16 Oilfield Review

Raising the Standards of Seismic Data Quality

Phil ChristieDavid NicholsAli ÖzbekCambridge, England

Tony CurtisLeif LarsenAlan StrudleyGatwick, England

Randall DavisHouston, Texas, USA

Morten SvendsenAsker, Norway

For help in preparation of this article, thanks to Mark Egan,Olav Lindtjorn and Steve Morice, Gatwick, England; andPeter Canter, Leendert Combee, James Martin and Nils Lunde, Asker, Norway. Special recognition to all themembers of the Receiver, Positioning and Central

Seismic data just got better, thanks to a group of engineers and geophysicists who

developed the world’s most advanced marine seismic acquisition system. The clarity

of the new images has to be seen to be believed.

In the last 20 years, the oil and gas industry hasbenefited from remarkable advances in seismictechniques. Where once surveys covered a two-dimensional sliver of the subsurface, they nowilluminate three-dimensional volumes. Marineacquisition that began with a single cable of sen-sors in tow now involves deployment of an arrayof streamers covering an area the size of a golfcourse. Marine and land surveys are prepro-cessed onboard or in the field, reducing dataturnaround from years to weeks. Multi-component seabottom cables record compres-sional and shear waves for analysis of reservoir

lithology and fluid content. Sophisticated dataprocessing and improved computing capabilitiesallow geophysicists to extract images from noto-riously difficult settings such as complex faultzones, below salt and beneath shallow gas.Time-lapse recordings help scientists understandand track changes in reservoir fluids, pressuresand stresses as hydrocarbons are produced, facil-itating optimal exploitation of reserves.

These innovations are helping make seismicdata a vital tool for every stage of the E&P effortat a time when many oil companies are empha-sizing enhanced production from existing assets.

Acquisition Domains at the Oslo Technology Center,Norway, for contributing to the world-class engineeringeffort described in this article.Monowing, Q, Q-Fin, Q-Marine and TRINAV are marks ofWesternGeco.

Summer 2001 17

Optimization and fast-track delivery of newassets from ever fewer wells increase relianceon reservoir geophysics to build subsurface mod-els with real predictive power.

Because so many of the newly inventeduses—imaging for well placement, predictingpore pressure and monitoring fluid fronts—require extremely accurate data, there is a height-ened demand for data of the highest possiblequality. For seismic data, high quality is defined ashigh signal-to-noise ratio and wide bandwidth, orrange of frequencies contained in the signal. Overthe years, tremendous care has gone into devel-oping survey-design programs and efficient data-processing schemes to increase signal quality byenhancing acquired signal bandwidth and ampli-tudes and suppressing noise to get the most outof every bit of data acquired. But the questionmust be asked: can seismic data get any better?

The answer is yes, but to understand how, wemust first examine the problem of noise.

What Causes Noise?About 10 years ago, scientists and engineers atwhat is now WesternGeco began to look at theheart of the noise problem. They proposed a con-ceptually simple, two-part campaign to improvemarine data quality. First, identify every signifi-cant source of noise in seismic data, then sup-press or minimize it.

Through a holistic analysis of data from exist-ing acquisition systems and additional modeling,they were able to quantify the level of noise rel-ative to signal for each noise type (above).Dozens of potential causes were considered,including source and receiver positioning, distor-tions due to source variations, receiver sensitivity,recording electronics, and water and vessel

motion. The dominant noise sources were foundto be swell and wave action at the surface, vari-ation in source characteristics and positioningerrors associated with receiver groups. In somecases, noise levels were high enough to makeinterpretation of the resulting images difficult.Only by reducing noise to its lowest possiblelevel would seismic data be usable for reliablestratigraphic and time-lapse interpretation.

This article chronicles efforts by geophysi-cists, engineers and signal-processing experts tominimize these sources of noise, enhance signalquality and produce images suitable for detailedinterpretation. We describe how traditionalmethods of acquisition and noise suppression fall short and how advances in acquisition systems—especially a new point-receiverapproach—are helping to produce a quantumleap in seismic data quality.

> Significant sources of noise detected in marine seismic data. Horizontalbars show levels of noise present in standard processed data. Effects ofswell noise and source-signature variation can be ameliorated by processingthat reduces noise to levels indicated by arrows. Vertical color bands showthe level of noise that can be tolerated in different applications of interpretedseismic data. For structural interpretation, higher noise levels can be toleratedthan for stratigraphic interpretation, and interpretation of seismic data fortime-lapse reservoir monitoring requires the lowest possible noise levels.

Sensor-sensitivity variation,hydrophone drop-outs

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Decreasing Noise Level Beneath the Signal

Traditional Marine AcquisitionMarine seismic surveys are acquired by shipstowing streamers, or instrumented cables, torecord signals from shots fired as the vesselmaneuvers across the target (right). A typicalstreamer is 3000 to 8000 m [9800 to 26,200 ft]long and, in conventional acquisition, carrieshundreds of receiver groups of 12 to 24 hydro-phones feeding to a single recording channel(below). In principle, summing the detected signals before recording—a step called arrayforming—enhances signal-to-noise ratio. How-ever, array forming can irreparably damage signalfidelity and reduce the effectiveness of subse-quent processing steps aimed at attenuatingnoise traveling down the streamer. To minimizesea-surface wave noise, streamers are towed ata depth specified in the survey-planning stage,usually 6 to 10 m [20 to 33 ft]. Towing at shal-lower depths can increase the high-frequencycontent of the recorded signal, but usually alsoincreases noise level.

High-performance acquisition vessels cantow 12 to 16 streamers spaced 50 to 100 m [160to 330 ft] apart. Deflectors based on Monowingmultistreamer towing technology are deployed atthe front of the streamer to help maintainstreamer spacing.1 While the Monowing devicescontrol streamer separation at the front, whathappens behind that point is subject to nature.Currents, tides and other forces can causestreamers to feather, or drift laterally from programmed positions, and in extreme cases,tangling can occur. Tangled streamers have to be reeled back to the vessels and untangled manually, resulting in nonproductive time.

Any application of seismic data requires accu-rate position information, and some uses, such astime-lapse seismic monitoring, demand repeat-able positioning. To ensure that the acquisition

arrangement is accurately documented, position-ing sensors are used to determine the position ofevery source and receiver at every shot point asthe vessel moves. Global Positioning System(GPS) measurements use satellites to pinpointthe vessel position to within three meters. Withtraditional systems, positions of seismic sourcesand receivers relative to the vessel are calcu-lated using information from acoustic andstreamer-mounted heading sensors in networks

at the front and tail of the streamer (next page, far right). The front and tail positions of thestreamers are known accurately. However, thepositions of individual sensors are estimated froma streamer shape that is calculated by use ofstreamer-mounted heading sensors placed at afew locations along the streamer, which canintroduce significant errors.

18 Oilfield Review

> Streamers, or instrumented cables, for recording signals as the seismic vessel moves across the target.

> Interleaved groups of hydrophones feeding to a single recording channel. Signals from each hydrophone in a group are summed to produce a singlerecorded trace per group.

Conventional Analog Groups

Single conventional group, 24 individual hydrophones

12.5-mgroup interval

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16.12-mgroup length

Summer 2001 19

The typical seismic source is an array com-posed of subarrays each containing up to six airguns separated by about 3 m [10 ft] (below). Like streamers, air-gun arrays also are towed ata depth of 6 to 10 m. Arrays that are towed tooshallow produce insufficient output; instead ofthe air-gun burst traveling downward, it producesonly bubbles at the sea surface because there isnot enough hydrostatic pressure to form themproperly. Sources produce signals that arealtered by destructive interference between thedirect sound waves that travel downward andthose that travel up first and reflect off the seasurface—ghosts—just a few milliseconds later.Receivers similarly suffer from interferencebetween the upcoming reflections and downgo-ing ghosts reflected off the sea surface. The shal-lower the source or streamer, the more thehigh-frequency content in the recorded signal,but the greater the loss of deeply penetrating lowfrequencies and the higher the noise. The deeperthe source or streamer, the greater the low-fre-quency content and the lower the noise, but atthe cost of losing high-frequency signal. The sig-nature of a source array can vary from shot toshot depending on variations in individual gun fir-ing times, gun-chamber pressure, array geometryand drop-out—failure of a gun to fire. Theseshot-to-shot variations can reduce the accuracyand repeatability of seismic surveys.

Improved Marine AcquisitionWesternGeco geophysicists and engineers devisedways to suppress the streamer-, positioning- andsource-related noise that plagues traditionalacquisition. Several teams at the Oslo TechnologyCenter in Norway cooperated to overcome thetremendous technical challenges involved in per-fecting the Q point-receiver technology. The prod-uct of their labor, the Q-Marine system, deliversmarine seismic data of unsurpassed quality. Thenew system includes improvements in receiversensitivity and positioning accuracy, steerablestreamers, enhanced source control and point-receiver acquisition to consistently provide repeat-able high-quality data.

To solve the problem of receiver sensitivityvariation, manufacturing engineers stipulatednew high-fidelity tubular hydrophones with tightand stable sensitivity specifications. Hydro-phones typically experience hydrostatic pres-sures that may affect sensitivity over time, oreven destroy the sensors. The new hydrophoneshave much higher survival-depth tolerances andmore stable sensitivities because they are pre-aged in the manufacturing process and performconsistently thereafter. Each hydrophone has itsown calibration certificate, and all sensitivity values are stored in the streamer front-end electronics for automatic data calibration.2

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Source> Positioning networks at the front (top)and tail (bottom) of the streamers. GlobalPositioning System (GPS) sensors, head-ing sensors (compasses) and acousticsensors provide measurements to helpcalculate the position of the sources andreceivers in the streamer array.

> Air-gun subarrays each containing six air guns. The quality of every seismic shot depends on thesize, location and firing timing of each gun in the array.

6- to 10-mtowingdepth

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Typical Configuration

15- to 20-msubarrayseparation

1. Beckett C, Brooks T, Parker G, Bjoroy R, Pajot D, Taylor P,Deitz D, Flatten T, Jaarvik LJ, Jack I, Nunn K, Strudley Aand Walker R: “Reducing 3D Seismic Turnaround,”Oilfield Review 7, no. 1 (January 1995): 23-37.

2. Svendsen M and Larsen L: “True 4D-Ready-SeismicUtilizing Q-Marine,” paper OTC 13163, presented at theOffshore Technology Conference, Houston, Texas, USA,April 30-May 3, 2001.

With recent advances in electronics and fiber-optic networks, the system can record more than4000 hydrophones per 12-km [8-mile] streameron up to 20 streamers, for a maximum of 80,000channels. The resulting 4-fold increase in band-width capacity compared with conventionalacquisition systems opens the possibility ofbringing raw point-receiver data up to the vesselfor advanced processing with digital group-forming algorithms, discussed later in this article.

The new acquisition system carries an acous-tic ranging system along the full length of thestreamer. Distinctive acoustic sources spacedevery 800 m [2600 ft] along the streamers emitsignals that can be recorded at any seismichydrophone. The relative timing of each arrivalallows a set of ranges, or distances betweensource and hydrophone, to be computed acrossthe entire network (below left). The acousticranges are used as input to a ranging-network

adjustment that extends between GPS readings.The result is an absolute positioning accuracy towithin 4 m [13 ft] anywhere along the streamers.The computational power required for solving thein-sea network adjustment is many times greaterthan that required for the conventional solution.

While all traditional acquisition systemsallow control of streamer depth, only the Q-Marine approach enables active horizontalsteering in addition to depth control. Streamer

20 Oilfield Review

> The new Q-Marine positioning system deploying a full acoustic network along the entirestreamer length. Receiver positioning can now be calculated to within 4 m [13 ft] anywherealong the streamer. In addition to range information (orange) from the tail (left) and frontnetworks (right), the full-streamer network for this 10-streamer configuration calculatesranges at hundreds of intermediate points (blue).

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> The Q-Fin steering device for controlling streamer separation and position by steering thestreamer horizontally and vertically.

Summer 2001 21

orientation can be modified laterally for optimalcoverage, allowing streamers to be towed at separations as close as 25 m [82 ft] with greatlyreduced risk of tangling. Narrow streamer sepa-ration allows higher resolution sampling forimproved imaging, and in-sea equipment can besteered safely near potential hazards such assurface installations. Steerable streamers areideal for reservoir surveys because they allowsignificantly faster vessel turns, a major time-saving in relatively small-acreage surveys.

Steering control improves logistics involved instreamer deployment and retrieval, making theback deck safer. Acquisition operations are saferbecause less time is spent on the back deck.3

Steering devices are located every 400 to800 m [1300 to 2600 ft] along the streamer. TheWesternGeco Q-Fin steering system has indepen-dently controllable wings to steer streamers up,down, and side to side (previous page, bottom).Unlike traditional devices that are clamped on tohang below the streamer, the Q-Fin assemblage is

an integral part of the streamer. This innovativeconfiguration maximizes hydrodynamic lift andhelps minimize acoustic noise associated withstreamer steering.

The Q-Fin mechanism is controlled by a steer-ing controller, which compares calculatedstreamer positions in the navigation system withthe desired positions, and adjusts streamer ori-entation as required (above). The controller

Range data

Navigationdata

Measuredstreamer positions

Steering controller

Demandedstreamer positions

Positioning data

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TRINAV navigation systemStreamers

> Flow of streamer steering data. Positioning data from the streamer are fed to the positioning controller, whichcalculates streamer positions in terms of ranges, or distances, between hydrophones. The TRINAV navigationsystem uses the ranges to calculate actual positions, which are recorded as navigation data, and also passesthe positions to the steering controller to feed back changes if required.

3. Swinsted N: “A Better Way to Work,” Oilfield Review 11,no. 3 (Autumn 1999): 46-60.

computes the forces required by each steering finto bring all streamers to their appropriate loca-tions (above).

The steering capability of Q-Marine stream-ers reduces the need for infill lines—lines thatare shot to fill gaps after the bulk of acquisitionis completed. This translates into shorterturnaround time for surveys and less nonproduc-tive time. Better steering also produces higherquality data, because consistent seismic linespacing delivers more uniform areal coverage.

To reduce noise further, seismic-sourceexperts engineered improvements to the marineair-gun arrays, which generate both seismicenergy and unwanted noise. Variations from oneshot to the next in the output from an air-gunarray lead to unwanted noise in the recorded sig-nals. Gun-array control systems are designed toprevent this from happening, but events outsidethe tolerances of the control systems can lead tounacceptable levels of variation in the output ofthe array. Minor changes in air pressure at differ-ent guns and wave action at the surface can

result in an unpredictable source signature. Tocompensate for these situations, variations in thepressure field surrounding individual air guns—due to the presence of other air guns and otherhydrostatic pressure variations—must be mea-sured and calibrated.

Since the source signature must be removed,or deconvolved, from the recorded data beforefurther processing, the lack of a fully predictablesignature has forced geophysicists to rely on sta-tistically based deconvolution techniques.However, these provide only approximateanswers and may fail to account for source-gen-erated variations.

An advanced source-controller system and asignature-estimation technique solve this prob-lem. Source-control electronics on the air-gunsubarrays synchronize and fire each gun based onits acoustic output. Fiber-optic lines communi-cate with the vessel, replacing conventional two-way systems that can mistime gun firing as theysend signals to and from the vessel. GlobalPositioning System antennae deployed on eachsubarray provide accurate positioning of air guns.

The pressure signature near each gun is mea-sured for input to a signature-estimation tech-nique.4 A patented hydrophone arrangementadjacent to each air-gun element records acous-tic pressures and defines, for each air-gun ele-ment, a notional signature that does not containthe effects of pressure fields from other guns. Bysumming notional signatures from all the airguns together with the free-surface ghost reflections, a far-field signature, or the effectivesource output seen by the streamer hydrophones,can be computed.

An example of the power of the calibratedmarine source (CMS) technique comes from theOrca basin in the deep water of the Gulf ofMexico. In this basin, a salt body outcrops on theseafloor, increasing the salinity of the deepestwaters. The contrast in seawater salinity gener-ates a strong, isolated, horizontal reflection at3.0-sec two-way time, some 200 msec before

22 Oilfield Review

Survey 1 Survey 2

> Two surveys (left and right) with repeated streamer positions in a four-streamer test. For each survey, positions are calculatedfor the four streamers (top), showing a constant streamer separation. The forces required to achieve the desired positions areshown by white arrows (bottom).

Summer 2001 23

the reflection from the seabed (below). Withoutmarine-source calibration, variations in bubblesgenerated by the raw source are evident around3.15 sec. These variations, although they appearminor, affect later signals and can lead to erro-neous interpretations. After CMS deconvolution,bubble amplitudes and their variations are minimized so signals from deeper reflections are cleaner.

This combination of calibrated receiver sensi-tivity, enhanced recording capability, improvedstreamer positioning, better source control andsignature estimation sets the stage for the ultimate breakthrough that distinguishes the Q-Marine system from other marine seismic sur-vey techniques, and that is point-receiver acqui-sition. Point-receiver acquisition records tracesfrom individual receivers, whereas conventionalacquisition sums traces from a group of receivers

in a step called analog group forming, thenrecords that sum (see “Problems with SeismicRecording Using Arrays,” page 24 ).

The idea of acquiring data from each sensorindividually rather than as a group is not new. Inthe late 1980s, Shell geophysicists proposed asimilar method and discussed the potential bene-fits.5 They realized that the traditional techniqueusing an acquisition system composed of hard-wired groups did not produce optimal data. Theyalso showed how signal processing, or digitalgroup forming, could reproduce the desired filter-ing effects of analog group forming. However, theyacknowledged that the ultimate solution—a onechannel per hydrophone system—would requirestep changes in hardware and processing capabil-ities, and would not be adopted immediately bythe industry. The WesternGeco Q-Marine systemis the first to realize this point-receiver vision.

Seeing the DifferenceThe combination of advances introduced withthe Q-Marine system brings unsurpassed clarityto the resulting seismic images. An examplefrom the Garden Banks area in the Gulf ofMexico shows the improvements in signal qual-ity and resolution that can be achieved when all the noise-reduction and signal-boosting

Raw-source bubble variation

Bubble variation after source-signatureestimation deconvolution

Bubble Elimination, Deepwater Gulf of Mexico

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> Calibrated marine source in the Gulf of Mexico. The major reflection feature in this seismicsection is the salinity contrast imaged at 3.0 sec (top). Zooming in shows bubble signals thatarrive from 3.1 to 3.15 sec with varying arrival times and amplitudes (middle). Marine-sourcecalibration helps remove the variations in the bubble (bottom) so that interpretation of deeperreflections can be made with greater confidence.

4. Ziolkowski A, Parkes G, Hatton L and Haughland T: “The Signature of an Airgun Array: Computation fromNear-Field Measurements Including Interactions—Part 1,” Geophysics 47 (1982): 1413-1421.

5. Ongkiehong L and Huizer W: “Dynamic Range of theSeismic System,” First Break 5, no. 12 (December 1987):435-439.Ongkiehong L: “A Changing Philosophy in Seismic DataAcquisition,” First Break 6, no. 9 (1988): 281-284.

(continued on page 26)

24 Oilfield Review

Ever since the 1930s, when reflected seismicwaves were first used for petroleum explorationon land, signals have been acquired with groups,or arrays, of sensors. This technique, designedto facilitate land acquisition, was adopted laterfor marine acquisition. A brief review of acquisi-tion basics shows the advantages and disadvan-tages of the method.

Energy from an exploration seismic sourceradiates outward in several modes. On land,compressional and shear waves, called bodywaves, travel through the body of the earth,reflect off subsurface layers and return to sur-face sensors; these are the most useful wavesfor seismic imaging. Offshore, only compres-sional waves are generated. Not all the energyrecorded by surface sensors is usable for imag-ing. Waves that travel directly to the sensorwithout reflecting are considered noise, becausethey do not contribute energy to a reflectionimage. In addition to these direct arrivals, otherenergy modes can arrive as noise. On land, sur-face waves, called ground roll, travel along theground surface and add high-amplitude noise.In marine acquisition, waves originating in andtraveling along the streamers constitute noise.

When the reflecting surface at depth is hori-zontal, compressional and shear waves arriveback at the sensors along nearly vertical ray-paths, while much of the noise arrives nearlyhorizontally. Early on, geophysicists discoveredthat the different arrival directions could beused to dampen the amplitude of incomingnoise. Instead of recording arrivals on a receiver

Problems with Seismic Recording Using Arrays

1. Özbek A: "Adaptive Beamforming with Generalized LinearConstraints," Expanded Abstracts, SEG InternationalExposition and 70th Annual Meeting, Calgary, Alberta,Canada, August 6-11, 2000: 2081-2084.

Conventional Grouped Hydrophones, 12.5-m Group Spacing

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> A shot record acquired in relatively rough weather with conventionallygrouped hydrophones. High-amplitude wave noise that appears incoherentcan be seen on many traces at nearly all arrival times.

By recording signals at every receiver position digitally, the properly

sampled incoming wavefield, containing both signal and noise, can

be processed using sophisticated algorithms. This signal-processing

step, which improves upon the noise-suppression capability of a

hard-wired array, is called digital group forming. Digital group

forming can make use of processing techniques more powerful

than simple linear summation.

Summer 2001 25

at one point, they set up a group—called ahard-wired array—of receivers separated by nomore than one-half the dominant wavelength ofthe expected noise. This simple analog summa-tion of signals arriving at each receiver in thegroup attenuates much of the horizontally arriving coherent noise, but unfortunately mayalso attenuate the higher frequencies of signalsthat arrive nonvertically, such as from a dipping reflector.

By recording signals at every receiver positiondigitally, the properly sampled incoming wave-field, containing both signal and noise, can beprocessed using sophisticated algorithms. Thissignal-processing step, which improves upon thenoise-suppression capability of a hard-wiredarray, is called digital group forming. Digitalgroup forming can make use of processing techniques more powerful than simple linearsummation.1

Comparison of digitally formed array resultswith those from hard-wired arrays shows howwell the new technique works. A shot recordacquired with conventionally grouped hydro-phones at a standard 12.5-m [41-ft] group spacing displays high residual levels of weather-related noise that appears incoherent, and thusdifficult to filter out (previous page). At thesame time, a Q-Marine streamer, with closelyspaced digital traces, recorded the same shotsunder the same weather conditions (top left).The noise, properly sampled, is coherent andcan be filtered out through processing withoutaffecting the signal. The digitally array-formeddata, output with one channel every 12.5 m,have significantly reduced levels of the residual noise that dominated the conventional shotrecord (left).

> A shot record acquired simultaneously with the data acquired in theprevious-page figure, but with closely spaced Q-Marine point-receiverhydrophones. High-amplitude wave noise is present, but appears coherentand can be filtered out with processing.

> Q-Marine data. A shot record of digitally array-formed point-receiverdata output at larger trace spacing for comparison with the shot recordfrom the hard-wired array shows almost none of the high-amplitude noisethat contaminated the conventional shot record.

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techniques come into play (above). A conven-tional three-dimensional (3D) survey shot in mid-1997 for multiple clients produced an apparentlysatisfactory image. With Q seismic acquisitionand processing technology, a remarkablyenhanced image was delivered in 2000, eventhough the new section is only from a 2D line.The Q-Marine seismic section illuminates morelayers and small-scale features than the conven-tionally acquired section. Reflections that were

imperceptible in the older survey are clear andstrong in the newer image.

Another comparison, this time over the Dianafield, again shows the superior resolution andimaging power achievable with the Q system (next page, top). The image produced from a con-ventional 1999 survey shows the prospect as ahigh-amplitude feature on the flank of a saltdome. A Q-Marine survey shot over the same line images the field and overburden with greater resolution.

With Q-Marine technology, more high-frequency signal is preserved at all depths (next page, bottom). Whereas conventional sur-veys may contain usable 60-Hz signals at the tar-get depth, the Q system delivers frequencies upto 85 Hz at the same depth. This improvement inresolution allows more detailed interpretation ofsubtle features such as lateral stratigraphicchanges and time-lapse reservoir variations.

26 Oilfield Review

Garden Banks Conventional Line 3 Garden Banks Q-Marine Line 3

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> Comparing a conventional seismic section with one acquired using Q-Marine technology. A two-dimensional (2D) panel from a three-dimensionalsurvey (3D) acquired in 1997 with conventional streamers (left) in the Garden Banks area, Gulf of Mexico, shows several subsurface reflections.Results from a 3D survey should be superior to those from a 2D line, but in this case, the 2D line acquired in 2000 with Q-Marine technology (right)reveals more about the subsurface.

Summer 2001 27

Diana Field Conventional Data Diana Field Q-Marine Data

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> Conventional (left) and Q-Marine seismic data (right) from the Diana field, Gulf of Mexico. The Diana field appears as a dipping high-amplitudereflector in the lower right of each panel. The Q-Marine survey images the field and surrounding layers with higher resolution than can be obtainedwith conventional acquisition.

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> Average amplitude spectra for Diana field data acquired conventionally and with Q technology. Conventional data (left) contain useful(at least –30 dB) signal up to 60 Hz at the target depth. Q-Marine acquisition and processing (right) preserve high-frequency signals up to85 Hz at the same depth. Frequency spectra pertain to signals recorded in the interval 3.3 to 3.7 sec.

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Zooming in on part of the Diana prospect, theQ-Marine survey adds resolution at target depthto help delineate features that can affect layercontinuity (above). The conventionally acquiredsection shows a fairly continuous-looking reflector, while the Q image reveals possible discontinuities in the reservoir. The improvementin image quality achieved in Q surveys is making many operators question what they mayhave missed in earlier conventional surveys inother areas.

Repeatability for Reservoir MonitoringIn addition to enhancing imaging for structuraland stratigraphic interpretation, the Q-Marinesystem delivers surveys that can be used in time-lapse reservoir monitoring. Use of seismic datafor monitoring reservoir changes is based on eval-uation of differences between two seismic sur-veys acquired at different times separated by aperiod during which some aspect of the reservoir,such as fluid saturation, pressure or rock stress,has changed. Time-lapse monitoring attributes allobserved changes to the reservoir, not the seismic

recording system or background noise. The tech-nique is based on the premise that two surveysacquired at intervals during which no reservoirchange has occurred should be alike.

Repeatable positioning of streamers is key toreliable time-lapse surveys. When streamers areeven slightly off position, seismic lines acquiredonly days apart can show differences unrelatedto subsurface changes (next page, top). Properlyrepeating streamer positions minimize differ-ences between immediately succeeding surveys(next page, bottom).

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> A seismic close-up of the Diana prospect. The conventionally acquired survey (top) shows a relativelycontinuous high-amplitude reflection at the reservoir level, while the image derived from the Q survey(bottom) reveals a less continuous reflection.

Summer 2001 29

Survey 1 Survey 2 Difference

.When streamer position isnot repeated. Streamers thatare slightly off position duringrepeat surveys fail to delivertruly repeatable data. Theinsert (above) shows thestreamer positions in two shotsacquired within two days ofeach other (left and center).Subtracting one shot gatherfrom the other (right) showsdifferences related only tovariations in acquisition, sincethe subsurface did not changeduring the two-day period.

Survey 1 Survey 2 Difference

. Repeatable data with repeat-able positioning. When posi-tioning is properly repeated,time-lapse surveys show realsubsurface changes. Shotsfrom Survey 1 (left) and Survey2 (center) were acquired withrepeatable streamer positioning.Their difference (right) correctlyshows no difference in thesubsurface.

Streamer position

Streamer position

In another example from the Gulf of Mexico,a 2D line was acquired to serve as the baselinesurvey (above). Two days later, a second line wasacquired, under the same calm-sea conditions asthe first. The data were acquired from pointreceivers and processed identically using source-signature deconvolution and digital groupforming. Subtracting one line from the othergives an image of the difference between thetwo surveys (next page).

Measures of repeatability can be defined toquantify the likeness of two traces.6 One possiblemetric is the normalized root-mean square(NRMS) difference between two traces within a

given time window. The lower the NRMS, themore alike the traces. Another metric, pre-dictability, is a function of the correlated powerbetween two traces. The higher the predictabil-ity, the more alike the traces. The difference plotshows high repeatability values on the left half ofthe image and lower repeatability on the right.7

For this test, streamer position was not con-trolled. Strong currents caused the streamers to

feather, or deviate from their optimal positions,making it difficult to reproduce the streamer posi-tion on the repeat pass. When streamer locationsare not reproduced from one survey to the next,repeatability suffers. Strong trace similarities correspond to data for which acquired commonmidpoint (CMP) traces are in the same location.Lower trace similarities occur when CMP loca-tions differ across the two surveys.

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Repeat 2D Stacked Section

> Initial stacked section (top) acquired in calm seas for repeatability test. The repeat survey(bottom) was acquired under the same weather conditions two days later for quantifyingrepeatability.

6. Morice S, Ronen S, Canter P, Welker K and Clark D: “The Impact of Positioning Differences on 4DRepeatability,” Expanded Abstracts, SEG InternationalExposition and 70th Annual Meeting, Calgary, Alberta,Canada, August 6-11, 2000: 1161-1164.

7. Kragh E and Christie P: “Seismic Repeatability,Normalized RMS and Predictability,” submitted for presentation at the SEG International Exposition and 71st Annual Meeting, San Antonio, Texas, USA, September 9-14, 2001.

Summer 2001 31

Getting the Most from Seismic DataInterest in the new Q-Marine system is growingrapidly. The Geco Topaz, the first vessel to berigged for commercial services, began 3D Q-Marine data acquisition in the Gulf of Mexicoin January 2001. She has a full summer seasonscheduled in the North Sea acquiring severaltime-lapse Q-Marine surveys and high-resolution3D data sets. A second vessel, the WesternPride, is being rigged for the Q-Marine system

and will be available by August 2001. A third ves-sel will be equipped with Q-Marine technologybefore the end of 2001.

The early results are meeting and even sur-passing expectations in terms of data quality andrepeatability. The imaging power and resolutionseen in Q-Marine survey data have become thenew benchmarks for data quality. As more Q sur-veys are acquired, geophysical interpreters willcome to rely on the clarity delivered by the new

steered-streamer, point-receiver, calibrated-source technique. Systems are under develop-ment or in deployment for land, borehole andseabed acquisition using the same principles asin Q-Marine technology. Eventually, every reservoir, even those in notoriously difficult envi-ronments, may benefit from the enhanced illumi-nation that comes with properly sampled signalsfrom the subsurface. —LS

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>Measures of repeatability (top), common midpoint locations (middle) and difference plot (bottom).Subtracting the repeat line from the initial line gives the difference between the two surveys. Onthe left side of the difference plot, amplitudes are small because the locations of the common mid-points that contribute to the stacked data are similar. SP1 is the location of the first shot point. Onthe right side of the line, differences are large because common midpoints differed greatly in thetwo surveys. The predictability and NRMS curves are indicators of similarities and differences,respectively, between the lines compared.