Practical Migration, deMigration and Velocity ModelingThe modeling study conﬁrmed Single source Longer offsets Not shown: Rock physics modeling illustrated that AVO/4D analysis would

Practical Migration, deMigration and VelocityModeling

Scott Field

Bee Bednar

Panorama Technologies, Inc.14811 St Marys Lane, Suite 150

Houston TX 77079

July 11, 2013

Bee Bednar (Panorama Technologies) Practical Migration, deMigration and Velocity Modeling July 11, 2013 1 / 66

Outline

1 Scott Field — UK North Sea

2 Fake Rocks


Scott Field — UK North Sea

Outline


2 Fake Rocks



Synopsis

This study from the Scott Field, North Sea represents an amalgamationof work over a ten year period during which three 3D data volumes wereacquired and data was almost continuously re-processed. High initialproduction rates but unexpected water breakthrough Early wells towardscrest were disappointing and required new 3d survey in 1996.

Here we overview some of the survey planning.



Scott Field UKCS

Outer Moray FirthJurassic SandFault block

Four maincompartmentsSatellite fields



Regional Seismic Line

Figure: Nearby regional seismic line from Hibbert and Mackertitch (1993) Showinggeneral tilted fault block trend and Jurassic stratigraphy



General Scott Seismic Cross-Section

Awarded in 1972Ivanhoe field 1975

8000 ft TVDSS

Initial well missedDiscovered in 1983

12,000 ft TVDSS



General Scott Seismic Cross-Section

The field structure, effectively a large southwards tilted fault block, iscompartmentalized into a series of four main pressure isolated fault blocks by midto late Jurassic faulting. The Kimmeridge Clay Formation provides both the topseal and the source of the trapped hydrocarbons

The Scott Field, Blocks 15/21a, 15/22, UK North Sea, Simon Guscott, KenRussell, Andrew Thickpenny & Robert Poddubiuk in GLUYAS, J. G. & HICHENS,H. M. (eds) 2003. United Kingdom Oil and Gas Fields,CommemorativeMillennium Volume. Geological Society, London, Memoir, 20, 467D482.



Scott Facts

Upper Jurassic reservoirs in a series of rotated fault blocksHighly compartmentalizedComplex structural evolution including multi-phase faulting and inversion

35 sq km area 43 well: 2 platformsUpdip production wells with injector downdip to maintain pressureCrestal areas originally avoided as the seismic data poor quality23 producers, 20 injectors, 2 reservoirs

Upper Piper and lower Scott (shore face) sand reservoirsSeparated by a regional transgression shaleBest quality reservoir (20% porosity) at crest

Production History220,000 STB in 1995.80,000 STB in 1999 with 60% water cut

Ultimate recoverable reserves ± 440 MMSTB (46%)Scott Field was one of the largest developments in UKCS during the 1990s

Operated by Hess, then Talisman, and now Nexen



Scott Field

Outer Moray Firth, North SeaDiscovered 1983

From 2D time grid

First oil 1993, 7% UK production3D seismic

1985, 1990, 1996, 2001

OBC undershoot in 1996Full OBC in 2001



Exploration History

1990 Exploration SurveyShot NW-SE in 2 phasesOne part single source 60 foldOne part dual source 40 foldMinimal navigation processingStrike to main bounding faultAppraisal, equity, and development6 1990 surveys limited resources

Exploration Surveys≈ $200 sq km (1990)Relaxed acquisition parametersRelaxed processing parametersFit for purpose?



Initial Poststack data quality

1990/1991 ProcessingDesignatureDeconvolution Before StackDip Moveout (DMO)Stacking Velocity AnalysisStackDeconvolution After Stack2-Pass Time MigrationFilterScale

1992 Equity ProcessingNew Velocity Analysis1-Pass time ””high-dip”” timemigration

HDTMIG an implicit XT mig

Filter and Scale



Mapping after Hibbert & Mackertich (1993)

3D data were used to extract isopach maps for the main geological units(Paleocene through to Jurassic)

Map time horizonsDepth convert using well data (V0 + kz)Maps illustrate the main tectonic elements and sedimentary depocenterspresent during these periods.

3D horizon dip was also extracted as an attributeThese attribute maps show the dominant fault/lineament trends that transecteach seismic horizon.Integrated with the isopach maps they show dominant fault trends anddepositional influence through time.

Little else was normally extracted from 3D data at this time



Geophysical Objectives

Jurassic reservoir, 3-4s, 20 degreemaximum dipsReservoir beneath variablethickness chalk layerNo near surface gas problems, butchannelsReservoir acoustically transparentso 4D not relevant ?Main objective:

structural resolutionimprove upon 1990 data

Secondary:AVO/attributes/porosity4D effects ?



Scott Shooting Direction

Dip versus Strike?Topic of some concern in 1990(WATS Today)

If the structure is polarized; e.g,.salt wall, then

Strike shooting may reducenon-hyperbolic moveoutDip shooting may be easier toidentify structures

Easier velocity picking andmultiple suppression

Mother Earth is 3DNo defined dip direction

3D modeling to assess shootingdirection



Scott Modeling Approaches

3D model required for all methodsRay tracing

Fast.Basis of many survey planningpackagesHigh frequency approximation

Poor Amplitudes

Usually a single arrival method

Waveform: finite differenceAccurate

Cost proportional to F 4

Very slow (hence expensive)No longer true (GPU’s)16km cubes in 20 minutes20,000 shots in a few days

Generates all arrivals3D no longer expensive



Scott Modeling Approaches

Waveform: Phase ScreenIntroduce by Wu (1994)

Modeling and Migration10 times as fast as FD

But limited to 90 degreePoor amplitudesUseful took for quick analysis



Scott Modeling Shot Records

Split-Spread 12km gathers50 m shot intervalGathers edited to 4,500 km cables25 m group interval



Exploding Reflectors

2d or 3d model can be compared toreal world data to address problemsin acquisition, processing orinterpretation.Here we initially used post-stackmodeling to verify the model andtest post-stack migration algorithmsExamples

Post-stack processing parametersResolution studiesImaging, time versus depth,algorithm comparison studies




























Synthetic vs Real Migrations

(a) 3D Poststack Time (b) 3D Beam Stack PSDM

Modeling can be used to determine data qualityModel data can be used to illustrate optimum processing e.g. foramplitude, phase, resolution and imaging studiesOnce the post-stack modeling was deemed a success we could move to3D prestack modeling



Stack and Poststack Processing

Multiple free dataStackedFK Time migrated

Data with multiplesStacked and compared tomultiple free dataMultiple contamination ofreservoir is clear

Focus on optimal imaging



Prestack Imaging Comparison

(c) Stacked Section Picked Velocities (d) DMO/Gazdag PSTM



Prestack Imaging Comparison

(e) PSPI PSDM (f) Kirchhoff PSDM



Migration Cost-Benefit Analysis

Analysis used to study effect ofdifferent processing and imagingschemes on modeled dataBecause we know the answer this isone of the few methods we can use toattempt to quantify seismicprocessing results



Summary of Proposed Parameters

The modeling study confirmedSingle sourceLonger offsetsNot shown: Rock physics modelingillustrated that AVO/4D analysiswould have limited value

Confirmed by Nexen, 2009

Survey direction changeAs much as a result of logistical asgeological factors

OBC data was chosen as part of theplatform undershoot

Existing Proposed1990 1996Dual source Single Source50m shot 25m Shot30 fold 90 fold3km Cable 4.5km CableNo Platform OBCNW-SE N-S



Reshooting: Business Case

In field development cases the following arguments may assist in judgingthe ””business case”” – is this seismic stuff going to change my welllocations and make me more money ?

Seismic technically poor e.g. multiples, imaging, resolutionLocation of sealing faults criticalFaults in simulation do not match those on seismic so could be missingopportunity to drain parts of field4D effects, obviously if they can be backed up by rock physics modeling (notan issue for Scott).

Timing of the survey is always criticalSometimes easier to justify new or ””high technology”” e.g. OBCPolitical considerations



Business Case: NPV of 7 Prospects

If 7-8 wells are to be drilled with an NPV of $70M then even an expensive$10M new OBC seismic may be justified

Opportunity Reserves NPV NPVMMbbls No Seismic $MM With Seismic $MM

1 4-6) 0 24-302 3 0 183 5 0 264 2-3 10-16 12-185 2-3 10-16 12-186 2-3 10-16 12-187 2-3 10-16 12-188 2-3 10-16 12-18

TOTAL 21-28 50-80 128-144

Prospects 1, 2 & 3 are deemed too risky to drill without new seismic

Half the NPV cannot be realized without the new seismic

For a $10M well, new survey data maybe more valuable if prospects arediscarded !



Decision Tree



Data Value for Single Prospect (Well)



Scott Field: Development 1996

Development Survey 19966 cables single source4.5 km streamersProblems with rigsPlatform area undershot using2-component OBC

GenerallyFor development/appraisalcare must be taken to ensurethat the survey has themaximum shelf lifeStaff resources dedicatedUsually means more moneySince 1995 all surveys havesome 4D potential asamplitudes may be preserved.

Still issues with data quality andprocessing !!!



Scott Data Quality

(g) inLine (h) xLine

Inline and Crossline are of gooddata quality (which is which ?)Timeslice shows merged OBC dataand acquisition footprint.



PSTM vs PSDM Migrations



PSTM vs PSDM Migrations Detail



Scott OBC Data

Data quality much improved over 1990 data

OBC with three cables was shotto undershoot the platform area.Only second ever OBC surveyin the North Sea and theworldOs deepest at that time(140m water)Issues with data quality andsampling.Note also the hole due to rigactivity in the SW



OBC Gathers and Stack

Poor dataqualityOBC databut deepwaterStrongmultiplesfocusedover targetcrestalarea.Fold islowest heredue toplatform.

(i) OBC Gathers (j) OBC Stack



1996 PSTM

Original processing: streamerWave-equation multiplesuppressionRadon multiple suppressionMerge with obcPSTM (MovesTM type)

Original processing: OBC dataSum hydrophone/geophoneRadon multiple suppressionMerge with streamer dataPSTM (MovesTM type)



1996 PSDM

Original re-processing of OBC portionResum hydrophone/geophone

Soubaras, 1996

Radon multiple suppressionPSDMAggressive Radon multiple suppressionHorizon based multiple suppression

ImprovementsAll multiplesuppressionefforts failed



Conclusions and Updates

Development drilling, which had been suspended in early 1997, wasresumed in mid-1998 as results of the 1996 3D seismic survey becameavailable. The new data were a significant improvement over the 1993dataset, although parts of the field crest were still poorly imaged. Theimaging problem results from a weak acoustic impedance contrastbetween the oil-bearing sandstones and the overlying Kimmeridge ClayFormation mudstones at the crest, coupled with the presence of strongseabed and interbed seismic multiples.One notable success of the new drilling campaign was drilled on thewestern flank of structural Block I the well encountered a full reservoirsection, with the Scott Sandstone at near virgin pressures. When the wellcame onstream initial production rates were close to 25 000 STB/day ofdry oil but these rates ultimately declined due to lack of pressure support.The well produced c. 3 MMSTB solely under depletion drive until 1999when an injector was drilled.




Development drilling was suspended in mid-1999, resumed in 2000 andfocused on economically locating and exploiting bypassed oil. Pre-stackdepth migration of the 1996 3D seismic data indicate that it hassignificantly improved imaging over much of the field.A new 3D (full OBC) was shot in 2001 and operatorship changed toTalisman and now Nexen.In a 2009 paper Nexen reported:

Autumn 2008 had produced 400 M barrels.70 wells (drilling paused in 2004 after poor margin well results)2003 PSDM of 2001 OBC plus new interpretation and remapping. 2006post-stack freq enhance PSDM2005-2007 infill drilling with less focus on high risk, bypassed attic oil nearfaults. 6 successful wells.Still problems with crestal multiples, minor faulting ! Seismic reported as””significant”” value to asset adding production and reserves).




What’s different today?Cost effective full waveform modeling and imaging

Anisotropic30,000 VTI shots over 16km cubes in 48 hoursMulti-cable extraction and imaging over a variety of direction

Nearly interactive hypothesis testingAVO/AVAAttributesExploding reflector models

Surface Related Multiple SuppressionBut only with proper data acquisitionRegularization is still an issue


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Outline


2 Fake Rocks


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Emerging Solutions

An emerging general approach to resolution of of a varitey of hydrocarbonexploitation problems involves

Construction of an accurate and realistic subsurface modelConsistent with existing geologic interpretationsWith a sufficient number of horizons to capture detailed structureWhich includes Anisotropy when and where requiredHas sufficiently realistic reflectivity to provide a reasonable analysis platformComposed of reservoir properties for assessing reservoir characterizationpotential


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Emerging Solutions

Synthesis of high quality full waveform wide azimuth (WATS, OBC,Nodes) dataExtraction and migration of realistic acquisition styles for

Cost/benefit analysisAssessment of amplitude accuracyQuantification of attribute predictabilityQuantification of seismic inversions

Application of various multiple elimination scenarios forQuantification of acquisition limitations on multiple suppressionAssessing the degree to which multiple suppression is important

Providing an initial model for full waveform inversion (FWI)


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Initial Model

(k) Horizons and Data

Figure: The initial Scott horizons and depth migration of the merged data.


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Initial Model

(a) Horizons and Vp

Figure: The acoustic velocity model and interpreted horizons used to construct it.


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A Modern TTI Model

Constructing a modern TTI includesInterpretation of a suite of realistic geologic horizonsHorizon based estimation of interval velocity between the horizons

Map demigration and migration was used to properly register the horizonsbetween iterative steps

Computation via Gardner-Gregory of a background density volume fromthe estimated velocity modelFull two-way reverse time migration of the Scott data

Using a true-amplitude angle domain imaging condition

Estimation of a reflectivity model from the background density andtrue-amplitude RTM of the Scott dataEstimation of δ and ε at selected well locationsHorizon based interpolation of the estimated δ and ε

Horizon based interpolation of horizons based dip estimates to providesymmetry angled for TTI extrapolation


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The VTI model

(a) Structural Surfaces with Reflectivity

Figure: A geologically consistent VTI Earth model derived from existing borehole andthree-dimensional seismic data.


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The VTI model

(a) Vp



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The VTI model

(a) δ



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The VTI model

(a) ε



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The VTI model

(a) Reflectivity

Figure: Reflectivity derived from a reverse-time-true-amplitude migration of theexisting three dimensional North Sea survey


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The VTI model

(a) 3D Shot

Figure: 3D WAZ Shot.


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WATS Acquisition

(a) WATS Acquisition

Figure: Cross Line 8356 from the full WATS acquisition.


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WATS Acquisition

(a) Cross Line NAZ Acquisition

Figure: Cross Line 8356 from a NAZ (EW) acquisition.


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WATS Acquisition

(a) In Line NAZ Acquisition

Figure: Inline NAZ (NS) acquisition.


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WATS Acquisition

Inline NAZ (NS) acquisition. There are insignificant amplitude differencesbetween the two NAZ images, but the WATS image differs considerable fromthe other two.


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WATS Acquisition


Figure: Top reservoir from the full WATS acquisition


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WATS Acquisition

(a) Cross Line NAZ Acquisition

Figure: Top reservoir from the Cross Line Acquisition.


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WATS Acquisition

(a) In Line NAZ Acquisition

Figure: Top reservoir from the NAZ inline (NS) acquisition.


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WATS Acquisition

(a) In Line MAZ Acquisition

Figure: Top reservoir from the and a MAZ acquisition


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WATS Acquisition

In General WATS image amplitudes are more consistent with model basedreflectivity, the faults are much clearer and the multiples less destructive thencomparable events on the other three images. The best competitor to theWATS is the multi-azimuth MAZ image.


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WATS Acquisition


Figure: Piper illumination amplitudes from a full waveform (RTM) migration of the fullWATS acquisition.


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WATS Acquisition

(a) NAZ In Line Acquisition

Figure: Piper illumination amplitudes from a full waveform (RTM) migration of the InLine NAZ acquisition.


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WATS Acquisition

(a) NAZ Cross Line Acquisition

Figure: Piper illumination amplitudes from a full waveform (RTM) migration of theCross Line NAZ acquisition.


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WATS Acquisition

There are significant amplitude differences between all three images, but thetwo NAZ images differ considerable from the WATS image. Experience hasshown that the WATS image is the more accurate of the three. In this case,the acoustic transparency of the Jurassic sand may render the analysis mootbut it is worth noting that when amplitudes cannot be ignored, full azimuthdata may be required for optimization extraction.


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Questions?


Documents

Practical Migration, deMigration and Velocity ModelingThe modeling study conﬁrmed Single source Longer offsets Not shown: Rock physics modeling illustrated that AVO/4D analysis would