High-Density,Long-Offset 3-D DatasetsDrive Seismic Acquisition Onshore unconventional formations and

deepwater subsalt horizons present radicallydifferent operating settings and technical chal-lenges, but the role of petroleum geophysicsremains essentially the same in both environ-ments: getting to the “ground truth” to determinewhere (and where not) to place wellbores.

After all, the need to accurately describe thesubsurface, reduce risk and predict geologicproperties between wellbores is the samewhether those wells are separated by a matterof hundreds of feet on the same horizontalwell pad in West Texas or by several miles inadjacent offshore fields in Walker Ridge, drivinga common need for more dense, wider-azimuth,longer-offset, higher-resolution images.

“For many years, the seismic method was anexploration tool. It indicated where to drill basedon structural components or structural repre-sentations of trapping and sealing mechanisms,”says Steve Jumper, chief executive officer ofDawson Geophysical Company. “In general,with unconventional plays, the use of geophysicsexpanded into complex reservoir characterizationand development-type applications.”

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Seismic data was used early on in un-conventional applications more for iden-tifying hazardous structural componentssuch as faults, folds, karsting and dip di-rections, Jumper explains. “By utilizingmore attribute-rich seismic data, the sci-ence is moving toward having the abilityto identify the most favorable rock forcompletions,” he says.

Consequently, seismic data is helpingoperators figure out not only where todrill to access the most “fraccable” rock,but also how to drill with respect to se-lecting the best landing zone and planningthe well path on optimal spacing, Jumpergoes on. “Acquiring high-resolution 3-Ddata with higher density and wider azimuthalso allows seismic data and attributeanalysis to be a better predictor of stratig-raphy,” he adds, noting that rock makeup is particularly critical in stacked re-source plays with multiple prospectivepay zones.

“We have enough seismic data andwell control in the Permian Basin, inparticular, to have a pretty good idea ofthe structural complexity, but we do notknow with nearly as much degree of cer-tainty what the stratigraphic componentslook like,” explains Jumper. “As we in-crease density and apply analytics, thereis a better chance of using seismic dataas a predictor for rock stress, rock type,and rock fabric for better placement of a

horizontal well in the sweet spot of anunconventional reservoir.”

High-Resolution 3-D Data

Dawson recently completed an acqui-sition project in West Texas with a peakof 48,000 channels. This was the largestproject in the company’s history, Jumperreports, representing a 15-fold increasein density, volume and data source pointsacquired per day compared with typicalprojects. “Combined with another surveyproject in eastern New Mexico with34,000 channels, the total field recordeddata was 1.4 petabytes, yielding about157 terabytes of high-density, high-reso-lution 3-D seismic data,” he reports.

And those surveys could be preludesto an even higher-channel count projectin Dawson’s near future, according toJumper, who notes that the company cur-rently is shooting a multicomponentproject in the Midland Basin that requiresas many as 44,000 three-component unitsor 132,000 channels.

“Shooting 500 square miles in WestTexas looks a lot different than 500 squaremiles in the SCOOP/STACK play inOklahoma, where there are many smallerland and mineral owners,” Jumper states.“Timing becomes an issue as to whenprojects are ready from a permittingstandpoint.”

Channel count is also on the rise in

land surveys in Canada, where DawsonGeophysical has been recording multi-component data that capture compressionalas well as shear energy to image verticaland horizontal seismic waves in three di-mensions. “We are building views intoour 3-D surveys that lend themselves tobetter imaging analysis,” Jumper remarks.“We design surveys to illuminate subsur-face points in as many directions and dis-tances from shot to receiver as possible.”

Because Canadian structures tend tobe much shallower, the multicomponent3-D surveys are generally not as big froman areal coverage standpoint as in thelower-48, but have much higher sourceand channel densities. “It is not uncommonto have 10-meter spacing, and channelcount tend to be driven more by densityin Canada than in the Permian Basin,” heexplains. “The density allows us to illu-minate shallow objectives very well.”

Multicomponent Project

The company recently completed ahigh-density 3-D multicomponent projectwith 96,000 channels. More than 60 ter-abytes of output high-density, high-reso-lution data was generated from about 1.6petabytes of field recorded data, accordingto Jumper.

Areal extent and density are the twokey drivers of increasing channel counts,Jumper says. “It is common to have sur-veys that are hundreds of square miles,and we have had some that are in thethousands of square miles, where it istaking multiple crews to get the projectdone in a timely manner,” he details,adding that both the density of energysource placement and respective channelswithin a given area are increasing.

Energy source placement and move-ment become important in efficientlycompleting the surveys without sourceinterference. “Let’s say we are 25,000feet apart in the Permian Basin, or roughlyfive miles in any direction from the energysource,” he posits. “We would need tohave basically 100 square miles of chan-nels on the ground.”

The energy source would illuminate2.5 miles outward in all directions, orabout 25 square miles. That shot pointwill move a few hundred feet or so andshoot again. This continues over the entiresurvey, moving a very large template atvery small increments. “Each point hasmany illuminations, building redundancyfor statistical analysis,” Jumper explains.

Of course, there are also various tech-

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Identifying topographical and geographical surface hazards is so critical to the successof seismic data acquisition projects that Dawson Geophysical maintains a subsidiary,EagleEye Geospatial, to address these issues through high-resolution aerial imaging.Both manned and unmanned aircraft platforms capture detailed images to map roads,fences, power lines, production sites, pipelines and other surface features before bootsever hit the ground.

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niques for implementing energy sourcesin an almost simultaneous manner, whichis facilitated by the size of the survey.Sometimes a survey is large enough thatmultiple sets of energy sources can operatealmost simultaneously, he says.

Aerial Imaging

In onshore data acquisition, the singlebiggest challenge to survey design is ar-guably not what lies beneath the surface,but what is on top of it–be it in an urban-ized area or a rural area with complexterrain. Identifying topographical and ge-ographical hazards on the ground is socritical to acquisition success that Dawsonmaintains a subsidiary, EagleEye Geospa-tial, to specifically address these issueswith aerial imaging services, Jumper says.

“The typical approach for well padplanning is to pull up an image on GoogleEarth, but in sparsely populated areasthose images could be more than twoyears old,” Jason Stockstill, general man-ager of EagleEye, points out. “As fast aschanges happen in areas like the PermianBasin, the imagery needs to be muchmore current.”

In addition to up-to-date information,aerial imaging provides very high reso-lution and accurate elevation information.“We have the necessary resources, fromour UAV to manned aircraft platforms,to capture details with an accuracy ofless than one foot,” says Stockstill. “Wecan map roads, fences, power lines andother features and plan around them longbefore boots ever hit the ground to helpimprove the timing and efficiency ofDawson’s field crews.

“EagleEye utilizes these resources tosupport the activity of our seismic crewsand to provide a means for improved ef-ficiencies through the collection of accurateimagery and the distribution of multiplelayers of geospatial analysis that hasproven to be useful to our clients withinthe oil and gas industry,” Stockstill adds.

Deepwater Gulf of Mexico

In the Mississippi Canyon area in theGulf of Mexico, CGG has acquired anew high-density multiclient nodal surveydesigned for high-quality imaging of thesubsurface and improved definition ofsubsalt structures.

“We are seeing that clients want in-creased density for enhanced resolutionof target reservoirs,” says Matt Bognar,CGG’s senior vice president of multiclientand new ventures for the Western Hemi-

sphere. “The idea is to get a better imagefrom a better velocity model that leads toa better interpretation with less uncer-tainty.”

Innovative ocean-bottom node (OBN)acquisition methods and CGG’s uniquevelocity modeling algorithms, poweredby high-performance supercomputers thatmake it possible to quickly and efficientlymodel huge datasets, are revolutionizingsubsalt imaging, Bognar claims. “Whereonce the industry relied on interpretationsto estimate the subsurface, we are nowable to be increasingly data-driven andrely more on the actual information inthe seismic dataset,” he says. “This ismade possible by the high quality of theseismic data, CGG’s advanced imagingtechnology, and the accuracy of the re-sulting velocity model.”

To that end, Bognar explains that thefull-azimuth, long-offset OBN data ac-quired in the Mississippi Canyon will beused to generate an improved velocitymodel and clearer images of the complexsubsalt-related geology in the area.

“The velocity model being developedwith the new OBN survey will use ouradvanced full-waveform inversion (FWI)techniques. Since imaging and interpre-tation rely on the velocity model to re-construct the subsurface from the seismicdata, the better the velocity model, thebetter the image,” he explains, addingthat the updated velocity model also canbe applied to previous datasets in CGG’slibrary for improved imaging accuracy.

The overall permit area for the project

is almost 1,900 square kilometers, saysBognar. “The survey will provide excellentoffset and azimuth coverage for subsaltillumination,” he relates. Remotely oper-ated vehicles were used to deploy theOBN equipment and roll the patch.

“Full-azimuth, long-offset data deliversthe data required for higher-quality im-aging compared to older technologies,”Bognar comments. “The goal is to havebetter clarity at depth to improve theimage of a particular structure.”

During deployment and recovery, everyproposed seabed node location was verifiedthrough visual inspection by a cameraon the ROV. “There could be infrastructureor archaeological interference,” he notes.“We made sure that we maneuvered safelyaround all hazards and sensitive features.”

Elsewhere in the Gulf of Mexico,CGG announced in mid-June that it hadcompleted the imaging of another nodalsurvey of the Mad Dog Field in the GreenCanyon area for BP and partners. Thisocean-bottom node survey also usedCGG’s full-waveform inversion to producea fast-track velocity model in a greatlyreduced time frame, facilitating superiordepth migration for imaging only weeksafter delivery of the OBN data. Projectcycle time was reduced by almost halfwhile delivering greatly improved subsaltimages.

Tailored To Smaller Operators

Lockhart Geophysical Company re-cently completed a 200 square-mile 3-Dsurvey in Nebraska that was more than

SpecialReport: Seismic & Geophysics

CGG has completed the acquisition of a multiclient ocean-bottom nodal survey in theGulf of Mexico’s Mississippi Canyon area. The overall permit area for acquiring thehigh-density, full-azimuth and long-offset data is almost 1,900 square kilometers. Usingadvanced full-waveform inversion and proprietary velocity modeling algorithms, thesurvey is designed for high-quality subsurface imaging and improved definition ofsubsalt structures.

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SpecialReport: Seismic & Geophysics

double the size of any previous projectthe company had conducted, accordingto Geophysical Technician Carlos Jimenez.

“Typically, we are tailored to the small-er operator/producer in Kansas,” he says,adding that in this case, the client choseLockhart for its wired acquisition system.The client wanted to see the data in realtime because it was more comfortablewith real-time data gathering with ourcabled geophones.”

Lockhart began stepping out fromKansas fairly recently in response to op-portunities in Nebraska and Colorado,namely the Niobrara Shale. In contrastto Kansas, where drilling targets are rel-atively simple, shallow conventional ge-ologic formations and roadways are uni-formly spaced one mile apart on gridsacross flat rural terrain, Nebraska andColorado present surveying challenges.

“One recent project was in the hills ofFremont County, Co., where the terrainwas extremely difficult,” Jimenez states.“We are willing and able to adapt tosurvey design challenges as needed withour wired system.”

In Wyoming, Lockhart has multiplejobs lined up for 2-D cabled surveys withintersecting lines. “Some operators prefershooting 2-D for reconnaissance,” notesJimenez. “If they see something thatpiques their interest, they will order a 3-D survey focusing on a particular area.”

Lockhart has plans to add wirelessnodal systems in the future, given the ad-vantage the technology has in crew sizeand efficiency, reports Jimenez. The com-pany already has tested systems and

achieved a reliability rate exceeding 99percent. Nodal systems have a batterylife sufficient to last for the duration oftypical surveys conducted for operatorsin Kansas, he notes. “We can finish thejob, charge, download data and move onto the next job.”

If the client wants to see some wirelessnodal data in real time, Jimenez says thecompany plans to lay out a wired line sothe client can see how the data is affectedby strong winds or any other environmentalconditions. And that, he points out, is thebig advantage of cableless systems. “Nodescan be completely buried, you can makethem almost disappear,” Jimenez com-ments.

He says the ideal solution for Lockhartis a true all-in-one node, where no wiresare exposed. When there are no exposedwires, they are not an attractive nuisancefor cows or other animals to tug on. “Wespend about two hours a day troubleshoot-ing problems that often happen becausewires have been pulled or damaged,”Jimenez concludes.

More Science Required

Natural gas production from the Mar-cellus Shale is at record levels, but aftermore than a decade of concerted devel-opment, operators are beginning to ventureoutside the established fairways, accordingto Steve McCrossin, president of PrecisionGeophysical in Millersburg, Oh.

“With known sweet spots getting drilledup, operators are stepping out of theircomfort zones and moving away fromthe core, which requires more science,”

he states, noting that geologic conditionsand reservoir properties can change dra-matically from one part of the Marcellusplay to another. “Operators are relyingon high-resolution seismic to better un-derstand noncore areas and properly definesubsurface features for drilling hazardidentification and derisking.”

Precision Geophysical maintains twocrews equipped with the ARAM Aries™24-bit system and Geospace Sensors’GS-32CT™ high-frequency geophonesfor both 2-D and 3-D recording witheither cabled or cable-free (or both) ac-quisition methods. In mid-July one ofthe crews was working a project in theUtica Shale in Southeastern Ohio, andthe other was working on a Marcellusproject in Pennsylvania. “Both are pro-prietary 3-D shoots for oil and gas com-panies,” McCrossin reports.

Like other horizontal resource plays,one of the primary applications of 3-D inthe Marcellus/Utica is geosteering lateralsto total depth. “In the past, operatorshave found that horizontal wells oftendrilled in and out of zone,” he explains.“The uniqueness of 3-D seismic data,combined with logging-while-drillingdata acquired at the bit, lets directionaldrillers keep the drilling assembly in zoneall the way to planned TD.”

According to McCrossin, staying withinthe targeted zone is especially critical giventhe fast penetration rates that have becometypical of Marcellus/Utica drilling, withoperators regularly reporting daily horizontalfootage rates of 4,500 or more. Of course,when drilling a mile of rock every 24 hours,drifting out of the target window for even5-10% of the time can mean hundreds offeet of nonproductive lateral section.

“Fast drilling times have become rou-tine for many Appalachian operators,”McCrossin comments. “Using seismicdata for geosteering lets them achieveboth high well productivities and highlevels of horizontal drilling efficiency.”

Marcellus/Utica surveying challengesare related largely to the fact that theregion is both heavily populated and haschallenging terrain, McCrossin says. “Be-cause of the congestion, the challengingpart is getting surface permits so thatthere are not lots of areas within a surveylayout where data cannot be acquired. Ittakes time to get all the permits, but it’sworth it.”

He adds that the company uses existingroadways to layout and deploy equipmentwhenever possible. “It can be a little

In late July, one of PrecisionGeophysical’s two seismiccrews was acquiring a pro-prietary 3-D survey in theUtica Shale in Ohio, while theother crew was shooting aproprietary 3-D survey in theMarcellus Shale in Pennsyl-vania. One of the primary ap-plications of 3-D in theMarcellus and Utica isgeosteering laterals ‘in zone’all the way to total depth.

Knox County Ohio

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scattered when we get into towns, but ifyou do a good job with the permittingand can get Vibroseis™ through the area,data quality can be kept consistent withminimal skipped areas,” McCrossin states,pointing out that the ARIES system alsoenables “live” analysis to ensure qualitycontrol as data collection proceeds.

“You can see the data in real time as itis being recorded,” McCrossin relates.“If quality starts falling off, we canincrease the source energy or maybe de-termine that it is too noisy and temporarilyhold up on shooting. There could be anairplane passing over some loud surfaceactivity. Real-time QC is the only way tohave this knowledge and accommodatefor issues while recording is active.”

When coupled with the GS-32CT close-tolerance geophones for more usable dataacross the seismic bandwidth, he saysARIES also gives Precision Geophysicalthe flexibility to design richer and higher-density surveys to meet client needs inthe Marcellus/Utica. “As operators stepout into less proven drilling areas, theygenerally run Vibroseis reconnaissance2-D lines to figure out where to focus fol-low-up 3-D surveys,” he remarks.

Then, the 3-D surveys are laid out ontight grids with closer line spacing, andoften include larger recording patches toachieve longer offsets for wider azimuths,McCrossin explains. “Our projects typi-cally have channel counts of 5,000-10,000,which enables the richer datasets andhigher resolutions,” he concludes.

High-Density Survey

Almost a decade ago, Fairfield Geo -technologies set off to build a large con-tiguous database in the Delaware Basin.The DB1 survey conducted at that timehad five times the density of previous sur-veys, collecting nearly 1.4 million tracesper source square mile, says Joe Dryer,president of Fairfield Geotechnologies.

Then in 2017, the company’s RedTank survey to the north increased cov-erage by 20 percent, with more than 1.6million traces per source square mile forthe same number of source points. “Therewas an immediate impact on image qual-ity,” Dryer remarks.

Now Fairfield’s latest Permian survey,which began in early 2019, is 10.5 timesthe density effort at Red Tank, he reports.The C-Ranch project has 16.8 milliontraces per source square mile and 1,369source points. “Trace density is now beyondwhat seemed possible only a few years

ago,” states Dryer. “We believe the newparameters will greatly benefit rock prop-erties characterization, improve signal-to-noise ratio, and result in better imaging.”

In South-Central Louisiana, Fairfieldis partnered with CGG on a frontier AustinChalk opportunity. The project is analogousto Texas in that a significant uplift intrace density will provide a better under-standing of the formation, which has re-cently regained industry interest, Dryernotes. The project deliverables includeAVO-compliant and inversion ready datafor fast-track reservoir characterization.

Full-azimuth, long-offset 3-D datafrom these surveys offer the potentialfor significantly better insights intorock properties key in field planning,Dryer explains. “As data quality hasimproved, operators have increasinglylooked to seismic data to find sweetspots,” he says. “Additionally, seismicis playing an increasingly importantrole in well spacing, lateral orientationand enhanced recovery.”

Trace density is particularly helpfulin understanding the complex near-surfacegeology common in some areas of thePermian Basin. “Careful processing ofhigh trace-density data helps see throughseismic signal distortion caused by thiscomplexity,” notes Dryer. “Adding knowl-edge of the subsurface and geologic con-straints to the velocity model results ingreatly improved seismic imaging, ulti-mately leading to greater exploration suc-cess with lower risk.”

Similarly, in the marine environment

new “sparse” ocean-bottom nodal geome-tries are acquiring long-offset, full-azimuthdata required by imaging techniques suchas full waveform inversion (FWI). “Theexpectation is that the resulting improvedvelocity model will result in significantlyimproved imaging,” says Dryer. “The sameprincipal applies on shore, where newdata, well sampled in offset and azimuth,is driving interest in FWI to get a moredetailed near-surface velocity model.”

New acquisition geometries that resultin significantly larger data volumes haveled to other changes at Fairfield Geot-echnologies. The company no longer hasa physical computing center. “It is allabout efficiency and scalability,” Dryerstresses, saying that the move to cloudcomputing enables the company to scaleup computer resources on demand.

“We can bring thousands of processorsto bear on raw survey data without in-curring the cost of owning and maintainingthe computing technology,” Dryer explains.“The cost is variablized, enabling us todeliver quantitative interpretation-readydata much faster and more cost efficientlythan ever before.

The value extractable from the datais tied directly to data quality and thequality of the data processing. To thatend, Dryer points out that Fairfield Ge-otechnologies has seen an uptick in re-processing related mostly to proper dataconditioning for reservoir and rock prop-erty characterization.

He adds that Fairfield Geotechnologieshas teamed with Ikon Science, which

SpecialReport: Seismic & Geophysics

Fairfield Geotechnologies’ C-Ranch high-density survey in the Permian Basin has 16.8million traces per source square mile and 1,369 source points. In some areas in the Per-mian, a shallow high-velocity anhydrite zone greatly complicates imaging. New surveyparameters that densely sample the subsurface in offset and azimuth lead to better ve-locity models that improve imaging.

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offers geoprediciton software and services.“We recognized early on that our clientswere looking to get more out of theirdata. Our joint venture with Ikon Scienceis a good example of how we think inter-preters can extract the most value out oftheir data,” Dryer observes.

He explains that the partnership givesclients the option to get an interpretation-ready dataset that puts them on the fasttrack to decision making, saying “Timeis everything, particularly in unconventionalplays. We streamlined the process fromacquisition to interpretation, cutting thetime to analysis dramatically.”

“These are exciting times for the in-dustry,” Dryer concludes. “Denser surveys,precision processing techniques and un-limited computing power are leading toenhanced recovery rates.”

Revealing Critical Insights

Microseismic technology got its startas a means of measuring completion ef-

fectiveness. Now it has exciting new ap-plications in evaluating wellbore spacingand placement, predicting well production,mitigating interwell interference, and evenmaximizing the return on investment forhydraulic fracturing treatments, says Mi-croSeismic Inc. President Peter Duncan.

“We can estimate the pressure drawdownaround wells as a function of time,” saysDuncan. “Pressure drawdown tells operatorswhich stages along the lateral are producinghydrocarbons and which are not, and alsoreveals critical insights to answer questionsabout interactions among hydraulic fracturesin multiple wellbores.”

After initial success in completionmonitoring and analysis, MicroSeismicbegan using reservoir simulations basedon microseismic data to predict productionperformance. A look back on three years’worth of projects showed excellent historymatching, says Duncan. To deliver specificvalue for reservoir engineers, however,he says, the company went a step farther

to analyze well spacing and its related re-turn on investment and net present value.

“To prove the technology, we did astudy in which we monitored wells inthe Permian Basin and calculated pressuredrawdown over time,” explains Duncan.“We started with four wells, then modeledand predicted returns for drilling additionalwells per section.”

“Adding two more wells yielded almost50 percent more hydrocarbons, with a pos-itive NPV of 28% after considering extraoperating costs,” continues Duncan. “Thatwas a good investment, but if we doubledthe wells, there was only a 60 percent in-crease in hydrocarbons, taking the NPVnegative compared to the base case.”

To get the most accurate modeling re-sults, Duncan advises integrating as muchavailable data as possible, including 3-Dseismic, rock stress data, property data,and rock mechanics. “Microseismic addsa different perspective, for example, inidentifying faults that have a more hori-zontal motion with very little verticaloffset,” he explains.

Duncan asserts that this approach usingmicroseismic integrated with other typesof data is the ideal solution for evaluatingwellbore spacing/placement in resourceplays with multiwell pads. There is eveninterest among operators for applying themethod to conventional reservoirs, al-though he says that would be a muchmore difficult analysis because conven-tional carbonate and sandstone-type reser-voirs tend to respond to fracturing acousti-cally at much lower levels.

With a reservoir model in hand, en-gineers can have an idea of how eachwell should be stimulated to maximizereturn on investment. “They can watchthe well treatment in real time and followa template to see when the treatmentreaches the goal,” says Duncan. “Theyalso can monitor how the rock fracturesand map the stimulated reservoir volumein real time to help prevent parent/childwell interactions.”

Ultimately, the technology gives theoperator the ability to make decisions inreal time and make on-the-fly adjustmentsto the pump schedule during fracturingtreatments to increase bottom-line wellperformance. “We are moving towardbeing able to judge the return on invest-ment to the point of being able to say,‘Fifteen more minutes of treatment willgenerate a net present value of X amount,’”concludes Duncan. “If NPV is positive,the treatment would keep going; if it isnegative, treatment would stop.” ❒

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Prod

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2,500

2,000

1,500

1,000

500

Time 20 Years

*Assumptions: $50 WTI, $3 HH,10% discount rate, $2.5 mm well cost

4 Wells

6 Wells

4 Wells

6 Wells

$19,285,000

$24,770,000

+43%

+28%

NPV/Section*(Production-Well Cost)

Going beyond stimulation monitoring and analysis, MicroSeismic Inc. is using microseis-mic data in reservoir simulations to predict production performance over time. As illus-trated here, combining microseismic data with a proper economic analysis shows that a50% increase in the well count per section would increase hydrocarbon production by43%. That would be sufficient to offset the additional completion and operating costs as-sociated with a six-well rather than four-well development plan and result in positive NPV.

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