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                I Large scale deepwater sediment            I   Imaging Through Gas Clouds:
                remobilisation: examples from North             A Case History in the Gulf of Mexico
                Sea 3D seismic and outcrop
                                                            I   Neural Network Applications to
                I   Off the shelf seismic data processing       porosity Prediction; Hebron Field
                                                                offshore Newfoundland, Canada
                I   A seismic analysis of late albian age
                    submarine fan                           I   Depth Conversion Methodologies,
                                                                Uncertainty, Quantification, and
                I   Estimating TIV Anisotropy                   Application; Hebron Filed, Offshore
                    Parameters in The Jeanne d'Arc              Newfoundland Canada
                    Basin at White Rose H-20
By Leave of Poseidon
Poseidon was, like many of the Greek gods, difficult to please and dangerous when
affronted. Those who chose to risk the sea and acquire marine seismic know well the
special challenges attached to that endeavor. The unique problems in processing,
acquisition, processing and interpretation require a different set of techniques and thinking,
the consequence of which is that those who dare to choose this battle ground never forget
that they work upon the seas of the world.

                                       Sponsor in part by
Large scale deepwater sediment remobilisation :
examples from North Sea 3D seismic and outcrop
S.J.M. Molyneux 1; J.A. Cartwright2 and L Lonergan, T.H.Huxley School, Imperial College, London, UK.
  PanCanadian Petroleum Ltd, Calgary. 2Department of Earth Sciences, Cardiff University, Cardiff, Wales

The Palaeocene/Eocene to Mio-Pliocene sediments of the Central and Northern North Sea contain deepwater sediments with significant
hydrocarbon reserves within submarine fan sands encased in mudrocks. Post depositional processes have significantly changed the
original small and large scale geometry and reservoir characteristics of these deepwater sediments.

Examples of large scale remobilisation from 3D seismic, well and core data from the above intervals vary from cross cutting 10’s of
metres thick and 100’s of metres in extent intrusions of sands, kilometer scale seabed pockmarks, sand mounds with kilometre
wavelengths deposited between a mud mounded sea floor and syn to post depositional controlled polygonally faulted deepwater sands.

Outcrop analogues of large scale remobilisation are difficult to identify as the scale of these sandstone intrusion is often larger than the
outcrop available. Within Upper Miocene Santa Cruz Mudstone, Santa Cruz, California exist one of only two kilometre scale sandstone
intrusion complexes in the world. The intrusion of these sands is postulated to have been related to the expulsion of basinal fluids
including hydrocarbons and related overpressure build ups, as proposed for several of the intrusive examples above in the Tertairy of the
North Sea.

The geoscientist should be aware of the small to very large scale nature of sediment remobilisation which can significantly change
primary depositional geometries and physical properties of deepwater sediments. These above examples of remobilisation highlight the
great variation in reservoir character, which may significantly affect the petroleum exploration and development of such reservoirs.
Ignoring such features will lead to incorrect reservoir modelling and subsequent exploration and development “surprises”.

This paper outlines examples of large scale remobilisation as examined from 3 D seismic datasets from Tertiary deepwater reservoirs of
the North Sea.

Section 1 reviews previous works on large scale remobilisation and the processes which may be involved.

Section 2 documents a large scale intrusive complex in block 24/9 of the Norwegian Viking Graben (North Sea) in Palaeocene aged
deepwater sediments of the Balder Formation.

Section 3 outlines interpreted large scale sandstone intrusions within UK North Sea block 21/4 and 5 of Lower Eocene age deepwater

Section 4 outlines Lower Eocene aged pockmarks of UK North Sea block 15/18 which occur within deepwater slope deposits.

Section 5 describes kilometre scale interpreted deepwater sand and mud mounds of the Lower to Middle Miocene Utsira formation in UK
North Sea blocks 16/27, 28 and 29.

Section 6 presents the Upper Eocene Belton Member deepwater sands which are interpreted to have been controlled in their deposition
by polygonally faulted lows and highs forming displacing the palaeo muddy seafloor.

Section 7 reviews a coastal exposure of a large scale sandstone intrusion complex which extends over a kilometre within Upper Miocene
Monterrey diatomaceous shales, at Yellow Bank Creek, Santa Cruz, California.

Finally, section 8 summarises the potential effect large scale remobilisation may have on exploration and development of deepwater

1 - Review Of Large Scale Remobilisation
Reservoir remobilisation can be defined as : “any comprehensive redistribution of reservoir units from their original depositional
configuration due to pore pressure build up”.

Small scale (mm to metre) remobilisation of deepwater sandstone reservoirs in the form of sandstone dykes and sills has been
recognized in outcrop and in core since the 1900’s (see review of sandstone intrusions in Allen, 1985 ). Large kilometre scale
remobilisation of deepwater sediments has been rarely observed and only two documented outcrops exist worldwide ,(a) Ordovician

sandstone intrusion complex of the Southern Front Range, Colorado, USA (Harms, 1965 ) and (b) Upper Miocene sandstone intrusion
                                                                       3                 4                  5
complex, Yellow Bank Creek, Santa Cruz, California, USA (Jenkins, 1930 ; Thompson, 1995 ; Thompson, 1999 ). Only recently has large
scale remobilisation been recognised subsurface with the advent of 3D seismic. Dixon, 1995 highlighted large scale injection and
remobilsation of sands from the Forth/Harding hydrocarbon field reservoired in North Sea Tertiary deepwater sediments. Thicknesses of
sandstone intrusions reach upto 10’s of metres with lateral extent over 100’s of metres. Sandstone intrusions also occur within similar
                                                                                  7                       8                9
aged Tertiary North Sea deepwater sediments of the Balder (Jenssen, 1993 ), Gryphon (Jaffri, 1993 ; Timbrell, 1993 ), and Alba
(Lonergan and Cartwright, 1999 ) hydrocarbon fields.

It is important to note that these deepwater turbidite sands were deposited within extensive deepwater muds which were pervasively
deformed by polygonal faults. Polygonal faults are a response of muds to expelling water in three dimensions almost immediatley upon
                                                11        12                                 13      14                             15
deposition and during burial (Cartwright 1994a , 1994b , Cartwright and Lonergan 1996 , 1997 , Cartwright and Dewhurst 1998 ;
Lonergan 1998 ). These faults on seismic data sets have a polygonal pattern in plan view, are spaced between 100 to 1000 metres
apart and have displacements of between 10 to 100 metres.

Below are a series of large scale remobilisation examples interpreted from 3D seismic, well and core data from the North Sea (section 2
to 7) and an outcrop example from California, USA (section 8).

2 - Norwegian North Sea Block 24/9 Palaeocene Balder Formation Large Scale Intrusive Complex
Large and small scale sandstone injection features (discordant dykes, sills and clastic intrusions) are documented from 3D seismic, well
log and core data in Late Palaeocene to Eocene sediments from Norwegian North Sea block 24/9.

The study area is located in the axis of the South Viking Graben, with Tertiary deepwater sediments supplied mainly from the west. Two
wells in the block (24/9-5 and 24/9-6) encountered oil in massive sandstones of late Palaeocene/early Eocene age (Balder Formation),
corresponding to a high amplitude response on seismic. These sandstones are confined to an isolated east/west trending fault bounded
low, and vary from a few metres to 40m thick. Deposition from detached sand-rich debris flows or high energy turbidity currents is

Evidence for modification of depositional geometry is present at all scales. From seismic data, steeply dipping high amplitude continuous
reflectors (10 to 50 msecs TWT/ 10-50 metres thick) can be followed from within the Balder, up along fault planes and into Eocene
sediments above cross cutting up to 200m of stratigraphy at an angle of 10 to 30 degrees. The top of the Balder reservoir is complexly
faulted, though many of these faults do not offset the base reservoir surface. Discordant sandstone dykes, shear fractures and
compactional features in core suggest early sand remobilisation.

These steeply dipping high amplitudes originating from the Balder below are interpreted to be 10 to 50m thick sandstone intrusions.
Injection is postulated to have occurred by expelling basinal fluids and hydrocarbons during the Eocene to Miocene, which built up
overpressure in the isolated Balder age sands below, with overpressure being released during during fault movement.

The Balder discovery contains hydrocarbon reserves, but untested upside in the form of the injected sandstone high amplitude limbs
could form a well-connected reservoir, cross-cutting stratigraphy, and increasing recoverable reserves. If successfully proven, field
development would be optimised by locating producing wells in the higher injected portions, draining connected reservoirs in the Balder

3 - Uk North Sea Blocks 21/4 And 5 Lower Eocene Aged Large Scale Sandstone Intrusions
Kilometre scale, Lower Eocene “V” shaped amplitude anomalies, have been recognised on 3-D seismic surveys from the UK Central North
Sea. These features are interpreted as concave upward conical sandstone intrusions. They are typically circular to elliptical in map-view
with diameters of single cones ranging from 0.5 to 2km. Their sides are 100-300m tall, and dip between 5 and 15 degrees (compacted).
Intrusion width is 10 to 50 msecs which calibrates to 10-50 metres of sandstone exhibiting a blocky, low gamma ray character on
wireline logs. The conical sandstone geometries can be isolated or developed as compound structures amalgamated in clusters covering
hundreds of square kilometres. These amplitudes match the geometries of polygonal faults which pervasively deform the encasing Lower
Eocene muds.

We considered several possible genetic models for these structures, including palaeo-pockmark craters, collapsed gas hydrate diapirs,
and even isolated fan channel ribbon deposits. However, the preferred explanation is that upward migration of thermogenic methane
generated from Jurassic source rocks released during earthquake or by auto-triggered failure of pressure seals led to inflated fluid
pressures in isolated Palaeocene or Eocene deep water sandbodies. Catastrophic pressure inflation (internal blow-out) then led to large
volume liquefaction of the sands, and upward conical injection which exploited pre-existing fault and fracture networks (polygonal faults),
in the low permeability claystones of the Lower Eocene. We believe that these Lower Eocene intrusions are the largest reported
subsurface examples of clastic remobilisation, which by their very scale may have been overlooked or misinterpreted in outcrop in other

4 - Uk North Sea Block 15/18 Lower Eocene Aged Large Scale Pockmarks (Cole, D, 1998 )
A detailed 3D seismic interpretation has identified crater-like structures in the Paleogene sediments of block 15/18, Outer Moray Firth, UK
North Sea. The structures range from 500 metres to 4 km in diameter and are between 50 to 200 metres deep.

The structures are confined to one stratigraphic level, at the top of the early Eocene Balder Formation, and are restricted to an area of 15
x 15 km square within the available 3D seismic coverage.

The craters appear to cut down into the top Balder Formation on 3D seismic data. They have seismically chaotic infill and mounded
overlying reflectors. Planar high amplitude “wings” are located on the flanks of several of the structures.

Well data suggest that the structures are themselves sand-filled, but occur within an argillaceous and tuffaceous unit. A 100m thick
mudstone unit overlies the structures. The planar “wings” appear to be intruded sandstone dykes.

Shallow gas eruptions on the early Eocene seafloor is the most likely mechanism for the formation of the craters as explosively formed
seabed pockmark craters. The gas may have been sourced from deep Jurassic or Carboniferous sediments within the Witch Ground
Graben, or it could have originated in the Palaeogene delta sediments within the study area.
                                                                                                     6   3
Similar structures may prove to be effective hydrocarbon plays. The structures are large (100 x 10 m gross volume) and appear to be
infilled with clean, massive sand. The suggested mechanism requires large-scale early Eocene hydrocarbon migration. If correct this is
evidence of both a mature source and effective migration pathway. Migration of hydrocarbons would need to continue after deposition of
the top seal to allow any entrapment. The overlying muds provide a competent top-seal to have forced sandstone diapirism. These muds
may still act as an effective top-seal in restricted areas.

5 - Lower To Middle Miocene Utsira Formation Kilometre Scale Sand Mounds, Uk North Sea Block 16/27,
28 and 29
The Lower to Middle Miocene (Utsira Formation) of the UK North Sea blocks 16/27, 28 and 29 contain elliptical to circular mounded
features, 1 to 2km wide, 0.5 to 10km long with a vertical relief of 50-100 metres.

They onlap a muddy strata below of Oligocene age, have flank dips greater than 7 degrees (compacted) and are formed of massive sands
as noted from well control. These mounds occur over 10’s of thousands of square kilometres of deepwater basinal shales of the Central
North Sea.

The Utsira sand mounds are interpreted to be lowstand turbidite sands sourced from marine sands to the North in the Northern North Sea
                  18     19
(Gregerson 1997 , 1998 ), some 300 km away. These sands deposited onto a mud mounded sea floor with kilometre wavelengths.
                     20                                                                                                              21
Anketell 1970 predicted such mounding within muddy substrates. Similar geometries have been noted by Davies 1999
within the Oligo – Miocene succession of the Faeoroe-Shetland Trough and Vogt (1997 ) in Pliocene sediments of the Norway Basin.

6 - Upper Eocene Belton Member Deepwater Sands Syn and Post Depositionally Polygonal Fault Controlled, Norwegian North
Sea Block 24/9
Upper Eocene deepwater turbidite sands (Belton Member) of Norwegian offshore block 24/9 are expressed as a high amplitude reflection
on 3D seismic data on a low amplitude palaeo sea floor of mud. Well data calibrates these amplitudes as blocky sands between 0 to 100
metres thick. These turbidite sands have been compartmentalised by polygonal faults which pervasively deform the muds. Amplitude
maps and well data indicate that the sand is preferentially concentrated in the polygonally faulted lows on the Upper Eocene surface.
These polygonal faults have fault displacements upto 300 metres in extreme cases, but more commonly between 10-50 metres and
spaced 100 to 1000 metres.

The preferred interpretation is that the Belton Member sands deposited as deepwater sands onto a polygonally faulted palaeoseabed,
which concentrated deposition of sands within the downthrown lows.

7 - Upper Miocene Large Scale Sandstone Intrusion Complex, Santa Cruz, California, USA
Giant scale sandstone intrusions are exposed on the coastline North West of Santa Cruz, California. They are the largest scale clastic
intrusions in the world.

Sandstone dykes and sills of between 1cm and 300metres width, intruded into Upper Miocene diatomaceous mudstones, probably as a
function of minor Pacific Plate reorientation at 4Ma (Casey Moore pers.comm. 1999). The intrusion is related to movement along a series
of wrench faults at this time, part of the San Gregorio/San Andreas fault zone (Casey Moore pers.comm. 1999). The dykes and sills in
outcrop are fine to coarse grained poorly dolomite cemented clean massive sandstones. The sandstone is often partially stained with
degraded oil which at Yellow Bank Creek, the site of a 300m wide sill/dyke, display as complex banding and balls/pillows of migrating
hydrocarbons. These giant scale clastic dykes and sills may have been associated with migrating hydrocarbon fluids, expelling from
offshore basins into this regionally higher, basin margin position.

8 - Exploration and Development Issues Related to Large Scale Remobilisation of Deepwater Reservoirs
Interpretation of deepwater sandstone reservoirs is normally based on the interpretation of reservoir geometry that has a primary
depositional origin. However, seismic and core evidence from isolated deepwater sandbodies in the Palaeocene and Eocene of the North
Sea and the Californian field analogue reviewed above shows that original depositional geometries can be significantly modified by sub-
surface remobilisation of sands by processes related to elevated pore fluid pressures which may involve hydrocarbons including gas.
Important points to note regards large scale sandstone remobilisation are:

(a) Post depositional remobilisation of deepwater sediments is an important element in reservoir interpretation and modelling.
(b) Remobilisation involves in situ, higher pore pressure related processes such as fluidization and liquifaction of porous, poorly
    cemented sandstones at some stage during burial and reconfiguration of the original depositional geometry.
(c) Remobilisation changes reservoir properties and geometry: reservoir characterisation must be approached with this in mind.
(d) Failure to identify remobilised reservoirs prior to completion of the reservoir model will lead to unexpected results during
    development drilling.
(e) Large scale intrusion complexes may be related to tectonic activity and related flow which may also be associated with the
    migration of hydrocarbons from basinal kitchen areas. The presence of gas may be a large factor in heightened pore pressures
    associated with intrusions.
(f) Relationships to active faulting and folding such as large scale polygonal faulting of clay dominant systems may affect primary
    deposition of deepwater sand reservoirs and significantly change final reservoir geometry.
(g) Geometry of typical dyke-sill complexes is highly variable and complicated.

Wide varieties of geometries exist, from simple vertical dykes and horizontal sills to more complex sill-dyke geometries with conical,
rectilinear or radial patterns, sea floor mounds, and pockmarks.

Large scale deepwater sediment remobilisation is a poorly documented and understood phenomena. The field geologist, seismic
interpreter and petroleum geologist should bear in mind the scale and likely reconfiguration remobilisation may have on deepwater
sediments in outcrop, well and seismic data. Incorrect recognition of remobilised sediments may for the petroleum geoscientist lead to
subsequent exploration and development “surprises”.

The authors wish to thank Fina North Sea Ltd for funding the authors PhD research at Imperial College, London UK with special thanks to
Mick Cope and Rod Laver. Fieldwork in California was sponsored by an American Association of Petroleum Geologist and Petroleum
Exploration Society of Great Britain student fund, and a London University Research Grant. Many thanks for discussion on the process of
sediment remobilisation go to Edwin Tervoort, Dustin Lister, Richard Evans, Nick Lee, Dave Dewhurst and Richard Jolly while at Imperial
College, London, UK. Finally, thanks to PanCanadian Petroleum Ltd for encouraging me to present this work, especially Ian McIlreath of
the Calgary office and Alan Booth of the UK office. Special thanks too Chris Paton and Pentagraphix for computing advice during
construction of this paper. Views in this paper are those of the authors.

Allen, J.R.L., Principles of Physical Sedimentology, George, Allen and Unwin, 1985. 272p.
Harms, J.C., Sandstone Dikes in relation to Laramide Faults and Stress Distribution in the Southern Front Range, Colorado. Geological
      Society of America Bulletin, 1965, 76, 981-1002.
Jenkins, O.P., Sandstone dikes as conduits for oil migration through shales. Bulletin of the American Association of Petroleum Geologists,
      1930, 14, 411-421.
Thompson, B.J., Geometry and fluid flow mechanisms of the bituminous sandstone intrusion at Yellow Bank Creek, western Santa Cruz
      County, California : Thesis for Masters Degree, University of California, Santa Cruz, unpublished. 1995.
Thompson, B.J., Garrison, R.E. and Moore, J.C., A late Cenozoic intrusion west of Santa Cruz, California : fluidized flow of water and
      hydrocarbon-saturated sediments. In : Late Cenozoic fluid seeps and tectonics along the San Gregorio fault zone in the Monterrey
      Bay region, California (eds) Garrison, R.E., Aiello, I.W. and Moore, J.C., Annual Meeting of the Pacific Section AAPG, Monterrey,
      California, April 1999, 1999.
Dixon, R.J., Schofield, K., Anderton, R., Reynolds, A.D., Alexander, R.W.S., Williams, M.C. and Davies, K.G. , Sandstone diapirism and
      clastic intrusion in the Tertiary Submarine fans of the Bruce-Beryl Embayment, Quadrant 9, UKCS. In: Hartley, A.J. and Prosser,
      D.J.(eds), Characterization of Deep Marine Clastic Systems, Geological Society Special Publication, 1995. 94, 77-94.
Jenssen, A.I., Bergslien, M., Rye-Larsen, M. and Lindholm, R.M., Origin of complex mound geometry of Palaeocene submarine-fan
      sandstone reservoirs, Balder field, Norway. From: Petroleum Geology of Northwest Europe Proceedings of the 4 Conference
      (edited by J.R.Parker), 1993. 135-143.
Jaffri, F., Cross-cutting sand bodies of the Tertiary, Beryl Embayment, North Sea, 1993. Unpublished PhD thesis,
      University of London, UK.
Timbrell, G., Sandstone architecture of the Balder Formation depositional system, UK Quadrant 9 and adjacent areas. From: Petroleum
      Geology of Northwest Europe: Proceedings of the 4 Conference (edited by J.R.Parker), 1993. 107-121.
Lonergan, L. and Cartwright, J.A., Polygonal faults and their influence on deepwater sandstone reservoir geometries, Alba field, UK
      Central North Sea, 1999. AAPG Bulletin, 83, 410-432.

Cartwright, J.A., Episodic basin-wide fluid expulsion from geopressured shale sequence in the North Sea basin, Geology, 1994a.
      22, 447-450.
Cartwright, J.A., Episodic basin-wide hydrofracturing of overpressured Early Cenozoic mudrock sequences in the North Sea basin, Marine
      Petroleum Geology, 1994b. 11, 587-607.
Cartwright, J.A and Lonergan, L., Volumetric contraction during the compaction of mudrocks: a mechanism for the development of
      regional-scale polygonal fault systems, Basin Research 1996. 8, 183-193.
Cartwright, J.A. and Lonergan, L., Seismic expression of layer-bound fault systems of the Eromanga and North Sea Basins, Exploration
      Geophysics, 1997. 28, 323-331.
Cartwright, J.A. and Dewhurst, D.N. Layer-bound compaction faults in fine grained sediments, GSA Bulletin, 1998. 110; no 10;
Lonergan, L., Cartwright, J.A. and Jolley, R., The geometry of polygonal fault systems in Tertiary mudrocks of the North Sea, Journal of
      the Structural Geology , 1998. 20, no.5, 529-548.
Cole, D., Large crater-like structures in the Palaeogene sediments of Block 15/18, Outer Moray Firth, UK North Sea, 1998. Unpublished
      MSc thesis, Imperial College, London.
Gregerson, U., Michelson, O. and Sorenson, J.C., Stratigraphy and facies distribution of the Utsira Formation and the Pliocene sequences
      in the northern North Sea, Marine and Petroleum Geology , 1997. 14, no 7/8, 893-914.
Gregerson, U., Upper Cenozoic channels and fans on 3D seismic data in the northern Norwegian North Sea, Petroleum Geoscience, 1998.
      4, 67-80.
Anketell, J.M., Cegla, J. and Dzulynski, S., On the deformational structures in systems with reversed density gradients. Rocznik Polsk.
      Towarz. Geol., 1970. 40, 3-30.
Davies, R., Cartwright, J.A. and Rana, J., Giant (km) scale differential compaction/density inversion pillows in fine grained sediments,
      Geology, 2000., in press.
Vogt, P.R., Hummock fields in the Norway Basin and Eastern Iceland Plateau: Rayleigh – Taylor instabilities? Geology, 1997. 25,
      no.6, 531-534.

    E x am p les o f rem o b ilisatio n a ffects o n d eep w a te r re serv o irs

                       D E P O S IT IO N                                                A F T E R R E M O B IL IS AT IO N

                                           C H A N G E IN R E S E RV O IR G E O M E T R Y

                                                                                                                     M A S S IV E B L O C K Y
                                                                                                                        SA N D STO NE

                                            IN T R A -R E S E RV O IR S H A L E S
            C H A N N E L IS E D
     T U RBITIQ UE SA N D ST O N ES                                                 N O IN T E R N A L
                                                                                    C L AY B R E A K S

                                            C H A N G E IN R E S E RV O IR P R O P E RT IE S


                                                                                                             OWC        S IL L
         IS O L AT E D C H A N N E L S S A N D S

                                      C H A N G E IN C O N N E C T IV IT Y O F O R IG IN A L LY
                                                   IS O L AT E D R E S E RV O IR S

                                PRO DUCER                                                                YES NO

                          OWC                                                                                     OWC

                                              C H A N G E IN T O P R E S E RV O IR S U R FA C E
                                                A N D IN R E S E RV O IR V O L U M E T R IE S

    M o d el o f larg e scale rem o b ilisatio n featu res in th e E o cen e to M io cen e o f th e N o rth S ea

                                                                                                       SH EL F
                                                            P o ck m a rk s (C o le 1 9 9 8 )

                                                                                   SLO PE

                                                                                                                                  U tsir a m o u n ds   L arg e an d sm a ll
                                                                                                                                  a nd c o llap se      sc a le c lastic in tru sio n s
                                                                 C o n e sh ap e d                                                fe a tur es o v e r
                                                                                                      B A S IN                                          (N o rw ay 2 4/9 )
                                                                 in tru sio n s a lo n g                                          m ud m o u n d s
                                                                 p oly g o n al fau lts
                                                                 (U K B lo c ks 2 1 /4 + 5 )
                                                                                                G as m o und s                                                                             P oly g o n a l g ro w th
                                                                                                (B r o o k e et a l ., 1 99 5 )                                                            fa u lts
                                                                                                                                                                                           (B e lto n M e m b e r)

          S an d p ro n e                                                                                                                                                                                              S an d
                                                                                                                                                                                                                       v o lca n o
          S h ale p ro n e
                                                                                                                                                                                                                         T u rb id ite
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                                                                                                                                        h y d ro carb o n s                         p o ck m a rk                        p o n d ed san d s
          P re J u ra ss ic                                                                                                                                                                                              (Tim b rell, 1 9 9 3 )
          (N .B . S alt w ith in th e P erm ian m ay b e d iap iric
          ac tin g as a co n d u it fo r escap in g b asin al flu id s )
                                                                                                                                        F au lt
          P e rm ian salt                       C retace o u s C h alk

     Im p act o f p o ly g o n al fau ltin g o n reserv o ir g eo m e try ( C artw rig h t et. A l., 1 9 9 9 )

              D E PO S IT IO N A L :

                   L A K E S U P E R IO R                               2 4 /9
                                                                     B E LT O N                                    ALBA
                   ( W attru s e t. a l., 2 00 0 )

             P O ST-D E P O S IT IO N A L : T IE R S

                                                                                                          IN T R A T IE R B E D L E N G T H
                                                                                                                  S H O R T E N IN G

            P O ST-D E P O S IT IO N A L : -IN JE C T IO N

                                           2 4 /9
                                                                       FA U LT S N U C L E AT E                    T R IG G E R E D B Y
                             P R E -E X IS T IN G                        ON SANDBODY                                    FA U LT S
                                   FA U LT                                   M A R G IN S

 L o catio n o f 2 D an d 3 D se ism ic d a tasets u sed in th is N o rth S ea stu d y.
(p artly fro m P E S G B , 1 9 9 7 ; Jo n es 1 9 9 9 ; P erg ru m an d S p en cer, 1 9 9 0 )

                                                                                                                                       G ra b e n in g
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       O ute r M ora y                                                                                              , 29
           F irth
                                                   2 1/3 , 4 an d 5

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                                                                                                              o il m atu re (P erg ru m an d
                                                                                                              S p en c er, 19 9 0 )

“Off the Shelf” Seismic Data Processing
David Campden, Andy Dyke, Josef Heim & Elaine Jeong, WesternGeco, Calgary

Seismic reflection data offshore Eastern Canada are heavily contaminated with complex water-bottom multiples, caused by a hard and
irregularly shaped sea floor. In addition, some target reservoir intervals require imaging of steeply dipping structures in an environment
influenced by salt tectonics. This paper discusses the use of free surface multiple suppression techniques and Kirchhoff pre-stack time
migration methods and compares results with more conventional multiple suppression and imaging techniques.

Briefly, the structural styles offshore Nova Scotia have been controlled by the high sedimentation rates associated with the progradation of
the late Jurassic to early Cretaceous Sable Delta complex. This sedimentary loading propagated a series of large, down-to-basin, listric
faults, as well as initiating the movement of deeply buried Triassic salt. The latter accentuated the growth of syndepositional faults and the
formation of numerous localised sedimentary basins (CNSOPB, 1997).

Much of the current hydrocarbon exploration interest in this region is in the transition zone from shallow (~30 m) to deep (~3 km) water, or
off the continental shelf. Associated with this large change in water depth are deep channels in the sea floor, created by turbidite flows,
carrying sediments from the shallower regions down the continental slope to the deep ocean floor.

This combination of structurally complex geology and a highly irregular water bottom is not friendly towards standard "off-the-shelf"
processing methods. The main problems are complex water bottom multiples and seismic velocity fields that have a high degree of lateral
variability. While standard post-stack time migrations and Radon de-multiple techniques provide a first-pass solution, more sophisticated
techniques are required to unravel the structural complexity and better suppress the water-bottom multiples.

Free Surface Multiple Elimination
Numerous publications on the subject of surface related multiple elimination (SRME) exist (e.g. Verschuur, 1992). The method itself requires
no knowledge of velocities, or where the multiples are generated. It does, however, require very regular geometry, with a shot at every
receiver location and all offsets from zero to the maximum offset to be present. SRME will, in theory, model any multiples with a reflection
point at the free surface (i.e. it will not attack inter-bed multiples). Since the multiple model that SRME produces is based on a spatial
convolution of the data with itself, the source signature must be estimated and removed from the model before its subtraction from the input

In practice, a simple subtraction of the source-signature-deconvolved multiple model from the input data does not work! An adaptive
subtraction process must be used, consisting of residual matching filters to apply minor phase and time shifts to the multiple model prior to
subtraction (e.g. Nekut and Verschuur, 1998). These residual differences between the multiple model and input data result from errors in
estimating the source signature and from 3D effects. Offshore Eastern Canada, where the sea floor topography can be very complex, it is
the 3D effects that really cause the problems. Extension of the 2D version of SRME to 3D (van Dedem and Verschuur, 1998; van Dedem, 1999; Nekut, 1999) requires a significant increase in computational effort and is still in the experimental stage (i.e. large scale 3D
applications of the technique have yet to be published).

An inverse scattering formulation of free surface multiple elimination has been used for the results in this paper. This differs from SRME in
that it models the source as a monopole, rather than a vertical dipole in the water (Weglein, 1999). This more correct modelling of the
source can give better results for steeply dipping multiples compared with SRME.

                                                                 The data example presented here is a 2D line from offshore Nova Scotia. It
  Source spacing:                            25 m                was acquired parallel to the continental shelf, thus cutting across a number
  Receiver spacing:                          12.5 m              of channels created by turbidite flows. The acquisition parameters are
  Source to near trace distance:             196 m               given in Table 1.
  Number of receivers:                       576
  CMP spacing:                               6.25 m              Figure 1 shows a stack of the line, with a Radon de-multiple applied,
  CMP fold:                                  144                 specifically directed towards removing the water-bottom multiple. While
 Table 1: 2D line acquisition parameters                         this technique works well where the water bottom is regular, it is less
                                                                 successful below where the water bottom contains changes in dip.

Inverse Scattering Multiple Attenuation (ISMA) was applied to the line by first summing adjacent receivers, so the receiver and shot spacing
were the same. Next, the data were extrapolated to zero offset using a Hyperbolic Radon Transform applied in the CMP domain. The data
were then sorted back to shot domain for ISMA to be applied. After estimation and removal of the source signature, a residual matching
process was carried out. This is the most problematic and subjective part of the process. Allowing too much freedom to match the multiple
model with the input data results in primaries being removed. Too little freedom, and artefacts can be introduced by the multiple model.

Figure 2: shows the ISMA de-multipled stack (no additional multiple suppression has been used). This shows that in the areas below water-
bottom channels and where the water bottom is dipping, ISMA does a better job of suppressing the more complex multiples than the Radon


 Two-way time, s



Figure 1: Stack with Radon de-multiple. The multiples generated from the relatively flat water bottom have been suppressed. The circled
areas show residual multiples from below the water bottom with steeper dips.


 Two-way time, s



Figure 2: Stack with ISMA. Multiples from below the water bottom with steeper dips have been suppressed relative to the Radon
de-multiple stack.

Imaging methods
Generally speaking, post-stack time migration is not a good imaging method for East Coast Canada data. Figure 3 shows a post-stack time
migration from a portion of the line shown in Figures 1 and 2. This is supposed to show a salt upheaval below the Base Cretaceous.
However, steep dips are poorly, if at all, imaged and there are migration "smiles" between 4 and 5 seconds.

Pre-stack time migration (PreSTM) was performed on the line using two different methods. First, Common Offset Time Migration (COTiM)
was performed using all 144 offsets. This form of PreSTM has been widely used in the industry (i.e. MOVES from Veritas DGC, as well as
COTiM from WesternGeco). The final COTiM migration is shown in Figure 4 and shows a generally "cleaner" image compared with the post-
stack time migration, with less evidence of migration "smiles".

Kirchhoff migration was used for the second PreSTM method, the results of which are shown in Figure 5. Comparing Figures 4 and 5, it is
clear that the Kirchhoff migration has imaged the steep dips significantly better than COTiM. There are still some conflicting dips in the
image (on the left flank of the salt upheaval), but these are likely to be out-of-plane (3D) effects.

Kirchhoff migration uses a double square root (DSR), which is a description of the offset term, in the design of the migration operator.
Although the migration part of COTiM is zero offset (single square root), the combination of NMO, DMO and zero-offset migration is
attempting to mimic the DSR. In general, Kirchhoff is a more expensive method of PreSTM compared with the COTiM approach, but with
increasing computer power, more efficient algorithms and a better looking final image, it is becoming an increasingly attractive option.


 Two-way time, s



Figure 3: Post-stack time migration


 Two-way time, s



Figure 4: COTiM pre-stack time migration (144 offset slots)


 Two-way time, s



Figure 5: Kirchhoff pre-stack time migration

The authors wish to thank GSI for allowing the publication of this data and also to Pete Stewart and Björn Mueller from WesternGeco in
Houston for their technical support.

CNSOPB, 1997; Technical Summaries of Scotian Shelf Significant and Commercial Discoveries.
van Dedem, E., Verschuur, D. and Schonewille, M., 1999; 3-D surface-related multiple prediction and data reconstruction: Annual Meeting
     Abstracts, Society Of Exploration Geophysicists, 1068-1071.
van Dedem, E. J. and Verschuur, D. J., 1998; 3-D surface-related multiple elimination and interpolation: Annual Meeting Abstracts, Society
     Of Exploration Geophysicists, 1321-1324.
Nekut, A. G. and Verschuur, D. J., 1998; Minimum energy adaptive subtraction in surface-related multiple attenuation: Annual Meeting
     Abstracts, Society Of Exploration Geophysicists, 1507-1510.
Nekut, A. G., 1998; 3D surface-related multiple prediction, Annual Meeting Abstracts, Society Of Exploration Geophysicists, 1511-1514.
Verschuur, D. J. and Berkhout, A. J., 1992; Surface-related multiple eliminations: Practical aspects: Annual Meeting Abstracts, Society Of
     Exploration Geophysicists, 1100-1103.
Weglein, A.B., 1999; Multiple attenuation: an overview of recent advances and the road ahead, The Leading Edge, 18, 40-44.

A Seismic Analysis of a late Albian age Submarine fan, Glenwood
Prospect, Jeanne d'Arc Basin, Canada.
Torbjorn Fristad*, Andrew Barnwell*, *Norsk Hydro, and Edward Stacey,
Petro-Canada Oil and Gas.

Summary                                                                Reservoir
Prior to this work, amplitude anomalies (bright spots) inferred to     In order to predict the likely reservoir parameters, potential
be late Albian age submarine fan deposits were mapped on 2D            analogue submarine fans from the North Sea were reviewed.
seismic data in the northern Jeanne d'Arc Basin. One of these          The Glenwood fan is small (3-8kms) in length, and its seismic
prospects was acquired in 1999 by a group operated by Norsk            expression indicates a single package consisting of low-angle
Hydro (33.34%), and partners Petro-Canada (33.33%) and Mobil           reflectors with rare clinoforms and poor internal character. The
(33.33%) (fig.1). The prospect is a deep marine fan, which is          morphology is lobate, which may be channelised. These
likely to be sand-prone, with good-excellent reservoir potential.      characteristics indicate a sand-rich fan (Reading & Richards,
Now covered with 3D seismic the Glenwood anomaly has been              1994). Such fans have high N/G (> 0.7), but are usually fairly
reinterpreted and mapped. Other methods, including AVO, AVO            thin (<100m). These types of fans may be deposited during
attributes, amplitude and structure maps and wavelet                   highstands, due to shoreface reworking. The amplitude
classification were utilised in order to enhance our                   anomalies also suggest a sand model. If so, then Glenwood
understanding of this anomaly. This talk will outline our              appears to be a close analogue to the Miller Field of the UK
approach into the characterisation of the anomaly.                     sector; data from Miller and other sources were used as
                                                                       reservoir input parameters for volumetric calculations.
The Glenwood prospect is positioned on license EL 1047 and is          Geophysical Interpretation
positioned north of White Rose and is situated just off the Outer      Initially the 1998 seismic amplitude anomaly was mapped on 2D
Ridge in the northern Jeanne d'Arc Basin. (Fig. 1).          The       data. New 3D seismic data confirmed the presence of this
Glenwood prospect has a potential STOOIP of 328 mmbbls of oil          amplitude anomaly and enhanced our understanding of the
or 3.1 TCF of gas. The seismic anomaly is interpreted to be a          geology, as a feeder system was evident up-dip of the previously
mid-Upper Cretaceous aged, submarine fan deposit. The trap is          interpreted crestal area.
entirely stratigraphic. The top seal will be a deep-marine shale
and with an up dip seal within the main feeder channel. The            The seismic anomaly was mapped at a centre of a trough
source rocks are deeply buried and will be gas prone or over           (negative amplitude). The amplitude anomaly should correspond
mature under the license, but oil in nearby wells suggest the          to an acoustic impedance drop, increasing the likelihood for
possibility of an oil case.                                            having a porous rather than a calcite cemented sand.

                                                                       The prospect is defined by a strong seismic amplitude anomaly,
                                                                       which maps out as a set of fan lobes, which occur at slightly
                                                                       different stratigraphic levels, with a maximum length of about
                                                                       8kms. The top of the prospect, at the up dip seal location, lies at
                                                                       3710m depth. It has a maximum thickness of about 70m and a
                                                                       combined area of about 130 km


  Figure 1: Location map of the Glenwood prospect.

The first objective of this study was to review the regional
petroleum geology of the Glenwood license using an integrated
geological and geophysical approach. There are no wells drilled
on the license, but several exist in the vicinity. These wells, plus
all available internal and published data, were used in                Figure 2: Outline of Glenwood fans.
conjunction with the seismic database to formulate the
evaluation. Most well data were obtained from the GSC 'Basins'
database, available via the Internet.

The prospect is within a stratigraphic sequence not previously      Later modeling performed by Veritas suggest that a high porosity
penetrated by wells, but seismic correlation strongly suggests      sandstone (>12%) and hydrocarbon filled interval could explain
the main reservoir lies between the top of the Ben Nevis Fm and     the low rigidity/incompressibility and also the low amplitudes
the overlying Cenomanian unconformity, which means it is latest     observed on the seismic.
Albian to Early Cenomanian in age.

The geological age of the seismic anomaly was detained using
regional seismic control. Tie lines from both North Ben Nevis
and White Rose clearly indicate that the Glenwood prospect is                                                                    Tight Sands                       Carbonates

located between the Ben Nevis Fm and the Cenomanian

                                                                         Mu-Rho (rigidity)
Unconformity. This suggests a Late Albian age for the submarine                                                                     lowoil)              ine
                                                                                                                                      (               (br
fan and confinement within the Nautilus Fm                                                                               of nd
                                                                                                                   top d sa
                                                                                             Gas Sands               fille         Sands
                                                                                                                 oil                                       of nd
                                                                                                                                                  ba d sa
Stratigraphically, the fan may be equivalent to the Eider                                                                                        oil

Formation as seen in the Whale Basin, which is the first                                                  oo
                                                                                                        nw ly
                                                                                                     Gle oma
transgressive sand on the Aptian unconformity (McAlpine, 1990),                               Coal     an                          Shale

Inversion                                                                                                   Lambda-Rho (incompressibility)

A seismic inversion was done by CGG. The purpose of the
seismic inversion was to substantiate the thickness modelling       Figure 4: Lambda-Rho Vs Mu-Rho crossplots showing litholog.
and to confirm an acoustic impedance drop for the Glenwood
anomaly. An acoustic impedance drop was confirmed by the            From the above observations, there is a positive case for
inversion. The thickness of the low acoustic impedance interval     assuming a hydrocarbon filled reservoir in the Glenwood
was determined by measuring the time and depth converted            prospect. However, the AVO attributes are closely associated
using a velocity of 3600 m/s. An isochore map was then              with the outline of the amplitude anomaly and no DHI's are
contoured using the measured thickness and the amplitude map        obvious on the seismic data. Leading us to two conclusions,
                                                                    first that the AVO is being influenced more by the porosity that
AVO Modelling and Analysis                                          the presence of Hydrocarbon or the reservoir is completely filled.
The main objective of the AVO analysis was to determine the
AVO response from a potential reservoir at Glenwood. Both the       Depth Conversion
modelling and AVO analysis where done by Veritas. Models            The methodology that was chosen for depth conversion was the
where prepared to determine the theoretical response of a wet,      application of a linear velocity model down to Base Tertiary and
oil and a gas filled reservoir. Based on the modelling results it   then a second velocity function from Base Tertiary to the
should be possible to distinguish between a water and               character anomaly.
hydrocarbon filled reservoir, but to distinguish between gas and
oil an absolute calibration point is needed.                        The second velocity model down to the Glenwood anomaly
                                                                    proved to be difficult. Stacking velocities and linear velocity
                                                                    function both gave unrealistic velocities for the interval. A
                                                                    velocity function based on the Base Tertiary to A Marker (or
                                                                    equivalent) interval for all wells in the Jeanne d'Arc Basin was
                                                                    therefore chosen. The resulting interval velocity map shows a
                                                                    slight increase in velocity versus time to the anomaly.
                          40 API Oil
                                                                    We wish to thank WesternGeco, CGG Canada Services Ltd,
                            Gas                                     Veritas Exploration Services, Norsk Hydro and Petro-Canada Oil
                                                                    and Gas for their permission to present this talk.

                                                                    Fristad, T., Groth, A., Yielding, G., Freeman, B., 1997,
Figure 3: Models showing differences in expected response.                Quantitative Fault Seal Prediction: A Case Study from
                                                                          Oseberg Syd, Norwegian Petroleum Society (NPF), Special
                                                                          Publication No.7
                                                                    McAlpine, K.D., 1990, Mesozoic Stratigraphy, Sedimentary
The AVO analysis consisted of two steps. First AVO attributes
                                                                          Evolution, and Petroleum Potential of the Jeanne D'Arc
were determined. Secondly, inversion of two AVO attributes, the
                                                                          Basin, Grand Banks of Newfoundland. Geol. Survey Canada
expected P-Wave and S-wave reflectivity were extracted. The
                                                                          - Paper 89-17.
results of the inversions were used to calculate rock properties.   Poupon, M. & Palmer, G., 1999, Finding Channel Sands with
Rock property (λρ incompressibility and µρ rigidity) and cross-           Seismic Facies Analysis and Litho-seismic Modelling,
plots were used to assess fluid content and lithology.                    Offshore Magazine March 1999
                                                                    Reading, H.G. & Richards, M.R., 1994, Turbidite Systems in
Cross-plots suggest low rigidity and incompressibility, which             Deep-Water Basin Margins Classified by Grain Size and
normally would be associated with shale or coal/tuff This is not          Feeder System, Bull. AAPG, v 78, no 5, pp792-822
compatible with the morphology of the low impedance anomaly.

Estimating TIV Anisotropy Parameters in the Jeanne d’Arc Basin
at White Rose H-20 Well
Emery, David J., Brown, R. Jim, and Enachescu, Michael E.

In the summer of 1999 three delineation wells (L-08, A-17 and N-30) were drilled in the White Rose field of the Jeanne d’Arc Basin.
Interpretation of the VSP and log information indicates that the seismic velocities increase reasonably linearly with depth within the Tertiary
section followed by an abrupt velocity increase in the penetrated Cretaceous. Evaluation of anisotropy parameters using check shots and
stacking velocities indicates a ~6% difference between v(0°) and v(90°) (Hedlin, 1999).

During the summer of 2000, a single delineation well, H-20, was drilled into the northern part of the White Rose South Avalon Pool (figure 1).
The H-20 well was targeted to penetrate the hydrocarbon bearing Avalon Formation through a small intra-reservoir fault with a throw of
approximately 25 m. Due to the deviated nature of the H-20 well the VSP program was designed with a walkabove configuration. Rig time
and equipment availability provided the opportunity to also acquire a single offset over a limited depth range.

This paper deals with the evaluation of this limited VSP information for anisotropy parameters. The H-20 direct-arrival for the offset VSP
indicates that the Tertiary age Banquereau Formation of Tertiary age is weakly anisotropic (δ = 0.03 ε = 0.07). Evaluation of the interval
velocities derived from VSP shows a direct relationship between shale compaction and degree of anisotropy. The VSP interval velocity
information also indicates that the Santonian age Dawson Canyon shales are highly anisotropic (δ = 0.40 ε = 0.80).

Figure 1: White Rose H-20 Offset VSP located on a N-S 3-D seismic line

                                       VSP Source approx. 1000 m north of well                               VSP Receivers 2080-2500 m MD
                                                                                                      H-20          E-09            L-08

                                                            Ocean Bottom
                  Velocity increase from 1850 to 2300 m/s
 Banquereau Fm.

                                                               Eocene Unc.
                                                                 Base Tertiary Unc.
                                                                    Dawson Canyon Fm.
                                                                           Avalon Reserv

                                                                                                                                            500 m

The evaluation of the White Rose H-20 VSP for rock anisotropy was performed using Thomsen’s (1986) equations for weak elastic
anisotropy. The velocity of P-waves in such media is defined as:

                                                             v(θ) = v0 (1 + δ sin θcos θ + ε sin θ)
                                                                                2     2         4

where v(θ), the P-wave velocity for a phase angle θ, is determined by the vertical velocity (v0) and the two anisotropy parameters δ and
ε (Thomsen, 1986, equation 16a).

A short-spread assumption is appropriate for both surface reflection seismic, where the effective offset is less than the depth of
investigation, and for VSP data, where the offset is less than half the depth of investigation. Using Thomsen’s (1986) equation for a short-
spread the δ parameter can be estimated using the NMO velocity:
          δ = ½[(vNMO/v0) –1]                                               (2)

To estimate a range for ε, a least-squares solution was determined for a varying set of ε and δ values. The least-squares solution attempts
to minimize the traveltime and NMO velocity differences using the straight-ray angle for the average phase angle and the isotropic ray
length for raypath distance.

Assuming that the majority of the anisotropy effects on the direct arrivals occur in the 2050 m interval above the shallowest geophone
location in the offset VSP, the least-squares solution should represent the average anisotropy parameters for the Banquereau Formation.

Two different assumptions were used to estimate the range of interval anisotropic parameters for the 420 m span in the offset VSP. The first
approximation was for elliptical anisotropy (δ = ε) discussed by Daley & Hron (1977), because of its algebraic simplicity. Substituting ω for
δ and ε in Thomsen’s equation results in:

          ω = [(v(θ) / v0) – 1] / sin θ

The second estimation was for intrinsic anisotropy where ε > δ as proposed by Berryman (1979) and Thomsen (1986). Using a ratio of 2δ =
ε, Thomsen equation can be modified by letting τ = δ = ε /2 resulting in:

          τ = ((v(θ) / v0) – 1) / (sin θ + sin θ)
                                     2       4

The White Rose H-20 VSP values for δ, vary from 0.029 to 0.048, with the Tertiary section (above 2230 m) having the lowest values (table
1). The stacking velocities from the 3-D surface seismic compares with the observed moveout velocity from the VSP. The corresponding log
derived formation velocities are overestimated by 4-6%.

Since vNMO is derived from the lithology above each sample point, and since there is no significant change in δ until a depth of 2230 is
reached, it would be reasonable to assume that the Tertiary is only slightly anisotropic. The deviation in δ below 2230 m would indicate a
sharp change in properties below this point and a significant increase in anisotropic parameters.

The best fit for a least-squares error between the calculated and observed moveout velocities occurs at ε = -0.46 with a δ = +0.21. This
solution falls far outside the expected anisotropy parameter range for the White Rose area. The solution for elliptical anisotropy (ω = δ = ε =
0.04) is closer to the expected range and is situated at a local minimum. Around this solution is a group of solutions from δ = 0.02 ε = 0.10
to δ = 0.04 ε = 0.03 with approximately the same degree of error. The answer of δ ≅ .03 ε ≅ .07 falls at the center point of this cluster of
solutions and represent the average anisotropy parameters in the Banquereau Formation.

  Table 1: H-20 VSP summary

                              Average Average Average Minimum Maximum                                                   Group
                   Interval   Velocity v (NMO) v (NMO)^   δ      δ                                                      Angle
  Tertiary Shale 2050 to 2220  2168      2179     2236  0.028  0.036                                                    25.11
         Shale 1 2050 to 2120  2158      2171     2228  0.029  0.036                                                    25.57
         Shale 2 2130 to 2220  2176      2187     2242  0.028  0.034                                                    24.69
  Eocene Peak    2230 to 2250  2188      2200     2259  0.029  0.036                                                    23.54
  Paleocene      2260 to 2370  2208      2219     2282  0.032  0.038                                                    23.32
  Dawson Canyon 2400 to 2460   2243      2257     2341  0.042  0.048                                                    22.33
  ^ NMO velocity estimated using raypath length from isotropic GXII model

                               Interval         Offset         Phase        Elliptical       Intrinsic 2δ = ε          Estimate
                               Velocity         Velocity       Angle           ε=δ            δ           ε             Error*
  Tertiary Shale                2694             2800          31.18         0.147          0.116       0.232            0.06
         Shale 1                2632             2684          31.60         0.072          0.056       0.113            0.14
         Shale 2                2745             2845          30.80         0.139          0.110       0.220            0.12
  Eocene Peak                   2846             3686          29.13         1.246          1.007       2.015            0.69
  Paleocene                     2994             3163          29.32         0.235          0.190       0.380            0.11
  Dawson Canyon                 3726             4485          37.00         0.562          0.413       0.826            0.24
  D Canyon (GXII)               3726             6376          37.28         1.938          1.418       2.836            0.24
  * Estimated Error represents a 1ms time shift and the effects on the calculated Elliptical parameters

Evaluating the interval velocity behavior provides insights into the discrete anisotropy parameter of individual geological layers. The velocity
in the Tertiary sequences is relatively linear with crossover in the velocity display (figure 2). This may indicate that the Tertiary is
predominately isotropic with the net anisotropic effect occurring because of the intrinsic layering. Assuming elliptical anisotropy the Tertiary
would have a ω = 0.15 which is higher than the δ determined from vNMO values. Using the anisotropy relationship 2δ = ε the results for the
Tertiary would be ε = 0.23 with a δ of 0.11 or higher than the values determined from the average velocities.

The high velocity anomaly from 2230 to 2260 m feature a sharp increase in anisotropy parameters to ω = 1.2 or ε = 2.0 and δ = 1.0. The
anisotropy parameters are unexpectcally high. The sonic and density logs indicate only a small incremental change in rock properties where
the surface seismic indicates a relatively strong impedance response. While, geologically this interval corresponds with the Eocene
unconformity, the high velocity obtained for the interval is most likely the effect of time sampling errors (figure 2).

The Paleocene shales (2260 to 2370) are just slightly deformed and have undergone significant compaction with a v(0) = 2994 m/s and ω
= 0.23 or ε = 0.38 and δ = 0.19. The Paleocene shale interval has a consistent velocity shift and an constant set of anisotropy parameters.
This interval appears to be moderately anisotropy.

At 2380 m there is a pronounced shift in the interval velocities and calculated anisotropy parameters. This shift correlates with the Base
Tertiary unconformity and marks the change from parallel layering to moderately faulted and folded geometry. The underlying Dawson
Canyon Formation is made up of compacted Cretaceous shale and limestones with dips varying from 3° to 10°. The GXII raypath-model
solution indicates a substantial offset velocity (7450 m/s) and an unrealistic anisotropy effect ω = 1.9. While the ray-traced data may need
checking, the straight-ray approximation still demonstrates a significant anisotropy effect ω = 0.56 or ε = 0.83 and δ = 0.41. While the
investigated Dawson Canyon interval is limited on the offset VSP, it would be reasonable to conclude that these Senonian shales are strongly
anisotropic (ε > 0.4).

                                                        Velocity (m/ms)
                      2000.0                   3000.0                     4000.0                       5000.0
                                                                     Velocity Walkabove (Check Shot)

                                                                     Velocity 1000m Offset (Straight Ray)

                                                                     Velocity 1000m Offset (model)

                                                              Tertiary Shale
                                                              v0 = 2700m/s
                                                              group angle =25º
                                                              phase angle = 31º
                                                              ω = δ = ε = 0.15 or
                                                              ε = 0.23, δ = 0.12
Depth (meter SS)

                                                                          Eocene Unconformity

                                                                          Paleocene Shale
                   2300                                                   v0 = 3100 m/s
                                                                          group angle =23º
                                                                          phase angle = 29º
                                                                          ω = δ = ε = 0.23
                                                                          ε = 0.38, δ = 0.19

                                                                    Base Tertiary Unc
                               Dawson Canyon Shale
                               v0 = 3900 m/s
                               group angle = 22º
                               phase angle = 37º
                               ω = δ = ε = 0.56
                               ε = 0.83, δ = 0.41


                          Figure 2: White Rose H-20 Interval Velocity Profile - The blue line represents
                          the velocities for the zero offset VSP, the red line for the 1000-m offset VSP
                          using a straight line geometry and yellow using the raypath length from the
                          GXII model.

Previous work done by Hedlin (1999) indicated that the Banquereau Formation Tertiary shales are slightly anisotropic with an approximate
6% difference between v(0°) and v(90°). The offset VSP average velocities agree with this observation and gives a range of anisotropy
parameters from δ = 0.02 and ε = 0.10 to δ = 0.04 and ε = 0.03.

Since the White Rose VSP represents a short spread geometry, the dominant Thomsen (1986) parameter should be δ because of its control
on wavefront shape from 0° to 30º. This is reflected in the limited anisotropy parameter range estimated from the VSP (δ = 0.029 to 0.048).
The least square solution of ε = 0.07 with a δ = 0.03 would be consistent with the both surface 3-D seismic and VSP data.

The interval velocities indicate that the shales in the White Rose area have varying degrees of anisotropy parameters. The accuracy of
measuring the anisotropy parameters of these shales at White Rose, is unfortunately limited, since only a single offset was used. The
interval anisotropy parameters indicate that the lower portion of Banquereau Formation is weakly anisotropic (ω = 0.15 or ε = 0.23 with δ =
0.11), the Paleocene shales are moderately anisotropic (ω = 0.23 or ε = 0.40 and δ = 0.19) and the Dawson Canyon Formation is strongly
anisotropic (ε > 0.4).

Special thanks to Larry Mewhort and Ken Hedlin for their technical evaluation and application assistance, Larry Mayo for design and
acquisition of the VSP.

Berryman, J.G., 1979, Long-wave elastic anisotropy in transversely isotropic media: Geophysics, 44, 896-917.
Brown, R.J., Lamoureux, M.P., Slawinski, M.A. and Slawinski, R.A., 2000, Direct traveltime inversion of VSP data for elliptical anisotropy in
     layered media: CREWES Research Report, 12, 19-34.
Daley, P.F. and Hron, F., 1977, Reflection and transmission coefficients for transversely isotropic media: Bull. Seis. Soc. Am.
     Vol 67, 661-675.
Enachescu, M.E., 1987, Tectonic and structural framework of the northeast Newfoundland continental margin in Beaumont, C. and Tankard,
     A. J., Eds., Sedimentary basins and basin-forming mechanisms: Can. Soc. Petr. Geol., Mem. 12, 117-146.
Enachescu, M.E., 1988, Extended basement beneath the intracratonic rifted basins of the Grand Banks of Newfoundland: Can. J. Expl.
     Geophys., 24, No. 1, 48-65.
Grant, A.C. and McAlpine, K.D., 1990, The continental margin around Newfoundland in Keen, M.j. and Williams, G.L., Eds.,
     Geology of the Continental Margin of East Canada: Geol. Surv. Can., Geology of Canada, No. 2, 239-292.
Hedlin, K., 1999, White Rose time-depth analysis: Husky Oil Operation Ltd, internal report.
Thomsen, L., 1986, Weak elastic anisotropy: Geophysics, 51,1954-1966.
Schlumberger, 2000, White Rose H-20 VSP report: Husky Energy, internal report.

Imaging Through Gas Clouds:
A Case History In The Gulf Of Mexico
S. Knapp1, N. Payne1, and T. Johns2,
Seitel Data1, Houston, Texas: WesternGeco2, Houston, Texas

Results from the worlds largest 3D four component OBC seismic survey will be presented. Located in the West Cameron area, offshore Gulf
of Mexico, the survey operation totaled over 1000 square kilometers and covered more than 46 OCS blocks. The area contains numerous
gas invaded zones and shallow gas anomalies that disturb the image on conventional 3D seismic, which only records compressional data.
Converted shear wave data allows images to be obtained that are unobstructed by the gas and/or fluids. This reduces the risk for
interpretation and subsequent appraisal and development drilling in complex areas which are clearly petroleum rich. In addition, rock
properties can be uniquely determined from the compressional and shear data, allowing for improved reservoir characterization and
lithologic prediction.

Data acquisition and processing of multicomponent 3D datasets involves both similarities and differences when compared to conventional
techniques. Processing for the compressional data is the same as for a conventional OBC survey, however, asymmetric raypaths for the
converted waves and the resultant effects on fold-offset-azimuth distribution, binning and velocity determination require radically different
processing methodologies. These issues together with methods for determining the optimal parameters of the Vp/Vs ratio (γ) will be
discussed. Finally, images from both the compressional (P and Z components summed) and converted shear waves will be shown to
illuminate details that were not present on previous 3D datasets.

Multicomponent 3D surveys have become one of the leading areas where state of the art technology is being applied to areas where the
exploitation potential has not been fulfilled due to difficulties in obtaining an interpretable seismic image (MacLeod et al 1999, Rognoe et al
1999). In areas where conventional datasets suffer from poor data quality due to the presence of gas and/or fluids in the pore spaces, it has
been shown that ocean-bottom acquired multicomponent surveys have improved images (Thomsen, et al 1997, Granli et al 1999). For
marine surveys where the energy source is towed just below the sea surface, the initial downgoing wave is always compressional and mode
conversion to shear waves takes place at reflector boundaries (Thomsen 1999). For clarification, this paper will describe compression as P-P
waves and converted shear as P-S waves, indicating one mode conversion. The primary difference between the two is that the shear waves
are unaffected by the presence of gas or fluids and only detect lithologic variations. The resultant converted shear seismic image, therefore,
contains interpretable reflectors that were not present on the compressional data.

Over a six-month period from December 1999 until May 2000 a large multicomponent seismic survey was acquired in the West Cameron
area, Gulf of Mexico. This was the first commercial application of a new ocean bottom cable and sensor package designed specifically for
multicomponent applications. Cables were deployed under tension and the no-slack design with 50-meter group intervals helped improve
the correspondence between preplotted and actual location. Receiver positioning was confirmed using both a high frequency acoustic
method and a first break based technique.

The survey was acquired using swath style acquisition comprised of 102 swaths in 9 overlapping zones for a total of 18,700 CMP
kilometers and 930 square kilometers of full fold coverage. The area included numerous platforms and subsurface obstructions requiring
extensive planning, especially to ensure sufficient fold of coverage for both the compression and shear data. Commercial ship traffic caused
both noise problems and an operational hazard for vessel maneuvers.

Both field processing and conventional shore-based processing were utilized in this survey. In order to ascertain data quality and permit
preliminary evaluation of the imaging results, displays ranging from shot records to 3D inlines, crosslines and timeslices were created
onboard using optimized processing parameters that were determined from a 2D test line that was acquired and processed previously. The
shot records with the navigation merged were then brought onshore and proceeded through a complete isotropic processing sequence at
Schlumberger’s Houston office. This included creation of both a P-P wave data volume by combining the hydrophone and geophone using a
non-linear summation technique (Moldoveanu, 1996) and a radial and transverse volume from the P-S data recorded on the two horizonal
geophones. Deliverables include pre stack migrated gathers and migrated volumes for both P-P and P-S wave modes.

The large size of the survey resulted in several modifications to the basic P-S converted wave processing sequence (Brzostowski et al 1999,
McHugo et al 1999). Resolution of the receiver statics and determination of the appropriate binning Vp/Vs ratio (γVTI) as discussed in
Thomsen, 1999 proved to be challenging given the volume of data. We were frequently evaluating the length of the error bar, then iterating
to achieve a result which would accomplish our primary objective: imaging through the gas areas. A demonstration of the spectacular

results can be seen in comparisons between the compressive and radial shear data volumes. Figure 1 is an inline from a portion of the
survey where the P-P image, shown on the left, is distorted by the presence of a large gas cloud. The equivalent section from the P-S
volume shows the dramatic increase in reflection events, and hence the interpretability of the data. Figure 2 is a crossline that transects the
same gas cloud and shows a similar high quality image that can now be used to reduce the risk for further exploration. There are multiple
areas throughout the survey where this level of improvement can be demonstrated by comparing timeslices through the two data volumes
(Figure 3). Post stack versus pre stack migrated results for both P-P and P-S waves will be compared to identify improvements in data
quality with the added benefit of providing gathers suitable for AVO analysis.

Future Work
As can be seen by these examples the results are very encouraging, however, further analysis is necessary to fully realize the added value of
this dataset. Special processing to determine the effect of azimuthal anisotropy and depth domain imaging would be of interest. A definitive
evaluation of the obvious benefits versus potential inadequacies from limited azimuth acquisition needs to be addressed.

Brzostowski, M., Altan, S., Zhu, X., Barkved, O., Rosland, B. and Thomsen, L., 1999, 3-D converted-wave processing over the Valhall Field:
     Annual Meeting Abstracts, Society Of Exploration Geophysicists, 695-698.
Granli, J. R., Arntsen, B., Sollid, A. and Hilde, E., 1999, Imaging through gas-filled sediments using marine shear-wave data: Geophysics,
     64, no. 3, 668-677.
MacLeod, M.K., Hanson, R.A., Bell, C.R., and McHugo, S., 1999, “The Alba Field ocean bottom cable seismic survey: Impact on
     development,” SPE Paper 56977, Offshore Europe Conference, Aberdeen.
McHugo, S., Probert, A., Hodge, M., Kristiansen, P., Painter, D. and Hadley, M. E. A., 1999, Acquisition and Processing of a 3D
     Multicomponent Seabed Data from Alba Field - a Case Study from the North Sea : 61st Mtg. Eur. Assoc. Expl Geophys., Extended
     Abstracts, European Association Of Geophysical Exploration, Session:6026.
Moldoveanu, N., 1996, US Patent and Trademark Office, “Method for attenuation of reverberations using a pressure-velocity bottom cable,”
     Patent No. 5621700.
Rognoe, H., Amundsen, L. and Kristensen, A., 1999, Improved structural and stratigraphic definition from 3-D/4-C data - Statfjord Field:
     Annual Meeting Abstracts, Society Of Exploration Geophysicists, 736-739.
Thomsen, L. A., Barkved, O., Haggard, B., Kommedal, J. and Rosland, B., 1997, Converted-wave imaging of Valhall reservoir: 61st Mtg. Eur.
     Assoc. Expl Geophys., Extended Abstracts, European Association Of Geophysical Exploration, Session:B048.B048.
Thomsen, L., 1999, Converted-wave reflection seismology over inhomogeneous, anisotropic media: Geophysics, 64, no. 3, 678-690.

P-P Section                                           P-S Section (Radial)

                   Figure 1: Inline migration comparison

     P-P Section                                 P-S Section (Radial)

               Figure 2: Crossline migration comparison

     Figure 3: Timeslice comparison

Neural Network Applications to Porosity Prediction; Hebron Field Offshore
Newfoundland, Canada
Stan M Volk - ExxonMobil Development Company, John D. Logel - Petro-Canada Oil and Gas,
Craig Coulombe - Chevron Resources Canada

The Hebron Field is located approx. 350 kilometers SSE of St. John's Newfoundland. The filed has three pay zones and an estimated 2 billion
barrels in-place. The advent of seismic attributes has allowed more information to be extracted from the seismic data. A method of
determining which information to use is highly valuable. Neural networks can be employed to isolate the attributes, which in combination
can best predict desired log responses. Neural networks were employed in an attempted to predict the porosity prediction in these three pay

Porosity was predicted from five porosity curves in the field using linear regression and neural networks. Attributes were calculated from
seismic data, impedance, coherency, and velocity cubes. Numerous iterations were made using predictive and multi-layered feed forward
networks. A best fit solution was generated for each pay zone.

A neural network application enhanced the porosity distribution prediction and increased the correlation by an average of 30 percent for all
three pay zones. Comparisons to seismic inversions also showed a marked improvement using neural networks.

Depth Conversion methodologies, uncertainty, quantification and
application; Hebron Field, Offshore Newfoundland Canada
John D. Logel - Petro-Canada Oil and Gas
Craig Coulombe - Chevron Resources Canada
Stan Volk - ExxonMobil Canada

The Hebron field is located 350 kilometers SSE of St. Johns, Newfoundland. The field has three pay zones and estimated 2 Billion Barrels
in-place. The field has very subtle relief and some of the accumulations are very sensitive to velocity determination and depth conversion.
The field was depth converted using two different methods to better quantify uncertainty, and because neither method could be proved to be
superior to the other.

Seismic time to depth conversion is a process to convert from recorded seismic travel times to depth. This process is carried out to
determine drilling depth, reservoir understand and structural validity. The process is to build a detailed velocity model that is robust enough
to allow for lateral and vertical variations, that ties the wells and does not induce anomalies or artifacts. The process can be done a number
of different ways from very simply extrapolating time/depth tables from wells to pre-stack coherency inversion and tomography. The basic
data can include strictly well data or a combination of well and seismic processing velocities. The difference being in the time and cost

The methods used for the Hebron field mapping was to use a layercake based method that employed both a tied and smoothed stacking
velocity based model and a well based method that would account for the instantaneous change of velocity as a function of depth. This
change is expressed as an acceleration value (k) and surface intercept of (V0).

Quantifying errors
The use of two equal and “valid” velocity models continued to be a source of uncertainty and question. The differences were small, as
shown in the difference map in Figure 1. But in some accumulations, accounted for over 100 million barrels. To try and resolve the problem
and converge on a single model, other source of data were incorporated. These included average and interval velocity mapping, cross-
validation with well control, fault seal and juxtaposition analysis, hydrocarbon contact correlation and pre-stack depth tomography.

These methods were integrated together in an overall velocity model building and used independently and in combination to try and
encompass a wider range of gross-rock-volume (GRV) uncertainty.

                                                                      Zero contour

Figure 1. Difference map between Stacking velocity based model and Instananeous   Velocity Model


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