3d seismic technology application to the exploration

3D Seismic Technology: Application to the Exploration of Sedimentary Basins

Geological Society Memoirs

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DAVIES, R. J., CARTWRIGHT, J. A., STEWART, S. A., LAPPIN, M. & UNDERHILL, J. R. (eds) 2004.3D Seismic Technology:

Application to the Exploration of Sedimentary Basins. Geological Society, London, Memoirs, 29.

JONES, G., WILLIAMS, L. S. & KNIPE, R. J. 2004. Structural evolution of a complex 3D fault array in the Cretaceous and Tertiary of

the Porcupine Basin, offshore Ireland. In: DAVIES, R. J., CARTWRIGHT, J. A., STEWART, S. A., LAPPIN, M. & UNDERHILL, J. R.

(eds) 2004. 3D Seismic Technology: Application to the Exploration of Sedimentary Basins. Geological Society, London, Memoirs, 29, 117-132.

GEOLOGICAL SOCIETY MEMOIR NO. 29

3D Seismic Technology: Application to the Exploration of

Sedimentary Basins

EDITED BY

RICHARD J. DAVIES

Cardiff University, UK

JOSEPH A. CARTWRIGHT

Cardiff University, UK

SIMON A. STEWART

BP, Azerbaijan

MARK LAPPIN

ExxonMobil Exploration Company, USA

and

JOHN R. UNDERHILL

The University of Edinburgh, UK

2004

Published by

The Geological Society

London

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Preface

This Geological Society Memoir is the result of a highly

successful conference held in November 2001 at The

Geological Society, London. The 32 papers in this Memoir

attempt to capture how the rapid development of 3D seismic

technology has had a fundamental role in the exploration,

development and production of hydrocarbons and uses

movies as well as conventional figures and text to do

so. The Memoir also shows that 3D seismic data are a

tremendous - - but mainly underutilized - - tool for Earth

scientists involved in the exploration of sedimentary basins

in the context of a diverse range of disciplines whether

they be sedimentary, structural or even 'hard rock' .

Given the breadth and depth of the contributions we hope

that this book will become a well-thumbed reference for

those working with 3D seismic technology in industry

and academia, but perhaps more importantly will act

as an introduction for those that are now discovering its

utility.

Acknowledgements

First and foremost we would to thank all the contributors to the

meeting who made it such a success and then detailed their

results in this book. Michele O'Callahan is thanked for helping

to convene the meeting and Helen Wilson for organizing the

event. ExxonMobil, Landmark, PGS Exploration Ltd, Schlum-

berger, Troy Ikoda, and Veritas DGC Ltd. generously

sponsored the conference.

This Memoir would not have been possible without the

expertise of the following individuals who reviewed one or

more papers. Rolf Ackerman, John Allison, John Ardill, Bryn

Austin, Brian Bell, John Bingham, Stuart Bland, Ian Cloke, Pat

Connelly, Rupert Dalwood, Chris Dart, Bret Dixon, Richard

Dixon, Tony Dor6, Chris Elders, Duncan Erratt, Jean

Christophe Faug~res, A1 Fraser, Scot Fraser, Joe Gallagher,

Kerry Gallagher, Tim Garfield, Rutger Gras, Matt Grove, Jens

Peter Vind Hansen, Dan Helgeson, Peter Homonko, Howard

Johnson, Hugh Kerr, Paul Knutz, Nick Kusznir, Charles Line,

Lidia Lonergan, Dave Long, Richard Lovell, Steve Mathews,

James Maynard, Ken McClay, Alan McInally, Steve Mitchell,

Damian O'Grady, Mike Payne, Sverre Planke, Henry

Posamentier, Pat Shannon, John Smallwood, Roland Smith,

Gary Steffens, Martyn Stoker, Dorrik Stow and Alistair

Welbon. April Newman is thanked for providing logistical and

administrative assistance throughout the editorial process.

ExxonMobil also provided logistic support and kindly helped

fund colour pages. We are also very grateful to the Petroleum

Group of The Geological Society who championed the

meeting, encouraged the compilation of these papers and also

generously sponsored colour pages.

Contents

Preface v

Acknowledgements vi

3D seismic technology: are we realising its full potential?: DAVIES, R. J., STEWART, S. A., CARTWRIGHT, J. A., LAPPIN, M., 1

JOHNSTON, R., FRASER, S. I. & BROWN, A. R.

Depositional systems

Seismic geomorphology: imaging elements of depositional systems from shelf to deep basin using 3D seismic data: 11

implications for exploration and development: POSAMENTIER, H. W.

Depositional architectures of Recent deepwater deposits in the Kutei Basin, East Kalimantan: FOWLER, J. N, GURITNO, E., 25

SHERWOOD, P., SMITH, M. J., ALGAR, S., BUSONO, I., GOFFEY, G. & STRONG, A.

The use of near-seafloor 3D seismic data in deepwater exploration and production: STEFFENS, G. S., SHIPP, R.C., 35 PRATHER, B. E., NOTT, J. A., GIBSON, J. L. & WINKER, C. D.

Structural controls on the positioning of submarine channels on the lower slopes of the Niger Delta: MORGAN, R. 45

Sea bed morphology of the Faroe-Shetland Channel derived from 3D seismic datasets: LONG, D., BULAT, J. & STOKER, M.S. 53

3D anatomy of late Neogene contourite drifts and associated mass flows in the Faroe-Shetland Basin: KNUTZ, P. C. & 63

CARTWRIGHT, J. A.

Interactions between topography and channel development from 3D seismic analysis: an example from the Tertiary of the Flett 73

Ridge, Faroe-Shetland Basin, UK: ROBINSON, A. M., CARTWRIGHT, J. A., BURGESS, P. M. & DAVIES, R. J.

3D seismic analysis reveals the origin of ambiguous erosional features at a major sequence boundary in the eastern North Sea: 83

near top Oligocene: HANSEN, J. P. V., CLAUSEN, O. R. & HUUSE, M.

3D seismic interpretation of the Messinian Unconformity in the Valencia Basin, Spain: FREY MARTINEZ, J., CARTWRIGHT, J.A., 91 BURGESS, P. M. & VICENTE BRAVO, J.

Structural and igneous geology

3D analogue models of rift systems: templates for 3D seismic interpretation: MCCLAY, K. R., DOOLEY, T., WHITEHOUSE, P., 101

FULLARTON, L. & CHANTRAPRASERT, S.

Structural evolution of a complex 3D fault array in the Cretaceous and Tertiary of the Porcupine Basin, offshore Ireland: 117 JONES, G., WILLIAMS, L. S. & KNIPE, R. J.

Three-dimensional geometry and displacement configuration of a fault array from a raft system, Lower Congo Basin, Offshore 133

Angola: implications for the Neogene turbidite play: DUTTON, D. M., LISTER, D., TRUDGILL, B. D. & PEDRO, K.

Initial deformation in a subduction thrust system: polygonal normal faulting in the incoming sedimentary sequence of the 143

Nankai subduction zone, southwestern Japan: HEFFERNAN, A. S., MOORE, J. C., BANGS, N. L., MOORE, G. F. & SHIPLEY, T. H.

The evolution and growth of Central Graben salt structures, Salt Dome Province, Danish North Sea: RANK-FRIEND, M. & 149

ELDERS, C. F.

Integrating 3D seismic data with structural restorations to elucidate the evolution of a stepped counter-regional salt system, 165

Eastern Louisiana shelf, Northern Gulf of Mexico: TRUDGILL, B. D. & ROWAN, M. G.

Exploration 3D seismic over the Gjallar Ridge, Mid-Norway: visualization of structures on the Norwegian volcanic margin 177

from Moho to seafloor: CORFIELD, S. M., WHEELER, W., KARPUZ, R., WILSON, M. & HELLAND, R.

Tertiary inversion in the Faroe-Shetland Channel and the development of major erosional scarps: SMALLWOOD, J.R. 187

3D seismic analysis of the geometry of igneous sills and sill junction relationships: HANSEN, D. M., CARTWRIGHT, J. A. & 199

THOMAS, D.

Kinematic indicators for shallow level igneous intrusion from 3D seismic data: evidence of flow direction and feeder location: 209

TRUDE, K. J.

Application at development and production scale

Visualization and interpretation of 3D seismic in the Carboniferous of the UK Southern North Sea: LYNCH, J.J. 219

Direct visualization and extraction of stratigraphic targets in complex structural settings: JAMES, H., BOND, R. & EASTWOOD, L. 227

Locating exploration and appraisal wells using predictive rock physics, seismic inversion and advanced body tracking: 235

an example from North Africa: PICKERING, G., KNIGHT, E., BLETCHER, J., BARKER, R. & KEMPER, M.

Use of 3D visualization techniques to unravel complex fault patterns for production planning: Njord field, Halten Terrace, 249

Norway: DART, C., CLOKE, I., HERDLEV/ER, ,~., GILLARD, D., RIVEN/ES, J. C., OTTERLEI, C., JOHNSEN, E. & EKERN, A.

Seismic characteristics of large-scale sandstone intrusions in the Paleogene of the South Viking Graben, UK and Norwegian North 263

Sea: HUUSE M., DURANTI, D., STEINSLAND, N., GUARGENA, C. G., PRAT, P., HOLM, K., CARTWRIGHT, J. A. & HURST, A.

vm CONTENTS

Integrated use of 3D seismic in field development, engineering and drilling: examples from the shallow section: AUSTJN, B. 279

4D/time-lapse seismic: examples from the Foinaven, Schiehallion and Loyal Fields, UKCS, West of Shetland: BAGLEY, G., 297 SAXBY, I., MCGARRITY, J., PEARSE, C. & SEATER, C.

New applications

Improved drilling performance through integration of seismic, geological and drilling data: STEWART, S. A. & HOLT, J. 303

4D seismic imaging of an injected CO2 plume at the Sleipner Field, central North Sea: CHADWICK, R. A., ARTS, R., EIKEN, O., 311 KIRBY, G. A., LINDEBERG, E. & ZWEIGEL, P.

Towards an automated strategy for modelling extensional basins and margins in four dimensions: WroTE, N., HAINES, J., 321 JONES, S. & HANNE, D.

Examples of multi-attribute, neural network-based seismic object detection: DE GROOT, P., LIGTENBERC, H., OLDENZIEC, T., 333

CONNOLLY, D. & MELDAHL, P.

Modelling fault geometry and displacement for very large networks: LISTER, D.L. 339

Index 349

3D seismic technology: are we realising its full potential?

R I C H A R D J. D A V I E S 1, S I M O N A. S T E W A R T 2, J O S E P H A . C A R T W R I G H T 1, M A R K

L A P P I N 3, R O D N E Y J O H N S T O N 4, S C O T I. F R A S E R 5 & A L I S T A I R R. B R O W N 6

13DLab, School of Earth, Ocean and Planetary Sciences, Cardiff University, Main Building Park Place,

Cardiff CFIO 3YE, UK (e-mail: [email protected])

2BP Azerbaijan, C/o Chertsey Road, Sunbuo, on Thames, Middlesex TWI6 7LN, UK

3ExxonMobil Exploration Company, 233 Benmar, Houston, Texas 77060, USA

4Bp, E & P Technology Group, Chertsey Road, Sunbuo' on Thames, Middlesex TW16 7LN, UK

5Shell EP Technology Solutions, Shell International Exploration & Production Inc., 200 N Dairy Ashford,

Houston, Texas 77079, USA

6Consulting Reservoir Geophysicist, 1911 Country Brook Lane, Allen, Texas 75002, USA

Abstract: Three-dimensional (3D) seismic data have had a substantial impact on the successful exploration and production of

hydrocarbons. Although most commonly acquired by the oil and gas exploration industry, these data are starting to be used as

a research tool in other Earth sciences disciplines. However despite some innovative new directions of academic

investigation, most of the examples of how 3D seismic data have increased our understanding of the structure and stratigraphy

of sedimentary basins come from the industry that acquired these data. The 3D seismic tool is also making significant inroads

into other areas of Earth sciences, such as igneous and structural geology. However, there are pitfalls that parallel these

advances: geoscientists need to be multidisciplined and true integrators, and at the same time have an ever-increasing

knowledge of geophysical acquisition and processing. Notably the utility of the 3D seismic tool seems to have been

overlooked by most of the academic community, and we would submit that academia has yet to take full advantage of this

technology as a research tool. We propose that the remaining scientific potential far exceeds the advances made thus far and

major opportunities, as well as challenges, lie ahead.

The age of field-based geological mapping that began with

William Smith (1769-1839) started as a result of technological

advances such as mining and canal building, which in turn were

fuelled by basic commercial needs (Winchester 2001). In a

similar way, a 'new age' of subsurface geological mapping that

is just as far-ranging in scope as the early surface geological

mapping campaigns is emerging. It is the direct result of the

advent of 2D and subsequently 3D seismic data along with

advances in seismic acquisition and processing over the past

three decades. This 21st century 'quiet' revolution is driven by

the increasingly sophisticated technological demands made by

today's oil and gas exploitation industry but surprisingly this is

going on almost without remark from less directly related

sectors of the academic geological community.

The 3D seismic technology revolution has its roots in the

1930s when the first 2D data were acquired. A key evolutionary

stage was the advent of digital recording and processing

techniques during the 1960s. This facilitated 2D subsurface

imaging, followed in the 1970s by 3D imaging. The first

commercial 3D survey was recorded in 1975 in the North Sea

and was interpreted in the same year. 3D seismic data quickly

evolved from a research idea to cost-effective methods that have

substantially boosted the efficiency of finding and recovering

hydrocarbons. The quality of modern 3D seismic data is so high

in many cases, that the data are starting to be used as a research

tool and this is just beginning to allow researchers to challenge

certain paradigms of stratigraphy and structural geology.

The use of seismic data in the oil and gas industry quickly

led to a number of scientific advances. For example a

reinvigoration in stratigraphy started in the 1950s as a direct

result of the development of the common mid-point method

(Liner et al. 1999) and the acquisition and interpretation of 2D seismic data (Payton 1977). Widespread dissemination of the

rapidly expanding 3D database has the potential to advance many

geological disciplines which, in contrast to the 'stratigraphy

revolution', perhaps have less direct impact on the oil and

gas industry. In particular, the availability of surveys covering

several thousand square kilometres now enables basin-scale

processes to be investigated using the potential high spatial

resolution of 3D seismic data. New sedimentary and structural

phenomena are being imaged and explained for the first time.

These advances are perhaps not surprising when one considers

the scale limitations of most outcrop, which historically is the

most utilized type of geological data for studying structures at

similar scales. Many of our fundamental geological concepts

are rooted at the outcrop scale and therefore the alternative

perspective provided by 3D seismic imaging holds considerable

promise for developing and challenging these concepts, as well

as revealing new phenomena. Examples in this volume show

new phenomena that are recognized with 3D seismic, simply

because their size is such that they cannot be seen in toto for what they are at outcrop.

The aim of this introductory paper is to explore the breadth

of the impact of 3D seismic technology on the geological

sciences and to capture the overall aims of the volume: to raise

the profile of 3D seismic interpretation within the Earth science

discipline. The paper will set the scene for the Memoir by

reviewing the progress that has been made over the past three

decades in the development and application of 3D seismic

technology and exploring the future opportunities. The funda-

mental objective of the paper is to pose the question: are we fully

realizing the scientific potential that these data and the

technology could offer to Earth sciences?

2 D vs 3D s e i s m i c da ta

The ability to acquire and process 2D seismic data was

developed in the 1950s; 3D seismic data followed in the

1980s (Liner et al. 1999). 3D seismic is distinguished from 2D seismic by the acquisition of multiple closely spaced lines (e.g.

25 m) that provides regular data point spacing that feeds 3D data

migration during processing. This leads to a true data volume

DAVIES, R. J., CARTWR1GHT, J. A., STEWART, S. A., LAPPIN, M. & UNDERHILL, J. R. (eds) 2004.3D Seismic Technology: Application to the Exploration of Sedimentary Basins. Geological Society, London, Memoirs, 29, 1-9. 0435-40521041515 9 The Geological Society of London 2004.

2 R.J. DAVIES ET AL.

from which lines, planes, slices or 'probes' can be extracted in

any orientation, with nominally consistent data processing

characteristics. While it is possible to acquire a dense, 'high-

resolution' grid of 2D lines, or create a mesh of 2D coverage by

assembling spatially coincident 2D surveys of different

vintages, such grids are fundamentally different from true 3D

seismic data (Lonergan & White 1999). The close line spacing

of 3D seismic data means that these data do not have the

problems of spatial aliasing inherent to 2D seismic data, and

therefore have the potential to yield better stratigraphic

resolution, better migration and imaging of structural and

depositional dips. The density of subsurface reflection point

coverage allows stratal reflections to be mapped using

automated or semi-automated trackers to provide continuous

mapped surfaces that may in turn be used to derive a range of

seismic and structural attributes. These attributes feature

increasingly in exploration and development workflows.

Fundamentally, however, the greatest benefit of 3D resides in

its spatial resolving power both in terms of absolute spatial

resolution and relative accuracy in image positioning due to 3D

migration techniques employed during the processing of the

seismic data (Yilmaz 2001). Features such as fault systems can

now be mapped in much more detail than was possible with 2D

seismic data, with its inherent limitations of spatial aliasing

(Freeman et al. 1990).

Commercial considerations

The cost of acquiring 3D datasets is significant--tens of

thousands of US dollars per square kilometre for surveys that

are hundreds to thousands of square kilometres in size.

Therefore academic institutions rarely acquire and process

these data except over very small areas. The vast majority of

existing 3D seismic data have been acquired by the hydrocarbon

industry due to the key role this technology plays throughout the

life cycle of oil and gas exploration, development and

production. 3D seismic data and technology can often reduce

exploration risk, increase the accuracy of reservoir models and

at its best, enable development and production wells to be

positioned within complex hydrocarbon reservoirs (Dart et aI.

2004; Pickering et al. 2004). Although it may be regarded as an

expensive research tool, the cost of 3D seismic data has fallen

over the past 15 years (Table 1).

Evolving computer technology has facilitated the prolifer-

ation of 3D seismic data with a trend of decreasing cost but

increasing data quality. Increasing computer power has allowed

industry and academic groups to develop increasingly sophis-

ticated acquisition equipment and processing algorithms,

leading to advances in image quality along with increasingly

Table 1. Cost versus year of acquisition for 3D seismic data in the North Sea, UK

North Sea 3D cost over time

Year k USD (sq km)

1982 70-100

1986 30

1990 12-15

1993 8-9

1999 4

2002 10-20

large 3D datasets. The main driver behind the growth of 3D

seismic data over recent years, however, is global requirement

for hydrocarbon production. Although the global seismic

database is expanding, the rate of exploration drilling is such

that the obvious prospects are quickly tested and the inventory

of prospects relies increasingly on more subtle and higher risk

opportunities. This is paralleled by the movement of activity

into more challenging physical and political environments. The

main technical challenge today (2004) continues to reside with

processing geophysicists. They commonly work in collabor-

ation with asset teams (teams working on particular exploration

acreage, development or production project) which are well

grounded in the stratigraphic and structural history of a

particular area. Both disciplines should work jointly to produce

clearer, more accurate images that improve prospect economics

or increase recovery efficiency from producing assets.

F u t u r e exp lora t ion i m p a c t - - g l o b a l h y d r o c a r b o n reserves

A key question for 'E and P' geoscientists is to consider the

range in image quality within the proportion of global

hydrocarbon reserves imaged by 3D seismic. There are many

assets and basins around the world where data quality is

excellent but many datasets are good to poor due to geological

complexity. This is evidenced in Table 2 where the marked

assets and basins demonstrate a clear variability in data quality.

The hydrocarbon industry continues to make considerable

investment in improving seismic acquisition and processing to

improve poorly image quality within successions that have a

bearing on hydrocarbon exploration, development and pro-

duction. Doing so reduces risk and therefore effectively

increases global oil and gas reserves. Improving seismic

imaging is an ongoing, long-term and sometimes uncertain

approach to improving the quality of seismic interpretation that

is related primarily to economics--in most cases we know how

to collect the right data--instead short-term business drivers

dictate that we acquire data that we can afford. Acquisition (and

reprocessing) is then commonly repeated later, perhaps several

times during not only field life, but before any of this, during the

exploration for economic recoverable hydrocarbon volumes.

Interpreting 3D seismic data

When 3D seismic data first became available, there was no

experience or tool in use to optimize workflows, and early 3D

interpretations were done in a series of steps inherited from the

methodology developed for 2D seismic data. For example, good

understanding of the seismic wavelet, careful ties to synthetic

seismograms, checking datums and positioning, followed by a

methodical, grid based approach to interpretation, balancing

manual and automatic picking depending on data quality at a

specific reflector (Brown 1999). As the volume of 3D data has

expanded and technology has advanced, new workflow options

have emerged. One of the most significant developments for

interpretation is the evolution of the 'voxel', which is the 3D

equivalent of a 'pixel'. Pixel-based interpretation and voxel

interpretation use 'steering criteria' to grow interpretations

around manually inserted seed points or lines. Pixels are picked

on numerous 2D lines within a 3D dataset, where as voxels can

be selected within a 3D cube. This increases interpretation speed

but also allows interpreters to view all of the data within a

seismic data cube simultaneously, rather than on a line by line

basis. An opacity function allows the interpreter to instantly

remove data from view--perhaps low-amplitude reflections--

leaving high amplitude bodies that may represent reservoirs or

hydrocarbon accumulations. Both pixel-based autopicking and

3D SEISMIC TECHNOLOGY: REALISING ITS FULL POTENTIAL? 3

Table 2. List of 57 fields, assets and exploration areas subjectively ordered with respect to typical seismic resolution

Angola, Block 17

West of Africa, Girassol Field (high-frequency data)

North Angola

Southern North Sea (Quad 43)

Outer Congo Basin (with the exception of sub-salt succession)

Gulf of Mexico (with the exception of sub-salt succession)

Malay Basin

West of Africa: Congo

Nigeria Shelf

Nigeria Deep Water

Sakahlin Offshore

Black Sea

Mauritania Offshore

Southern Caspian Sea

West of Africa: South Angola

South Texas

Trinidad Shelf Mahogany

Mediterannean (Spain and Italy)

Beaufort Sea

Argentina, Neuquen Basin, Sierra Chata Field

Venezuela, Heavy Oil Belt, Cerro Negro Field

Brazil Offshore (Campos Basin)

India Offshore

Vietnam Offshore

Chad Doba and West Doba Basin

Inner Moray Firth, UK

West Texas, USA

Alberta and B C ~ a n a d a

Azerbaijan--South Caspian

Russia/Kazakhstan/Azerbaij an--Middle Caspian

West Siberia

Foz Do Amazonas Basin

Kazakhstan--PriCaspian PreSalt

Australia--NW Shelf

Michigan

Central North Sea, UK

Australia--Bass Straights

McKenzie Delta--Canada

Cook Inlet Alaska

Moray Firth North Sea

Argentina San Jorge

Falklands

West of Shetland--no Paleocene Basalt Cover

Irish Sea

US fold and thrust belt

Turkey--Onshore

Papua New Guinea--Onshore

North Atlantic Rockall

Flemish Cap---similar to Rockall off Nova Scotia

United Arab Emirates thrust belt

Bolivian Andes

PNG fold and thrust

Trinidad Onshore

North Sea giant chalk sub-gas cloud

Gulf of Mexico--sub-salt

West of Shetland--with Paleocene Basalt Cover

Gulf of Suez sub-salt

voxel autopicking are sensitive to signal variations as sensed by

the steering criteria, whether those variations are actual changes

in the geology or whether there is noise in the dataset. Noise

level, or data quality, is an extrinsic uncertainty that masks the

level of geological complexity which is an intrinsic uncertainty

in the data. This framework unsurprisingly suggests that voxel-

based approaches are of highest value in tackling the rapid

definition of simple structures in good seismic data quality

settings.

Pitfalls of the 3D seismic technology revolution

Rapid advances in technology commonly have unforeseen

pitfalls that go unnoticed in the excitement that drives the

change. We identify three challenges.

The in terpreter 's mindse t

"We met the enemy and he is us ' - -quote by American cartoonist

Walt Kelly (1970).

Perhaps the most significant potential pitfall lies with us,

the interpreters of 3D seismic data and it is rooted in our basic

behaviour. Many modern interpreters began their professional

lives without any in-depth experience of 2D seismic

interpretation. The research or asset team focus--and there-

fore the interpreter's focus--is swiftly directed at surface

mapping, attribute analysis and visualization: all of which are

key tools available to interpreters of 3D seismic data. Will the

present and next generation of interpreters be handicapped for

the lack of an apprenticeship in the 'harder' world of 2D

seismic interpretation? This world had different challenges of

interpolation between widely spaced lines as a precursor to

mapping but also a more holistic approach where the seismic

packages and their geometries were valued as much as

correlations of individual horizons. The tendency exists to

pick fewer lines and interpolate between widely spaced

sections and we term this 'data underutilization'. The data

are valuable and we must take care not to render the data

between mapped horizons as opaque or invisible through

overuse of this interpretation workflow.

Geophys ica l grounding

While interpretation tools have become increasingly accessible

it is likely that data acquisition and processing will become

more complex. Difficulties are compounded in multi-dimen-

sional seismic data types, such as 4D (Bagley et al. 2004;

Chadwick et al. 2004) and 4C. An understanding of the

assumptions made in the processing of 3D seismic requires an

ever-deeper understanding of geophysics. For example, multiple

attenuation algorithms are becoming increasingly sophisticated

and need careful supervision to ensure that primary reflectors

are not erroneously removed. This requirement mirrors a

necessity for the data interpreter to widen their 'skillset' to

encompass the range of geological architectures that are

resolved on higher quality data. The impact of this on

professional development--whether the specialists or general-

ists have the key roles--is currently a subject of debate in the oil

industry. The need for geophysical understanding and careful

calibration (Brown 2001) is paramount now and will become

more so in the future.

The view that 3D seismic volumes are 'true' realizations of

geological volumes is an assumption that can result in

exploration, development and production failure; and can

incur commercial penalties (e.g. Stewart & Holt 2004). Basic

acquisition problems along with various sources of noise, mis-

positioning of seismic energy and tuning (e.g. Yilmaz 2001 ) are

as significant now as they have ever been. Exploration acreage

can be located within complex geological settings and this

forces interpreters to work right at the limits of data resolution

and in many instances beyond (e.g. 'ghosting' horizons through

areas of poor data). At the scale of many reservoirs the

interpretation of flow units that are below seismic resolution is

sometimes a necessity when projects require i t--this can be

termed 'data overutilization'. Arguably other examples of data

overutilization come from the misuse of so-called direct

4 R.J. DAVIES ETAL.

hydrocarbon indicators (DHIs). Many experienced industry

interpreters will be able to recount examples of prospects that

were dramatically de-risked through the identification of a

DHI that did not make geological sense. In many cases pros-

pects have been drilled on 'overutilized' data and have been

proven dry.

Other common pitfalls include the tendency in clastic

successions to view seismic amplitudes as a direct indicator of

lithology. This of course should be cautioned against as fluid

content can significantly reduce acoustic impedance and there-

fore seismic amplitude. To get indications of fluid or lithology

from 3D seismic or impedance volumes typically requires

further processing after a thorough petrophysical study of the

rock involved (Whitcombe et al. 2002).

The e v o l v i n g ro le o f the s e i s m i c i n t e r p r e t e r

To meet the challenge of the pace with which the technology is

advancing the interpretation community needs to include fully

integrated ('quantitative') geoscientists with a general under-

standing of all aspects of data acquisition, processing and a

specialized knowledge of interpretation. A significant develop-

ment related to the growth of 3D seismic data as the 'core' of

assessment of hydrocarbon occurrence, volume and distribution

is the breakdown in the division of geologist and geophysicist in

the hydrocarbon exploration and production industry. Until very

recently it was typical for the 'geophysicist' to develop an

understanding of 'the container' using 2D and 3D seismic data

tied to well 'tops' while the geologist provided information on

reservoir distribution and quality using wireline logs, core data

and a regional understanding. This is changing: the modem

interpreter must truly be a multidisciplinarian, well versed in

subjects as diverse as petrophysics and sequence stratigraphy.

Continued professional training is thus a priority in such a

demanding environment.

3D seismic data: impact on Earth sciences

Despite the inevitable pitfalls the technology is positioned to

have a tremendous impact on Earth sciences. The history of

research in the geosciences is populated with examples of

paradigm shifts inspired by new technology, for example

submarine warfare technology and its role in the recognition

of marine magnetic anomalies associated with sea floor

spreading. 2D reflection seismology has already played a key

role in the evolution of concepts of extensional tectonics and

stratigraphy during the 1970s and 1980s, perhaps in part because

the academic community was fully involved in the acquisition

of the data. Indeed, academic programs in deep reflection

seismic were responsible for some important breakthroughs in

rift tectonics and basin development (e.g. the BIRPS and

COCORP projects--Klemperer & Hobbs 1991 ).

The abundance of large 3D seismic surveys now represents

a significant opportunity for research geoscientists from a

diverse range of disciplines to benefit from this petroleum

industry investment. Research is no longer spatially restricted

to tens of square kilometres and the typical extent of an oil

and gas field. In some areas sufficient 3D seismic data has

historically been acquired so that 'megamerges' of the surveys

provide coverage of entire sections of basins, for example in

the North Sea Basin, where only ten years ago, there would

have been incomplete coverage of variable quality 2D data

with local 3D across producing fields. These aerially extensive

surveys allow basin analysis at a very high spatial resolution

afforded by the 3D grid spacing. This means that there is no

loss of detail with increasing area and that structural and

stratigraphic elements can be placed in a basin wide context.

This gives basin analysis a fundamental new tool with which

to tackle diverse issues such as basin modelling, e.g. White

et al. (2004), basin wide fluid flow, sub-regional tectonics or

depositional systems and their stacking.

A small number of academic studies have nevertheless

been pursued with 3D seismic data as the principal research

medium either because of their intrinsic interest, because they

are based on collaborative partnerships with industry, or

because of serendipitous 'discovery' whilst in pursuit of

objectives of economic interest. Recognition of new geologi-

cal structures is always possible on 3D surveys because of the

newly available resolving power (Cartwright 1994; Davies

et al. 1999, Davies in press). Recently for example a 3D

seismic approach was applied to the investigation of meteor

impact craters and this has raised awareness of the potential of

3D seismic amongst the specialists investigating cratering on

the terrestrial planets (Stewart & Allen 2002). Every new

map, whether it be a time map or seismic attribute has the

potential to reveal features that we are yet to fully appreciate

in the field. Such features are not identified in the geological

lexicon.

Due to simple economic prerogatives, some advances have

been made in the effort to maximize production from discovered

accumulations. For example the study of post-depositional

remobilization of clastic reservoirs (Lonergan & Cartwright

1999; Huuse et al. 2004). Certain types of remobilisation

structures illustrate how 3D seismic allows for the identification

of features that currently have no good field analogue

(Molyneux et al. 2002; Gras & Cartwright 2002). The same

principle applies to the study of a diverse range of soft-sediment

deformation structures from density inversion folds (Davies

et al. 1999) and polygonal faults (Cartwright 1994) to giant

pockmarks (Cole et al. 2000). Soft sediment deformation is

likely to receive much more attention in the future, not least

because it is often apparent in the highest frequency part of the

seismic profile (e.g. Davies in press). There is a wealth of

seismic data from the first second of two-way travel time below

mud line, that has no commercial value but covers geological

phenomena of significant academic interest (Knutz & Cart-

wright 2004; Smallwood 2004) or has important implications for

offshore installation integrity (Austin 2004; Long et al. 2004)

and well planning (Stewart & Holt 2004).

S t r a t i g r a p h y

The concepts of seismic stratigraphy (Payton et al. 1977)

were based on 2D seismic data but the advent of 3D seismic

data now allows for individual depositional elements to be

recognized and for the interpreter 'to go beyond the parase-

quence'. Studies in this volume (Fowler et al. 2004; Frey

Martinez et al. 2004; Posamentier 2004; Robinson et al. 2004;

Steffens et al. 2004) illustrate three-dimensional seismic facies

distribution and stratigraphic architecture and demonstrate the

degree to which research in these disciplines has advanced

today. Recent focus has been on deepwater depositional

systems. In this setting it is commonplace to use several

reprocessed seismic volumes of an original dataset that are

designed to exploit various rock properties calibrated to

borehole petrophysics (Whitcombe et al. 2002). These data-

volumes typically display the seismic differences between fluid

and lithology, the presence or absence of AVO anomalies,

qualitative and quantitative acoustic impedance inversion. In

addition, parallel advances in software manipulation have

enabled the development of spatial-stacking or optical stacking

techniques for enhanced flat-spot analysis (Worrel 2001). All or

some of the described techniques have been used to further


augment the seismic resolution of complex sedimentary

architectures inherent in deepwater sands. Indeed visualization

of ancient deepwater processes via the highest quality 3D

datasets is providing the interpreter with startling images of

sinuous channel complexes on deepwater slopes. What began as

a primarily model-driven view of the relationship of reflection

seismic data to depositional models has evolved to a point where

the recognition of process-derived facies distributions can be

visualized directly (Fowler et al. 2004; Steffens et al. 2004;

Posamentier 2004). The understanding of clastic depositional

processes has received much attention from academic research-

ers because of the shift towards deepwater clastic reservoirs as

exploration targets (e.g. Morgan 2004). This will continue to be

a major growth area in the next decade, but researchers will

bridge disciplines to tackle the interactions between sedimen-

tation and tectonics in a host of deep water settings (e.g. Hansen

et al. 2004). The application of 3D seismic data to disciplines

such as geomorphology, a field that has now been coined

'seismic geomorphology' (Posamentier 2004) are still being

advanced by industry geoscientists.

S t r u c t u r a l g e o l o g y

The most significant advances in structural geology that have

resulted from the application of 3D seismic interpretation are

probably fault system geometry (e.g. Dutton et al. 2004; Jones

et al. 2004; McClay et al. 2004) and kinematics and salt

tectonics (e.g. Rank & Elders 2004; Trudgill & Rowan 2004).

Examples include mapping distributions of displacement on

fault surfaces (Nicol et al. 1996; Walsh et al. 2002; Lister 2004)

and using mapped stratal terminations projected onto the fault

surface plane, or Allan diagram, to map fault rock properties

(Bouvier et al. 1989). 3D mapping of fault planes and

intersections has allowed topological frameworks to be devised

(Nicol et al. 1996) and specific 3D problems have been

encountered that have caused structural fundamentals such as

strain to be revisited (Cartwright & Lonergan 1996). More

recently, large basement faults in rift systems have been studied

using regional surveys to examine the kinematic evolution of

basin-scale tectonostratigraphic architecture (Dawers &

Underhill 2000; MacLeod et al. 2002). Future research will

almost certainly extend the insights gained into the evolution of

normal fault systems to the study of thrust and wrench fault

systems.

In addition to fault geometries, 3D seismic can contribute to

more general strain analysis by defining the geometry of growth

strata (Bouroullac 2001) and controlling 3D structural restor-

ation that may reveal subseismic strain distribution. 3D seismic

is also a powerful means for delineating small faults and

fractures that can exert a major influence on field performance

(Hesthammer & Fossen 1997).

I g n e o u s g e o l o g y

Although conventionally a subject restricted to field-based

researchers, large acoustic impedance contrasts with surround-

ing sediments means that igneous phenomena easily manifest

themselves on 3D seismic surveys located in the petroliferous

volcanic margins of the UK, Norway, Brazil and West Africa.

Complexes of igneous sills and flood basalts have been

identified in these areas (Planke et al. 2000; Davies et al. 2002;

Hansen et al. 2004; Trude 2004). Igneous sills in particular are a

classical illustration of the optimum use of 3D seismic in a

research context. They are very well imaged on 3D seismic

because of their large impedance contrasts with the host sedi-

ments, and hence are relatively straightforward to interpret. This

has meant that the three-dimensional geometry of sills can be

defined with considerable accuracy, and this has led to several

novel conclusions about the interactions between sills and their

host rocks as well as the fundamental mode of emplacement

itself (Hansen et al. 2004; Trude 2004). These insights were

not possible with field-based approaches alone, because of the

incompleteness of the outcrop of even the best exposed sills.

Future potential

As with any technological advance there are likely to be both

predictable and unpredictable innovations as well as surprises.

AVO, pre-stack depth migration, long offset 3D, 4D (e.g.

Bagley et al. 2004; Chadwick et al. 2004) and other

technologies such as neural network based detection systems

(e.g. De Groot et al. 2004) that have emerged in the past ten

years now fill geophysical journals. If investment means that the

fields of research into 3D seismic technology and its application

in Earth sciences are well fertilized then opportunities are

significant. We can also consider the spin-off technologies such

as 3D visualization (e.g. Bond et al. 2004; Corfield et al. 2004;

Lynch 2004) that now allow key geological problems within a

prospective region to be assessed and an efficient work direction

decided within an afternoon, rather than over a period of weeks.

Perhaps the application of this technology in Earth sciences may

result in every Earth science department in the first World being

equipped with a visionarium in 15 years time. Such a facility

would be used for teaching and research but not just to look at

seismic data but outcrops, core plugs and any other data that

benefits from communication in an immersive 3D environment.

In this paper we cannot focus on every avenue that may bear

fruit but a notable absentee from the Memoir are papers devoted

to what may prove to be an important area of future

technological growth-4C seismic.

4C seismic

3D seismic data are essentially a discretization of the Earth in

terms of the properties of sound waves of which there are three

main types: surface, interface and body. Each of these is

characterized by the nature of its wave propagation in Earth

materials. The body waves are of most use in the seismic data

context as they propagate information through the Earth, and are

not confined to boundaries. There are two types of body wave:

longitudinal (P-) waves, which transmit information by

compressing particles in the Earth back and forth in the

direction of wave travel; and transverse (S-) waves, which

transmit information by shearing particles past each other in

directions perpendicular to the wave direction. Seismic sources

can in fact be designed to emit either wave type, and receivers

designed to record either.

3D seismic images formed from marine towed streamer data

typically use the properties of P-waves to remotely sense the

Earth, because S-waves do not propagate in fluids. In contrast,

on land 3D seismic images can be formed using either P- or

S-waves, depending on the source of waves and the type of

receiver at the surface. Since shear waves propagate by causing

particle motion perpendicular to the direction of travel, they can

only be recorded properly by an arrangement of three geophones

that are sensitive to particle velocity or acceleration. It is normal

to arrange the geophones in three mutually orthogonal

directions, such as in the X, Y and Z directions of a Cartesian

coordinate frame, thus representing the three components (3C)

of a vector recording of the particle motion. 4C seismic is a

method of acquiring marine seismic data that combines

three orthogonal geophones from land acquisition with the

6 R.J. DAVIES ET AL.

hydrophone from towed streamers to give four-component (4C)

recording. This is made possible by deploying the specially

designed 4C sensor packages on the sea floor so that they are

coupled to the elastic Earth to record particle motion on the

geophones, but still in the water to record the pressure on the

hydrophones. The marine source is typically an airgun array that

creates P-waves in the water. Due to the partitioning of energy at

elastic boundaries within the Earth (reflectors, reflector

terminations, etc.), conversions occur from P- to S-(and vice

versa) so that both P- and S-waves are recorded. It is possible,

and entirely likely that these conversions occur thoughout the

subsurface. However, only the strongest conversions are

observed in the processed 3D volume, and these tend to occur

where the highest contrast exist, such as at the sea floor (Tatham

& Goolsbee 1984) or, more usually, at the reservoir refectors.

There are numerous potential benefits that 4C may bring,

for example: (1) imaging where towed streamer (P-wave) data

cannot, for example, through gas chimneys, low P-impedance

reservoirs, beneath salt, basalt or mud volcanoes; (2) reduction

of water column multiple energy through 'PZ summation';

(3) flexible receiver geometries on the seafloor permit

acquisition of long offsets and wide azimuths which

improve illumination, fold and SNR; (4) lithology and fluid

prediction, by direct measurement of shear waves for AVO, as

opposed to inference from P-wave data alone; (51 fracture

mapping from wide-azimuth P-wave data, and C-wave

splitting analysis to give fracture orientation, fracture density

and pore-fluid fill.

The first commercial success of 4C seismic took place in

1994 in the North Sea (Berg et al. 1994), which showed that

P-to-S conversions at deep reflectors (C-waves; Thomsen

1999) could provide an image through a gas cloud where the

conventional P-wave image was obscured. This is mostly due

to the pore fluid (gas) being invisible to the S-wave leg,

whereas the P-waves are attenuated heavily. Although there

have been very many 2D test 4C surveys, there have been

relatively few 3D 4C surveys worldwide. They include Alba,

Emilio, Gullfaks, Hod, Lomond, Staffjord and Valhall. There

are major challenges ahead with acquisition and processing of

4C data, particularly with the X and Y components to form

converted wave images.

True 4D seismic and the 'electric oilfield'

3D seismic provides a static picture of the Earth. To understand

dynamic Earth processes requires observation over time. 3D

seismic can provide the dynamic data in the form of repeat

surveys over the same area. Over the last ten years much effort

has gone into developing workflows to process multiple 3D

volumes from the same area to emphasize changes due to the

dynamic processes.

Just as two or three 2D seismic lines would not be

considered 3D seismic, so two or three 3D surveys cannot be

considered 4D seismic, rather they should be termed more aptly

time-lapse 3D seismic. The method of acquiring time-lapse 3D

can be towed streamer, 4C or a combination of both. A principal

objective in time-lapse seismic processing has been to remove

acquisition differences between repeat surveys (such as

variations in towed cable feathering), and to make processing

as similar as possible.

Installing an array of 4C seismic sensors permanently on the

seafloor potentially provides very repeatable 3D seismic. 3D

seismic can then be acquired with a shooting vessel as

frequently as required, for example, every few months for the

lifetime of an oilfield field. This is true 4D seismic since the time

axis has more than a few points and dynamic effects may be

observed, rather than inferred from the differences between

static 3D surveys. The first of these true 4D surveys is

documented in Barkved et al. (2003).

A permanent installation of sensors on the seabed coupled

with instruments in wells also provide the opportunity for

further monitoring of the subsurface, for example, dynamic

subsidence in the overburden, and micro-earthquake events

from sub-seismic faulting in the reservoir--the 'electric oilfield'

vision of dynamic Earth monitoring.

Conclusions

The most fundamental impact of 3D seismic was a major

improvement in imaging, positioning of seismic energy and

spatial frequency of data. The most closely spaced 2D seismic

grids have line spacing in the order of hundreds of metres--

exploration surveys were often of kilometre grid spacing. With

no control on how sparsely sampled phenomena link along

strike, fault patterns and displacement profiles, for example, are

spatially aliased. 3D reduces the onset of aliasing by at least an

order of magnitude, to around 20m and the increase in

resolution is obviously more significant if factored volume-

trically. So phenomena that existed at a hundreds of metre to

kilometre scale were imaged in 3D for the first time.

One could take the view that 2D and 3D seismic data are the

first tools to directly image the subsurface in three-dimensions

and that their advent represents one of the most significant new

techniques available to the solid Earth sciences of any

developed within the past century. The advent of this new

type of data has created an opportunity to train the next

generation of geoscience students in three-dimensional subsur-

face mapping in addition to the training they receive in

traditional surface mapping techniques. By doing so this

generation will be cognizant of its utility for understanding

basin forming and filling processes just as the present generation

of geoscientists understands the benefit of detailed geological

mapping. Whilst the data stream comes mainly from the

petroleum industry, the opportunities for research will be mainly

in prospective basins. However, as the cost of acquisition and

processing decreases, there will be increasing use of 3D

surveying for primary research purposes (Heffernan et aL

2004). The major challenges facing academic exploitation of

this extraordinary data resource are how to equip laboratories

capable of handling large data volumes, and how to persuade the

hydrocarbon industry and governmental partners and sponsors

to provide the means to do so.

ML, SS, SF, RJ thank ExxonMobil Exploration Company, BP and Shell for permission to publish this paper. E. Jansen of Schlumberger provided information used to construct Table 1. M. Huuse made comments on an early draft of this paper. T. Dor& A. Fraser and J. Howe provided helpful reviews.

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2027,

Seismic geomorphology: imaging elements of depositional systems from shelf to deep

basin using 3D seismic data: implications for exploration and development

H E N R Y W. P O S A M E N T I E R

Anadarko Canada Corporation, 425 1st Street SW, Calgary.', Alberta T2P 4V4, Canada

(e-mail: [email protected] )

Abstract: 3D seismic data can play a vital role in hydrocarbon exploration and development especially with regard to mitigating risk associated with presence of reservoir, source, and seal facies. Such data can afford direct imaging of

depositional elements, which can then be analyzed using seismic stratigraphy and seismic geomorphology to yield

predictions of lithologic distribution, insights to compartmentalization, and identification of stratigraphic trapping

possibilities. Benefits can be direct, whereby depositional elements at exploration depths can be identified and interpreted.

or they can be indirect, whereby shallow-buried depositional systems can be clearly imaged and provide analogues to

deeper exploration or development targets. Examples of imaged depositional elements from both shallow and deep sections are presented.

Seismic data have long been used for lithologic prediction.

Initially, such interpretations were based on the analysis of 2D

seismic reflection profiles (Vail et al. 1977). The approach that

was used involved first the identification of reflection termin-

ations (e.g. onlap, downlap, toplap, erosional truncation) and the

recognition of stratigraphic discontinuities such as unconfor-

mities. Second, the reflection geometries between discontinuity

surfaces were described (e.g., oblique or sigmoidal prograda-

tion). Finally, the amplitude, continuity and frequency of

reflections were described and mapped. In sum, these obser-

vations yielded insights with regard to the type of depositional

systems present. This approach was referred to as seismic

stratigraphy (Vail et al. 1977).

With the development of 3D seismic acquisition techniques,

the opportunity to image geological features in map view

opened up new approaches to geological prediction (e.g.

Weimer & Davis 1996). Various reflection attributes such as

amplitude, dip magnitude, dip azimuth, time/depth structure and

curvature, to name a few, can be observed to yield direct images

of depositionally and structurally significant features. In

addition, analysis of seismic intervals can lend further insight

to such features. The study of depositional systems using 3D-

seismic derived images has been referred to as seismic

geomorphology (Posamentier 2000). This represents a signifi-

cant step change in how seismic interpreters evaluate 3D seismic

data. In general, depositional environments had commonly been

inferred on the basis of cross-section derived stratigraphic

architecture and subsequent mapping of seismic facies leading

to lithologic predictions. With the advent of seismic geomor-

phology, discrete, detailed depositional subenvironments and

depositional elements could be interpreted directly from map

view images leading to much more accurate understanding of

lithologic distribution patterns and enhanced prediction of the

distribution of reservoir, source and seal facies.

The following discussion will be divided into two parts, the

first section illustrating examples of seismic images of

depositional elements at exploration depths, and the second

illustrating images of depositional elements at shallow depths.

Depositional elements at exploration depths

Cretaceous channels--Alberta, Canada

Figure 1 illustrates two views of a major channel crosscut by

two lesser channels. Figure 1A is a horizon slice or flattened

time slice, whereby a reflection 32 ms above was interpreted

and used as a reference horizon for the purpose of slicing

through the 3D seismic volume. Figure 1B is a reflection

amplitude map of reflections immediately below the reflection

associated with the channel. Each images the channels in a

different way, with different details brought out by the two

display styles. Both show linear features within the large

channel, which can be interpreted as possible point bar

deposits. Both show a crosscutting and therefore younger

channel in the middle of the illustration. However Figure 1A

shows another smaller channel crosscutting the larger

channel towards the bottom of the illustration, not apparent

in Figure lB.

The integration of seismic geomorphology and seismic

stratigraphy is illustrated in Figure 2. Inclined reflections within

the interpreted channel fill can be observed on the reflection

profile oriented normal to the long axis of the large channel (Fig.

2B). These reflections can be interpreted to represent lateral

accretion surfaces associated with point bar deposition within

the channel (Figs 2C and D). The isopach map indicates

the presence of a thicker channel fill on the southwestern side

of the channel (Figs 2A and D). The seismic profile reveals that

the thicker part of the channel does not correspond to a deeper

channel thalweg, but rather is associated with a 'bump' across

part of the channel. This 'bump' is interpreted to be associated

with a substrate that is less compactible than the other part of the

channel fill (Fig. 2C). This least compactible section would

suggest the presence of lateral accretion sets that would be most

sand-rich, sand being less compactible than silt or shale

(Fig. 2D).

Planning of horizontal well bore trajectories should take into

account the presence of internal stratigraphic architecture

comprising varying lithologies (Fig. 3). In this instance,

orientation of horizontal well bores parallel to the lateral

accretion deposits would allow for improved reservoir manage-

ment. Lithologic variations associated with bedding parallel

boreholes would be lower than those associated with bedding

normal boreholes. Consequently, drilling parallel to bedding

planes might better protect against gas or water breakthrough.

Alternatively, if gas or water breakthrough is not a concern, then

a preferred strategy might be to drill across bedding planes so as

to access and drain multiple compartments with a single

borehole.

Several crosscutting Cretaceous-aged channels are illus-

trated in Figure 4. This image represents a map of the negative

polarity total amplitudes within a 16 ms window that contains at

DAVIES, R. J., CARTWRIGHT, J. A., STEWART, S. A., LAPPIN, M. & UNDERHILL, J. R. (eds) 2004.3D Seismic Technology: Application to the Exploration of Sedimenta~ Basins. Geological Society, London, Memoirs, 29, 11-24. 0435-4052/04/$15 9 The Geological Society of London 2004.

12 H.W. POSAMENTIER

Fig. 1.

3d seismic technology application to the exploration

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