpretation, allowing earlier explo-ration or development decisions and identi-fying areas that deserve more detailed pro-cessing. BP Exploration has conducted foursuch surveys offshore Vietnam with Geco-Prakla, using onboard processing of naviga-tion, low-fold data and widely spacedstreamers to speed turnaround. In one case,BP had farmed into a prospect—taken overa license relinquished by another opera-tor—with only two years remaining. At thetime, the planned 3D survey would havetaken six months for full-fold processing,compared to 11 weeks for a low-foldinterim data cube. By getting the data ear-lier, BP interpreters were able to spend more

30 Oilfield Review

■■Onboard velocity picking and quality control. Stacking velocities computed by onboard processing are displayed as contours, thepeaks of which can be identified in an interactive velocity picking window (A, black squares). Picks from the previous location arewhite squares, and picks from the next location are pink squares. Seven time-velocity curves, called velocity functions, are plottedas black curves. The picked velocities, applied to one common midpoint gather before stacking, yield flat reflections (B). The sevenvelocity functions are applied to one gather, yielding seven panels. The velocities are correct when they give clear, flat reflectors (C).Overlaying the stacked section on a color plot of the velocity field provides a quality check: changes in velocity coincide with majorreflections (D).

■■Effect of dip moveout (DMO) processing.In the case of a dipping reflector, DMOprocessing is required to correctly posi-tion a reflection signal. DMO is appliedafter normal moveout (NMO) correctionand before migration (MIG). [Adaptedfrom Sheriff RE: Encyclopedic Dictionary ofExploration Geophysics. Tulsa, Oklahoma,USA: Society of Exploration Geophysicists(1991): 89.]

NMO

DMO

MIG

Source Midpointtrace Receiver

Zero offsettrace

Migratedtrace

Originaldata

NMO–Normal moveout correctionDMO–Dip moveout processingMIG–Migration

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pared. In the relatively constant marineenvironment, where every survey hasroughly the same sources, receivers, subsur-face and acquisition geometry, surveys ofdifferent sizes and from different areas canbe scaled up or down for the purposes ofkeeping statistics. However, on and nearland, every survey is different, andturnaround comparisons from one area toanother may be meaningless. The environ-ment may vary from swamp to arctic tundra,from desert to jungle. Sources, receivers andacquisition geometries come in as manycombinations as there are environments.But in spite of the absence of statistics, landand TZ turnaround are improving.

Paralleling improvements in marineturnaround, TZ and land surveys are seeingmore reliable acquisition hardware, fasteracquisition through multiple sources andmore receivers, and real-time verification ofsource and receiver positions. The followingtwo sections describe case studies—firsttransition zone, then land—to demonstratesome of the latest techniques to shortenturnaround.

31January 1995

■■Final 3D-migrated seismic data volume. The datacube is shown with a “chair” cut on a Charisma work-station. High-amplitude reflections are displayed inred and blue.

7. Migration is a processing step that uses earth velocity information to position reflections at theirtrue locations.

8. A Charisma workstation is one of GeoQuest’s seis-mic interpretation systems. For more information oninterpreting seismic data: James H, Tellez M, Schaet-zlein G and Stark T: “Geophysical Interpretation:From Bits and Bytes to the Big Picture,” OilfieldReview 6, no. 3 (July 1994): 23-31.

9. Hardy R and Haskey P: “The Changing Role of On-Board Processing,” paper B029, presented at the56th EAEG Meeting and Technical Exhibition,Vienna, Austria, June 6-10, 1994.Johnson DT, Bradshaw DG, Early RG and Done WJ:“Processing Marine 3D Seismic Data on Board Dur-ing Acquisition,” paper B028, presented at the 56thEAEG Meeting and Technical Exhibition, Vienna,Austria, June 6-10, 1994.Taylor P and Keggin J: “Onboard Processing Can BeDone,” The Leading Edge 13 (November 1994):1103-1105.Thornton RI, Reilly JM, Millard P and Johnson ML:“Real Time Offshore 3D Processing—A Case His-tory,” paper B030, presented at the 56th EAEG Meet-ing and Technical Exhibition, Vienna, Austria, June6-10, 1994.

10. Helical-scan magnetic tape—also known as VHS-format video tape—can store 25 GBytes on a car-tridge, and will soon be able to store 365 GBytes.

11. SINet is managed by Omnes, a joint venturebetween Schlumberger and Cable & Wireless.

Inline number

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3007 2759 2511 2263 2015 1767 1519 1271 1023

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time understanding the prospect before thespud date deadline.

Quicklooks can be considered preliminaryor intermediate results, with potential to ben-efit from later reprocessing. One example isa 700-km2 [270-sq mile] exploration surveyshot and processed onboard by Geco Reso-lution for Mobil in Papua New Guinea. Onlyportions of the survey were processed withfull fold, saving some of the explorationmoney for drilling and development.

Today, quicklooks and fasttracks alike arepossible only if the onboard processingsequence is nearly set in stone duringpresurvey planning with tests on prior 2Ddata. If acquisition conditions require pro-cessing modifications, some, such as noiseattenuation, can be accommodated duringthe survey.

Further reductions in turnaround willcome from improvements in all stages ofacquisition and processing. Geco-Praklaresearchers are looking into improved algo-rithms for navigation and seismic data pro-cessing. New, high-density data storagemedia now being introduced will mean

fewer tapes created, and speed data transferwherever tapes are required.10 The wideravailability of high-speed communicationlinks such as LINK 100, which enabled thefast turnaround of the Statoil 33/6 survey,will make shorter turnaround the normrather than the news. Geco-Prakla’s LINK100 telecommunication service uses verysmall aperture terminal (VSAT) satellite tech-nology to transmit data to office-based usersvia leased land lines or SINet, the Schlum-berger Information Network.11 However, thegreatest potential for improvement in 3Dturnaround, lies not in marine seismic, butin land and shallow-water, or transitionzone (TZ), environments.

The Onshore ChallengeToday, turnaround for 3D land and TZ sur-veys can be only unfairly compared withthat for marine surveys. The main differenceis in acquisition, which in some cases maytake 50 times longer on land than at sea.

There is also little formal data on thetrends in turnaround for land and TZ sur-veys, because no two surveys can be com-

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cable. Bay cable consists of a 1/3-in. [0.8-cm] diameter instrumented cable, two tothree miles long, that lies on the sea bottom.The cable can shift with currents, and canbe damaged by boat propellers and sharpcoral. While radiotelemetry avoids theseproblems, the added flexibility creates anew problem, synchronization: each unitmust record at exactly the same time. TheDigiseis-FLX system uses a patented syn-chronization method, achieving an accu-racy significantly higher than otherradiotelemetry systems.

Another innovation that contributes to thespeed of the survey is the method withwhich the source explosives and thehydrophones are emplaced. The tech-nique—ramming—is like using a hypoder-mic needle to inject a source or receiver intothe earth. Ramming sources in soft transitionzone cuts down on the time required to drill

Transition ZoneThe North Freshwater Bayou in southernLouisiana, USA, was the site of a 3D surveydemanding exceptional turnaround (right).The acreage covered leases operated byUnocal and Exxon. Unocal was drilling atthe time of the survey, and planned at leastone additional well. Drillers, heading for adeep target below 4.0 sec two-way traveltime, wanted to confirm the location of thetarget before reaching total depth. The chal-lenge was to complete acquisition betweenthe July 15 end of the alligator breeding sea-son and the October 15 start of duck migra-tion—a 13-week window of opportunity.

Survey planners designed a 79-sq mile[200-km2] survey to be processed in twophases. Processing began on an 18-sq mile[46-km2] priority area, while acquisitioncontinued over surrounding acreage.

The shallow-water environment allowedan all-hydrophone acquisition. Some TZ sur-veys cross the line between water and land,and require a combination of receivers—geophones on land and hydrophones in the

water. Processing such surveys takes extrasteps to account for the different responses ofthe various receiver types.

The hydrophones used in the North Fresh-water Bayou were attached to the Digiseis-FLX system, a new, flexible transition zoneacquisition system developed by Geco-Prakla (bottom). Each Digiseis-FLX dataacquisition unit (DAU) is a floating instru-mented tube, tethered to an anchor andconnected to four hydrophone groups (next

page, top). Up to 1536 channels have beenrecorded in real time without reaching thelimits of the system. This large number ofchannels allows for flexibility in arrangingsource-receiver combinations, often withoutmoving the DAUs. Seismic data are trans-mitted to the acquisition boat using radiofrequencies that can be adapted to avoidconflict with other radio activity.

The Digiseis-FLX system presents advan-tages over other TZ equipment, called bay

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■■Location of NorthFreshwater Bayou3D transition zone(TZ) survey.

■■Data acquisition units (DAUs). Each DAU consists of an instrumented tube, a squarefloatation pad and an antenna. DAUs are maintained and transported on the floatingbase camp.

source holes. On land, drilling crews typi-cally drill 100- to 180-ft [30- to 55-m] deepshot holes in advance of the acquisitioncrew. Equivalent results are obtained with40- to 50-ft [12- to 15-m] deep ram holes.Ramming not only takes less time, but it alsocosts less. Deep holes cost about $300 perhole to drill, while ramming costs about $75per hole. Ramming hydrophones to a uni-form depth of 20 ft [6 m] below sea levelresults in better receiver coupling and higherquality data. The main limitation of rammingis the restriction to unconsolidated earth.

Not all the North Freshwater Bayouturnaround speed came from fast acquisi-tion. Geometry verification—much likenavigation data processing in the marineenvironment—carried out in the field, cutweeks off the normal processing time.Geometry verification, a feature of the Voy-ager mobile data processing system, checksthat the source and receiver positionsattributed to every shot record are correct.Usually this is checked back at the officeafter acquisition has been completed andthe crew has left, but fixing errors after thefact is time-consuming. In some cases,entire land surveys have had to bereshot—a turnaround nightmare.

One error typically encountered in geom-etry verification is a mistake in the identifi-cation of shot-point location. This can occurwhen the source, say a vibrating truck (vibrofor short) is at the wrong location, can’t getto the right location, or if the location is mis-surveyed. It can also occur if receiver loca-

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■■Transition zonecrew deployingDAU from environ-mentally-friendlyair boat.

■■Floating basecamp. The campcan be towedbetween locations.Not having to dis-mantle and set upcamp every dayspeeds turnaround.

tions are missurveyed, or if the wrongreceivers are active.

These mistakes can be detected quickly byapplying some simple processing at the basecamp, after the day’s acquisition (left). Theprocess is called linear moveout, or LMO.LMO compares arrival times recorded for agiven source-receiver geometry to thoseexpected for the same geometry, assuming aconstant velocity subsurface. If the sourceand receivers are in the right places, the

LMO process yields seismic traces with firstarrivals aligned in time. Any other pattern offirst arrivals indicates a mistake in thesource-receiver geometry (below).

This technique was used in the Unocalsurvey to quickly verify geometry in thefield. Catching errors with the crew still onsite permits corrective action. Shot andreceiver locations can be resurveyed if nec-essary to revise the location data base.Without this field verification, errors may bedetected weeks or months later. Then, pro-cessing specialists would have to test severalpossible geometries in hopes of discoveringwhat really happened, spending time andadding uncertainty. Verifying the geometryin the field saves up to four weeks in theoffice.

With much of the time-consuming workout of the way, the computing center pro-ceeded with the rapid disk-to-disk process-ing on a Sun SPARCstation 20. The fully pro-cessed 3D cube was ready three weeks afteracquisition, in time for interpreters to use.

Interpretation of the seismic volume sig-naled drillers that their target would be pro-ductive. Unocal interpreters were able touse the seismic data to confirm the qualityof their next well location and plan at leastone additional deep well at greater than20,000 ft [6090 m].

Reducing Turnaround on LandThree-dimensional surveys on landencounter many of the same difficulties asin transition zones, with the added prob-lems of access, topography and extremetemperatures. All of these make for longeracquisition campaigns and more difficultprocessing. Under fair marine conditions,multielement acquisition can collect morethan 75 km2 [29 sq miles] per day. Underextreme land conditions, such as −40° C[−40° F] arctic surveys, acquisition may pro-ceed at less than 1 km2 [0.4 sq mile] perday. Land surveys of 1500 km2 [586 sqmiles] have taken up to 41/2 years for acqui-sition. The potential for improvement inland 3D turnaround is undisputed.12

In land surveys more than other types,presurvey planning is the key to minimizingturnaround.13 Time spent planning anddesigning is more than compensated bytime saved acquiring data. With a given setof equipment, say a certain number of geo-phones and people, one plan might achieve150 to 200 shots a day, while a suboptimalplan with different shot and receiver linespacing may collect only 100 shots a day.

The most time-consuming tasks in acqui-sition—be they laying out receivers, drillingshot holes, repairing damaged cables oradvancing to the next vibro location—must

be identified and minimized to reduceturnaround. In the following examples of3D land surveys in Texas, such bottleneckswere identified during presurvey planningand circumvented in novel ways.

Rough Terrain TurnaroundThe Val Verde basin in Texas, USA is at theedge of the Sierra Madre mountains thatextend north from Mexico (next page,bottom). The basin is a hot play for gas, withsome wells in the region producing morethan 7 MMcf/D. The terrain is extremelyrough, with steep-edged mesas and incisedcanyons (next page, top). Several 3D sur-veys in the area have contributed to thecontinuous improvement of field operatingprocedures.

In one case, Conoco joined forces withHunt Oil to acquire the Geaslin survey in thesummer of 1994. Both companies had ashort fuse: they had to evaluate their leasesand make decisions for an early 1995 drilldate. The survey design specified the num-ber and location of shot points, but the shortturnaround and high cost ruled out dynamiteas a source, because too much time wouldbe taken to drill shot holes. Vibro sourceswere available—four vibrating trucks at12.5-m [41-ft] spacing constitute onesource—but the terrain presented mind-bog-gling logistics: in some cases it would takefour hours for a vibro trip up and down amesa (next page, middle). The solution wasto use two sets of buggy vibros, or eight inall, similar to a dual-source marine survey.14

While one set was shaking in the valley, theother set would work its way up a mesa.Similar dual-source vibro operations havebeen extremely successful in desert areas,such as Egypt and Oman, where there are noobstructions. In this case they allowed acqui-sition of 60 sq miles [153 km2] in 65 days.

As in all land jobs, darkness presents toomany hazards, so the crew operates onlyduring daylight hours. Evenings were wellspent, though, running geometry verificationon the day’s acquired data. One of the goalsof the next shift was to have that day’sgeometry checked and attached to the seis-mic traces, usually by midnight. That way,geometry problems could be fixed the nextday, before the receivers were moved.

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■■Field processing for source and receiver geometry verification. Linear move-out (LMO) processing, applied immediately after the day’s shooting, detectedan error in the position of the shot fired to four receiver lines, as indicated bywarped first arrival times (top). The next day, the shot point was resurveyed,and the new location input to LMO processing. The flat arrival times indicatecorrect geometry (bottom).

12. Jack I and Nestvold W: “3D Seismic—The NextStep,” Keynote Address at PETEX 94 meeting onTechniques For Cost-Effective Exploration & Produc-tion, London, England, November 16-18, 1994.

13. For a review of 3D seismic survey planning: AshtonCP, Bacon B, Mann A, Moldoveanu N, Déplanté C,Ireson D, Sinclair T and Redekop G: “3D SeismicSurvey Design,” Oilfield Review 6, no. 2 (April1994): 19-32.

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■■Buggy vibrator source—vibro for short.Four such trucks shake in series to createa single source. Each vibro weighs50,000 lbs [22,700 kg], is 30 ft [9 m] longand 10 ft [3 m] wide.

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■■Location of 3D land surveys Val VerdeCounty, Texas.

■■Rough terrain of Geaslin survey. The challenge of movingequipment on and off mesas was met by use of two sets ofvibrator sources.

What’s Coming to LandKeeping track of all the information perti-nent to a land survey is often the most time-consuming job, and steps are being taken toshorten it and make fuller use of all theinformation available. The Olympus-IMSinformation management system, now inuse by Geco-Prakla in Germany, is designedto do just that.

The Olympus-IMS system colocates in asingle data base the many types of data thatmust be handled in a land survey. Previ-ously, every type of data had its own database: the planned survey layout, the actualsurveyed receiver and source point loca-tions, shot hole drilling data, shootingschedule data and the recorded seismictrace data were handled by different soft-ware. The new integrated system minimizesthe number of data handling steps, reducingerrors and improving turnaround. The sys-tem will also link directly with processingsoftware to allow field processing for geom-

Processing the data from the Geaslin sur-vey proved to be a great challenge. ValVerde basin is notorious for bad data. High-velocity carbonates near the surface deflectmuch of the source energy away fromdeeper layers; receiver and source couplingto the surface varies with location; and therugged relief introduces high residual stat-ics—differences in seismic travel timethrough surface topography. After fourmonths of testing and processing, including3D DMO and migration, the processing wascomplete. The next step is interpretation, inpreparation for a possible 1995 drill date.

In the nearby Brown Bassett survey forMobil, acquisition time was further short-ened by the use of helicopters to movecables, recording boxes and geophones upand down the mesa and canyon walls.Three hundred “helibags”—net bags fortransporting material—helped the crewcomplete the 60-sq mile [153-km2] acquisi-tion in significantly less time than usual.

etry verification and further processingsteps. The Olympus-IMS system will beavailable in Australia and Texas by the mid-dle of 1995.

Further improvements in land turnaroundwill come from improvements in hardwareand communication. In the most adverseconditions, a good crew may spend as littleas two to three hours shooting out of tenspent in the field. In these circumstances, asmall amount of time spent trouble-shoot-ing equipment faults can have a consider-able impact on turnaround. Geco-Praklaengineers are developing more reliablehardware, to reduce the amount of timespent looking for and repairing flaws in geo-phones, cables and connectors. Today, eachreceiver point marked on a map consists ofup to 72 individual geophones, whose sig-nals are combined to yield a less noisy sig-nal at a central location, or source point(below). Up to 140,000 geophones willhave to be repeatedly picked up, put down

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■■Typical patterns for receiver and source arrays. When geophysicists talk about a receiver or source position,they nearly always mean the central position of an array of receivers or sources. Arrays are designed to atten-uate surface noise. Up to 72 receivers can be arrayed around the central position, and up to 20 individualsource positions can be summed to make one source point.

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and maintained in the course of a 3D sur-vey. Efforts are also underway to find newways to acquire the same amount and qual-ity of data with fewer receivers, cutting sur-vey time.

Improved communications will also cutturnaround time. Increased use of GPS isdecreasing the time spent surveying posi-tions for land source and receiver points.Surveying with GPS is faster and easier tocheck than traditional theodolitic surveying,and leaves less room for human error. Plac-ing GPS units on vibro sources helps keeptrack of actual source locations and reduceslocation error.

For arctic land surveys, snow streamershave been developed in collaboration withNorsk Hydro as substitutes for hand-placedgeophones in an effort to increase acquisi-tion efficiency. Geco-Prakla engineers havetested snow streamers in six programs,acquiring 1200 km [750 miles] of 2D data.Efforts are also underway to minimize envi-ronmental impact, which in arctic environ-ments must be included as part ofturnaround—a single drop of oil spilledmust be recovered before the crew moves.15

Connecting land crews via satellite toSINet, the Schlumberger Information Net-work, will give better day-to-day contactwith office bases, speeding equipment andsupply requests and allowing interactionwith processing centers. The first such satel-lite link has been made in Venezuela, andothers are planned.

Moving more processing to the field willfurther reduce turnaround for both land andtransition zone surveys. Parameter testing,noise attenuation and velocity picking canbe done with today’s field processing tools.But full concurrent processing, as performedin marine surveys, is still a dream for land.Land acquisition, more so than marine, is athree-dimensional problem: sources are notaligned with receiver lines, and more time isneeded to acquire enough seismic traces toprocess one part of the 3D volume. At best,processing through to stacking could lagacquisition by a few weeks, but the difficulttask of computing residual statics beforestacking cannot begin until all the data arein. Advances may come from taking a newview of 3D land surveys—planning, acquir-ing and processing with a truly three-dimen-sional view—rather than simply repeating aseries of two-dimensional snapshots.

The Role of Integrated Services in Reducing TurnaroundMarine, TZ and land 3D surveys are sure tofind further turnaround improvement in thecommon ground of integrated services. In anintegrated-service survey, planning, acquisi-tion, processing and project managementare delivered by one service company. Tradi-tionally, the oil company plans the survey,then one contractor acquires the data andanother processes it. Time is wasted transfer-ring data and responsibility between parties.

Geco-Prakla has developed an integratedservice for 3D surveys called TQ3D—TotalQuality 3D. Larger in area than most sur-veys, TQ3D projects can cover leased andopen blocks. A TQ3D project may be oper-ated from 100% proprietary to 100% nonex-clusive, or anywhere in between. Dataacquired on a proprietary basis become theproperty of the operator. Large projects caninvolve several operators. Data acquired ona nonexclusive basis become the property ofGeco-Prakla, and may be licensed.

The turnaround improvement achievablethrough integrated services is remarkable. Amixed proprietary-nonexclusive TQ3D forBP in UK block 47/10 was started and com-pleted in November 1994. Geco Topazacquired the 230-km2 [89-sq mile] survey inthree weeks. While full-fold data were beingacquired, a 20-fold data volume was par-tially migrated onboard, and processing wascompleted onshore. Processed data weresent to the GeoQuest Data Services groupvia SINet, and converted to Charisma work-station format. Total project time was fourweeks. Thirty-four such marine surveys havebeen completed, and 21 more are inprogress, covering a total of 43,000 km2

[16,800 sq miles].Integrated services are also reducing land

survey turnaround. Land surveys, with theirdifficult logistics, benefit from the approacha committed team brings to a project. Inaddition to survey design, acquisition andprocessing, land surveys require obtainingpermission to access an area from thosewho own and live on the land. The projectcan run more smoothly when a single con-tractor coordinates every phase. One suchproject in Africa turned around a 50-km2

[20-sq mile] survey in seven months, fromplanning through installation of processeddata onto an interpretation workstation. Twoother projects are in the survey design stage.

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15. For more on arctic surveys: Meyer H, Read T,Thomas J, Wedge M and Wren M: “EnvironmentalManagement in the Arctic,” Oilfield Review 5, no. 4(October 1993): 14-22.

For marine, transition zone and land 3Dsurvey turnaround, the journey is not fin-ished, but the direction is clear. Marine sur-veys are in the lead, having made tremen-dous progress in the last three years byconverting acquisition, positioning and pro-cessing to a set of parallel tasks. Somemarine surveys that would have taken 10years to acquire and process using 1980stechnology are now completed in months.Some say marine turnaround is no longer anissue, that any marine survey can now beturned around within any explorationist‘stime constraint.

Land and transition zone surveys, whilelagging their marine counterparts, havemade inroads with field processing, innova-tive sources and survey designs that opti-mize available equipment. These and furtherimprovements will contribute to minimizingturnaround time, allowing oil companies tospend less time waiting for information andmore time using it. —LS

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