Deep-water clastic reservoirs: a leading global play in terms of reserve replacement

and technological challenges

A. HURST,1 A. J. FRASER,2 S. I. FRASER3 and F. HADLER-JACOBSEN4

1University of Aberdeen, Department of Geology & Petroleum Geology, Kings College,

Aberdeen AB24 3UE, UK (e-mail: a.hurst@abdn.ac.uk)2BP Exploration, Chertsey Road, Sunbury-on-Thames, Middx TW16 7LN, UK3 Shell International Exploration and Production Inc, 200North Dairy Ashford, Houston, Texas 77079, USA4 TEK F&T, STATOIL ASA N-7005 Trondheim, Norway

Abstract: Experience from the exploration for, and development of, deep-water clastic reservoirs offshore NW

Europe has provided an important testing ground for new technology and has subsequently been applied globally.

In NW Europe, Upper Jurassic, Lower Cretaceous and Paleogene intervals have proven play fairways, all of

which retain exploration potential.Ancient, particularly Tertiary, passivemargins are identified as themain areas

of current global deep-water exploration interest; a review of play characteristics is given. Innovative geophysical

data and data analysis play an important role in deep-water clastic reservoir geology. The roles of AVO and

seismic inversion are emphasized in the context of direct hydrocarbon indication and reservoir delineation. In

areas of modern deep water, when drilling for ancient deep-water clastic targets, the importance of acquiring the

right data at the right time is critical to creating robust predictive models.

Keywords: deep-water clastics, turbidites, passive margins, slope channels, basin-floor fans, 3D seismic facies,

exploration risk reduction

Deep-water clastic reservoirs inNWEurope are among the largest,most explored, best described, and most productive of their kind.Exploration success, and subsequent appraisal and developmentof, these highly productive reservoirs, have produced data thatprovide a unique insight into the interplay of deep-water sedimentdispersal with basin geometry. Integration of abundant subsurfacedata has enhanced regional- and reservoir-scale models andallowed reservoir performance to be monitored optimally, withan improved knowledge and respect for sub-surface complexity.Development of the NW European deep-water reservoir plays hasmandated innovation in geoscience technology in tandem withcreative engineering technology solutions. Repeatedly, NWEuropean deep-water clastic fields have posed significant technicalchallenges for leading-edge technologies to resolve. Innovativegeoscience concepts have resulted in best technology practices thathave subsequently been transferred to global deepwater basinswith astounding success (Fraser et al. this volume; Vear thisvolume). Here, we present some key facts that documenttechnology transfer on global and local scales.

NW European Perspective

Deep-water clastic reservoirs form important hydrocarbon playfairways in the Tertiary, Cretaceous (predominantly Lower) andUpper Jurassic of the North Sea and Atlantic margins. UpperJurassic, deep-water reservoirs are known from the northern areaof the North Viking Graben and East Shetland Basin (Shepherd1991; Partington et al. 1993; Watts et al. 1996; Ravnas & Steel1997), the South Viking Graben (Cherry 1993; Garland et al.1999), the Moray Firth (Harker et al. 1993), with prospectivesequences associated with the basinward erosion products ofshallow marine Fulmar Formation in the Central Graben (Fraseret al. 2002), and west of Shetland (Herries et al. 1999; Fig. 1). Thedeep-water facies define a spectrum of linked depositional systemswithin the Upper Jurassic syn-rift sequence. Small radius (c. 5 km)conglomeratic apron-fan complexes dominate hanging-wall

depocentres immediately adjacent to major Upper Jurassic riftbounding faults while sand-prone, larger radius (c. 1015 km)basin floor fans occupy the distal portion of these linkeddepositional systems (Fraser et al. 2002).Lower Cretaceous deep-water fairways (Fig. 2) are locally

prolific in the Moray Firth where they are ponded in the remnantrift bathymetry as part of the early post-rift fill of the basin. Thereservoirs occur in combined structural and stratigraphic traps andsubstantial exploration potential probably remains (Garrett et al.2000; Martinsen et al. this volume). Some unusual sedimentaryfacies are often present in finer grained, more distal parts of thefairways that include the probable products of slurry flows (Lowe& Guy 2000), a previously unrecognized sedimentary facies indeep-water environments, which presents challenges in terms ofthe interpretation of pay and saturation distribution in otherwisesand-prone reservoirs. Minor Lower Cretaceous reservoir sand-stones are known east of the Shetland platform but theirdistribution is not well understood (Kerlogue et al. 1995;Copestake et al. 2003). Several small, low nett:gross sandstonesare present along the mid-Norwegian margin, two of whichcomprise the Agat Field (Guldbrandsen 1987; Skibeli et al. 1995)andmore recently the Snadd Field (Fugelli et al. 2002;Grtte et al.2002). Deep-water reservoirs are prospective west of Shetlandbut as yet only sub-commercial discoveries have been made(Goodchild et al. 1999).Tertiary, and in particular Paleocene, deep-water sandstones

(Fig. 3) reservoir some of the largest accumulations known in theNorth Sea (Bain 1993) and most of the currently recoverablereserves west of Shetland (Davies et al. 2004). Sandstones ofTertiary age are largely derived from denudation of the ancientnorthern British landmass. During the Paleocene, the samenorthern British landmass fed the deep-water East ShetlandBasin with coarse, poorly sorted sand, whereas west of Shetlandthe sand was finer grained and the depositional systems were lesssand-prone. Several elongate depositional systems, built out fromthe ancient Scandinavian landmass, are known to reservoir

HURST, A., FRASER, A. J., FRASER, S. I. & HADLER-JACOBSEN, F. 2005. Deep-water clastic reservoirs: a leading global play in terms of reserve replacementand technological challenges. In: DORE, A. G. & VINING, B. A. (eds) Petroleum Geology: North-West Europe and Global PerspectivesProceedings of the6th Petroleum Geology Conference, 11111120. q Petroleum Geology Conferences Ltd. Published by the Geological Society, London.

economically significant hydrocarbons (Gjelberg et al. thisvolume; Hamberg et al. this volume) and remain significanttargets for further exploration.

In the Eocene, sandstones become less widely distributed and

form smaller, often linear, reservoir units (Hartog Jager et al.

1993). Narrow (,25 km) sand-rich fairways are commonand have frequently acted as laterally extensive (in some cases

.50 km) conduits for secondary migration (e.g. west of theGannet field complex into the Pilot and Harbour discoveries,

Fig. 4). Sand injectites may extensively modify (Harding, Dixon

et al. 1995; Gryphon, Purvis et al. 2001; Balder, Bergslien 2002;

Alba, Duranti et al. 2002), or form (Grieg, Lawrence et al. 1999;

Chestnut, Huuse et al.), Eocene reservoirs; they complicate reser-

voir geometry and lithostratigraphic correlation. These systems are

increasingly recognized and may constitute new exploration plays(Hurst et al. this volume).In terms of the global impact of NW European experience, it is

important to emphasize the role of the Paleocene Foinaven andSchehallion fields, as examples of slope-channel systems that arepart of the passivemargin systemwest of the UK. This is one of thesettings where the role of slope-channel architecture, the generalgeomorphology of the depositional system, and the concepts ofintra-slope accommodation and reservoir development on slopeaccommodation were developed. Following the advent of 3Dseismic data (noting that the first commercial 3D seismic surveywas recorded and interpreted in the North Sea in 1975, Davies et al.2004), the seismic interrogation of the depositional profile couldbe used to clarify and resolve the complexity of reservoir geometryand architecture within the slope setting. Subsequently, the use ofamplitude extractions, time slices, horizon consistent semblancevolumes and, more recently, stratal slices has become commonindustry practice for resolving the architecture of individualcomponents of the deep-water system (Zeng & Tucker 2004).It is our view that North Sea data and prospectivity focused us

on process. Importantly this gave confidence in the prediction ofdepositional systems and of sand quality and architecture, insteadof relying on the lowstand-fan slug models that are based onsequence boundary recognition to predict down-dip sands. High-quality 3D seismic data allowed the mapping of compactionanomalies associated with lithological variations and subsequentlythe relationships between amplitude response and lithology/fluidcontent to be investigated. The drilling of relatively cheap deep-water North Sea wells permitted the calibration of deep-waterfacies from core and wireline logs directly with high-frequencyseismic (Hadler-Jacobsen et al. this volume;Martinsen et al. thisvolume). Confident ties between well and seismic data allowed thepetrophysical properties to be constrained and rock-responsemodels were created to directly calibrate seismic data.

Play concepts

Ancient passive margins are the predominant tectonic setting forexploration for deep-water clastic reservoirs. Typically, the majorplay fairways are ancient deep-water depositional systems that liedown slope of major river systems, which drain major continentallandmasses (Congo, Niger, Nile, Mississippi), predominantly ofTertiary age.

Source

Only locally are significant petroleum source facies associatedwith deep-water systems of Tertiary age (e.g. Baram Delta pro-delta facies, Brunei). The fine-grained strata associated with areasof major deep-water sedimentation are generally of poor sourcerock quality as the high rates of sediment accumulation dilute theconcentration of organic matter and promote oxidation beforesubstantial burial occurs. More typically the petroleum sourcesystem is in the underlying passive margin sequence (e.g.CenomanianTuronian of the Atlantic margins, Schiefelbeinet al. 1999) or the precursor rift sequence (e.g. Jurassic of NWEurope, Cornford 1998). In some deep-water plays, identificationof specific source rocks may be enigmatic despite long historiesof exploration and production that would normally elucidatethis fundamental component of petroleum systems. This may beparticularly true in basins where very high sedimentation ratesoccurred, burial history becomes very challenging to model, andthe location of possible source-rich intervals may be difficult toresolve using seismic data and where calibration with boreholepenetrations is limited.A well-documented Tertiary petroleum province in which low

rates of fine-grained deposition prevailed is along the Californiancoast where deep-water sandstones are interbedded with pelagicand hemipelagic mudstones and diatomaceous cherts, the former

Fig. 1. Location of oil and gas fields with Upper Jurassic deep-water

sandstone reservoirs on the NW European continental margin. Fields are

concentrated in the Moray Firth and along the eastern flank of the Fladen

Ground Spur. Discovery of the possibly billion barrel plus Buzzard field

has rekindled interest in this interval.Data aremodified and expanded upon

from Fraser et al. (2002).

Fig. 2. Location of oil and gas fields with Cretaceous deep-water

sandstone reservoirs on the NW European continental margin. With three

exceptions fields are located along Lower Cretaceous depositional fairways

in the Outer Moray Firth. It is widely believed that there is substantial

remaining prospectivity in the Cretaceous. Snadd Field is in Coniacian

(UpperCretaceous) sandstones.Data aremodified and expanded upon from

Garrett et al. (2000) and Copestake et al. (2002).

A. HURST ET AL.1112

which contain highly productive source rocks that are interbeddedwith reservoir intervals. These source rocks accumulated duringperiods of upwelling. A remarkably similar source system isbelieved to occur on the western margins of the Pacific around theisland of Sakhalin and the Kamchatka peninsula where deep-waterclastic reservoirs are supplied by the palaeo-Amur river.

The key elements for understanding petroleum systems inTertiary deep-water settings are the extent of the source facies,the thermal stress to which the source beds have been exposed,and the rate at which expelled hydrocarbons can migrate throughthe overlying stratigraphic section. The rate at which themigration (or petroleum) front moves through the section

shows a lag-time determined by the permeability of sealintervals such that an oil phase can lie above areas of present-day gas-mature source. In modern Tertiary systems this has beenestimated at around 1mm/year, approximately the same order ofmagnitude as the rate of deposition. Understanding the geometryof the petroleum front is critical. In Tertiary deltaic systems with

asymmetric sediment loads, the petroleum front is not a simplesurface in the earth and is governed by the effective stressregime and the capillary entry and exit pressures required thatallow the petroleum phase to migrate through the section.Understanding the permeability structure of the basin, through

depositional facies analysis is thus fundamental to the predictionof petroleum accumulations in the subsurface.

Seal

Thick intervals of fine-grained strata commonly overlie thehydrocarbon-prospective intervals in deepwater depositionalsettings. These units act with varying degrees of efficiency asregional top seals.Most regional seals in deep-water environmentsare deposited as a consequence of relative sea-level rise, denu-dation and/or change in character of source terrain, or a combina-tion of both. Typically these are related to marine condensedhorizons, which appear to onlap or base lap surfaces on seismicdata. They represent the structural/compaction geometry thathas had time to develop during periods of low sediment flux.Most shale/mudstone intervals have sufficiently low permeabilityto serve as capillary seals for petroleum accumulations (Bjrkumet al. 1998). The later effects of clay mineral diagenetic reac-tions on top seal permeability reduction has been proposed as ageological control on reducing petroleum biodegradation risks(Nadeau et al. this volume).As seismic resolution has improved, heterogeneities within

shale-prone intervals that may compromise their seal integrity,

Fig. 3. Location of oil and gas fields with Paleocene deep-water sandstone reservoirs. The Paleocene contains several mature deep-water clastic plays

focussed on the huge sand-prone submarine fan systems that built out from the ancient northern British landmass in to the present-day central North Sea

and less sand-prone systems to the west of Shetland. Data are modified and expanded upon from Ahmadi et al. (2002).

DEEP-WATER CLASTIC RESERVOIRS 1113

have become more apparent such as polygonal faults (Cartwright1994) and sand injecties (Hurst et al. 2003a, b). These hetero-geneities are frequently associatedwith hydrocarbon seeps (Lsethet al. 2003) and may preferentially vent gas from basins thusallowing oil to remain trapped.

Reservoir

Deep-water clastic reservoirs have two basic end members, whichare a product of the interaction between the size/volume ofsediment input as turbidity currents and the shape and size of thebasin receiving the sediment. Confined deposition occurs when theaverage width of high-density turbidity currents is equal to orgreater than the maximum width of the basin (accommodation).Unconfined deposition occurs when the average width of high-density turbidity currents is less than the maximum width of thebasin. Sedimentation in confined systems contrasts with that inunconfined systems as it is dominated by interactions between thesediment input and the topography and geometry of the basin. Assuch, the grade and mineralogy of the sediment entering the deep-water basin has a second-order influence on reservoir quality aslong as high-density turbidity currents occur.No scale is implied inthe differentiation between confined and unconfined systems andwith changes in the size and frequency of high-density turbiditycurrents into a basin through time, systems can change in characterfrom confined to unconfined and vice versa.

Confinement tends to produce sand-rich deposits with thicklybedded units that pinch out rapidly, usually against inclinedmargins. These systems are termed inefficient deep-water (fan)

systems by Mutti (1985). They are typified by sand-rich characterwith high N/G, excellent field-scale vertical permeability (Kv),

thick bedding, and rapid pinch-outs against opposing lateral andaxial slopes (infill of Hurst et al. 1999). Unconfined systems aregenerally substantially more stratified and less sand-rich than

confined systems. Mutti (1985) defines these as efficient deep-water (fan) systems in which sediment is transported effectivelyfrom proximal to distal areas of the basin. Sand and shale units

have high lateral continuity but high N/G reservoirs are unusual,field-scale Kv is typically poor unless fine-grained intervals are

disrupted by channels, scours, fractures, sand injections or, less so,bioturbation. Correlation between sections/wells can bemade withmore confidence than in the deposits of confined systems.

Many deep-water clastic reservoirs are associated with prolificwell productivity. For example, the Paleocene Forties Field in the

North Sea produced at a rate of 500 000 barrels of oil/day during itsplateau production. Both core and wireline character from deep-water sandstones that were deposited in confined (topographically)

basins typically show, at least superficially, homogeneousreservoir character (tanks of sand!). The common paucity ofprimary sedimentary structures, combined with overprinting by

water-escape structures (Lowe 1975), makes relationshipsbetween depositional processes and sand body geometry obscure.

Fig. 4. Location of oil and gas fields with Eocene deep-water sandstone reservoirs. Eocene prospectivity is widespread but relatively lightly explored.

Due to the shallowness of the reservoirs oils tend to be heavy. Sandstones are laterally restricted and are frequently modified by sand injectites. Data are

modified and expanded upon from Jones et al. (2002).

A. HURST ET AL.1114

Bedding thickness in sand-rich systems varies and is typically

complicated by the presence of amalgamation and by-pass

surfaces. Consequently, lateral correlation between units observed

in approximately vertical sections on a metric, even decametric,

scale is fraught (Hurst et al. 1999). This leads to complications

when generating 3D models of sand body geometry when up-

scaling procedures, such as employed successfully with many

other clastic reservoir facies (Pickup et al. 1995), are untenable

(Hurst et al. 2000).

Much of the current deep-water exploration activity on present-

day continental margins is focused on slope depositional systems

rather than the base of slope and basin floor settings inferred in

many earlier studies (summarized in Stow et al. 1996). Although

the sedimentary processes are similar, lateral confinement on

slopes forms strongly linear systems in which debrites, derived

from confining slope instability, are common. These slope

environments are normally associated with sediment bypass but

with the aid ofmodern 3D seismic imaging technologies have been

shown to display significant reservoir development, particularly in

confined slope channels (Mayall & Stewart 2000) and ponded

intra-slope mini-basins (Prather 2003). Channel and canyon

complexes dominate the upper slope (region of enhanced

depositional dip downslope of the progradational slope), linked,

at least periodically, to major sediment entry points, and variably

located slump complexes. Depending on the depositional dip, and

the shelf to basin relief, the canyon and channel systems can

deliver large volumes of coarse-clastic material considerable

distances into deepwater areas.

Turbidite slope channels commonly originate in the upper slope

as low sinuosity, narrow, levee-confined channels (Fig. 5). Locally,

the final central meander may be preserved as a narrow sinuous

channel (Mayall & Stewart 2000). Levees develop when the sedi-

mentary load cannot be contained within the confinement of the

channel during periods of high sediment flux. Further downslope,

where the depositionalgradient is reduced, the mid-slope channels

have an initial erosional confinement with a later fill phase that may

spill beyond the original confinement. Slope channels may take

complex routes through slope topography (Fig. 5) and display

variable sinuosity. Unlike in fluvial systems, channel sinuosity in

deepwater systems is poorly understood and relates to a range of

controls including the lower gradient, local seafloor topography and

sedimentary processes (Peakall et al. 2000; Mayall & Stewart

2000). Extensive high-quality 3D seismic indicates that few

channel systems terminate on the slope, although crevasse splaydeposits are common at changes of gradient and at sharp changes in

channel course.

The products of mass wasting, including slumps and debris

flows, aremajor components of slope depositional systems. Debris

flows occur both as large-volume, widespread lobate bodies, and

as locally derived elements of slope channel complexes where

their geometry reflects the shape of the channel floor onto which

they flowed. Rarely do the products of mass wasting provide

intervals of reservoir quality, and exploration focus is centred on

the slope channel complexes and their associated overbank and

mouth-bar deposits. Debris flow deposits (debrites), which may

vary greatly in sand content, frequently form over substantial areas

in deepwater systems. In confined settings debris flows are

ultimately constrained by the same topographic limits that limit

sand deposition from turbidity flows. Debris flows may be derived

axially from headward slopes or laterally from marginal slope

areas. Their composition is largely controlled by the composition

of the area from which they are derived. Even when sand-rich and

reasonably porous, the high content of fine-grained clasts and poor

sorting leave debrites with generally very poor reservoir quality.Hence, they may bewater saturatedwithin otherwise hydrocarbon-

bearing intervals, and have localized sealing capacity (Mayall &

Stewart 2000). A more positive characteristic of debrites is that

they constitute useful stratigraphic time-lines, which help intra-

reservoir correlation.

Outcrop analogues. As most exposures of deep-water clastic

systems were not deposited along ancient passivemargins or in rift

associations there are few outcrops that provide direct analogues

for the major deep-water clastic hydrocarbon provinces. However,

this may not be a significant factor as the lack of scale dependence

on confined or unconfined systems means that even within an

analogue, which has gross characteristics that are dissimilar to the

subsurface, there will be some features that remain relevant. In this

context, it is clear that emphasis should be placed on improving

the understanding of the physical processes of sedimentation

Fig. 5. Slope channel complexes, Angola. Image is a windowed stratigraphic amplitude extraction from the Miocene slope section of the Lower Congo

Basin. The slope channels highlighted above the background mudrocks take complex routes through slope topography. Extensive high-quality 3D seismic

indicates that few channel systems terminate on the slope, although crevasse splay deposits are common at changes of gradient and at sharp changes

in the channel course. Note the highlighted crevasse splay complexes at base of upper slope and at the sharp right-angled bend.

DEEP-WATER CLASTIC RESERVOIRS 1115

(Kneller 1995; Kneller & Branney 1995; Peakall et al. 2000) asopposed to the simple search for visual and geometric analoguesfor populating statistical models of reservoirs.The resolution of modern 3D seismic data has revealed features

that can be given sedimentological significance (see below) but ata thickness scale of .510m these occur at a scale often notrecorded in outcrop studies. A significant challenge remains toassociate the features observed on seismic data with featuresobserved on the modern seafloor and in the outcrop record,however, huge progress in uniting these disparate data has beenmade and supports confident prediction of lithology distribution(Hadler-Jacobsen et al. this volume).Our collective experience isthat the integration of outcrop analogue data into subsurfacemodels greatly enhances the understanding of uncertaintyassociated with all aspects of reserve mapping and fielddevelopment.

Technology

Geophysics

Although none of the following technologies were developedspecifically to explore or exploit deep-water clastic reservoirs,many of their early and successful applications have had asignificant effect on investment in several deep-water provinces.Advances in seismic technology have had impact in two funda-mental areas that mitigate lower risk exploration in modern deepoceans for ancient deep-water clastic reservoirs: (1) resolutionof features that may be given sedimentological or geomorpholo-gical significance, and (2) definition of direct hydrocarbon indi-cators (e.g. flat spots and amplitude conformance with structure).In addition, the optimization of recovery from fields has beenvastly improved by application of time-lapse (4D) seismic (Jack1998) a method that was pioneered in NW Europe on the deep-water clastic Magnus oilfield (Watts et al. 1996). Further refine-ment of time-lapse technology has been possible using permanentocean-bottom cables.Acquisition of shear wave data, initially from ocean-bottom

cable surveys and more recently from long-offset data, enablesimproved reservoir mapping in intervals where reservoir and non-reservoir lithologies in deep-water clastic reservoirs are not easilydifferentiated using p(compressional)-wave seismic data(MacLeod et al. 1999; Hoare 2001).

Direct hydrocarbon detection

By the application of acoustic impedence inversion and therecognition of AVO spatial stackingwe have the ability to variablyimage fluids and lithology and to highlight flat spots and/ordepositional features. By understanding the geology, the lithologycan be predicted and its effect removed, thus revealing the presenceof fluids.Inverted seismic data are the preferred volumes for interpret-

ation in deep-water systems. The key benefits of this method are:

. removal of the wavelet effect;

. images more closely resemble geology;

. the physical meaning is greater and more easily related toreservoir and fluid properties;

. reservoir properties are separated from overburden affects;

. stratigraphic interpretation can be improved.

One of the really big gains is that more people understand theconcept of impedance and geology than seismic traces, and thusworking in the impedance domain is an ideal mechanism forintegrating disciplines.Once seismic data are inverted, probably the key risk reduction

tool used in deep-water exploration is the application of AVO(amplitude versus offset) technology. AVO is basically anexceptional lithology indicator. However, integration of global,

or preferably local, rock property data can allow shale, brine-filledsand and hydrocarbon-filled sand to be separated in the seismicinversion domain (Fig. 6). Algorithms have been developed thatallow rotation of inverted data to differentiate lithology response

from fluid response in AVO gradient impedance (GI) and acousticimpedance (AI) space (Whitcombe & Fletcher 2001; Whitcombeet al. 2002).As mentioned above, AVO alone is excellent in describing

lithology. However, when used for fluid discrimination it may be

misleading and often misused. AVO gradient impedance can,however, be used regardless of whether one is examining ClassI, II or III responses to effectively discriminate lithology fromfluid; gas, oil and brine can be isolated in AI/GI space. Because

these fluid points lie almost on a straight line, one can define arelationship between them. The data can be projected in aspecific direction to enhance the separation between them. Thisdirection may be termed the fluid projection since it is adirection that highlights fluid change within a reservoir. The

lithology direction by definition is orthogonal to the fluiddirection. The display of seismic volumes in the fluid projectionand the lithology direction is immensely powerful in explorationrisk reduction (Fig. 7).

When conventional seismic data are viewed down the axis of achannel or a depositional body the complex lithology is revealedalong with the amplitude signature, which may indicate hydro-carbon charge.However, there is significant risk that the amplitudestrength reflects porosity and not pay. As well as AI/GI projection

other technologies are employed to reduce risk. By stacking all thetraces within a depositional body onto a single vertical time ordepth section, constant surfaces such as flat events are enhanced.This is another key exploration risk-reducing tool (Fig. 8). By acombination of AVO and flat spot enhancing technologies, the pre-

drill identification of pay sands and hydrocarbon-water contactshas allowed exploration success in Angola to exceed 95%.A commitment to obtaining the right data is the key to

delivering exploration success and improved technical under-

standing of deep-water depositional systems. Whether it is high-resolution data for the detailed reservoir description of complexslope-channel systems, or imaging in seismically difficult areas,great care must be applied during both acquisition and processing.

Fig. 6. AI/GI crossplot after Whitcombe & Fletcher (2001). The AI/GI

crossplot provides an effective means of visualizing AVO behaviour

and tying rock property data to seismic data. Acoustic impedance (AI)

is displayed on the x-axis and gradient impedance on the y-axis. The AI/GI

crossplot allows a seismic AVO projection to be easily determined to

maximize a particular property such as the separation of hydrocarbon

from brine filled sands or between sands and shales.

A. HURST ET AL.1116

Fig. 7. AVO gradients: fluid and lithology discrimination. Petrophysical log data is used to derive a gradient impedance log which is then filtered to the

bandwidth of the seismic. From the acoustic impedance and the gradient impedance the fluid impedance can be calculated (Whitcombe & Fletcher 2001;

Whitcombe et al. 2002). The display of seismic volumes in the fluid projection and the lithology direction is immensely powerful in exploration. With

data tuned to fluid and lithology exploration risks are considerably reduced; this is a key factor for improving exploration and appraisal performance in

increasingly expensive deep-water environments.

Fig. 8. Direct hydrocarbon detection. Conventional data down a channel or depositional body axis highlights the complex lithology and corresponding

amplitude signature. However, there is significant risk that the amplitude strength reflects porosity and not pay. As well as AI/GI projection other techniques

can be employed to reduce risk such as flat spot enhancement (sfe) technologies (see Fraser et al.). By stacking all the traces within a depositional body

onto a single vertical section time or depth constant surfaces such as flat events are enhanced. The identification of petroleum water contacts (flat-spots)

on 3D seismic data pre-drill has allowed exploration success in deepwater Angola to exceed 95%.

DEEP-WATER CLASTIC RESERVOIRS 1117

Deep-water confined channel systems are inherently complex with

multiple phases of channel fill. Conventional seismic data, even at

high frequencies (c. 60Hz), fails to resolve the internal geometry

and architecture that is required for planning reservoir develop-

ment (Fig. 9). Acquisition of high-resolution 3D seismic

(essentially 3D site surveys with up to 150Hz bandwidth) resolves

many of the internal stratigraphic complexities.

Immersive visualization environments are in increasingly

common use for displaying and interpreting 3D seismic volumes

in both exploration and production (Davies et al. this volume). Theability to tune the data to fluid and lithology allows a detailed

analysis of their 3D distribution in the subsurface for both field

development and well planning.

Wireline logs. Probably the most significant contribution made

by advances in wireline technology to the exploration and

development of deep-water clastic reservoirs involves the

resolution of thin beds, and more generally characterization of

sedimentary facies (Harker et al. 1990;Hansen& Fett 2000), using

borehole imaging tools. Although not unique applications to deep-

water clastic reservoirs, they have had particular significance

when applied to reservoirs that are typified by box-car profiles on

gamma-ray and sonic logs, often interpreted as structureless

sandstones, when in fact subtle depositional or post-depositional

features may be present and of significance when considering

reservoir heterogeneity and continuity (Duranti et al. 2002).

Risk

Technical risk is associated with the estimation of reserves and

well productivity from deep-water clastic reservoirs, in particular

in modern deep-water settings where exploration well costs are

high and in situations where long-reach, multi-lateral wells are

required to facilitate commercial development. As exploration

moves into deeper modern oceans and more remote, often

environmentally sensitive areas, the impact of exploration and

development activities on local and global environmental stability

(e.g. aquatic species breeding, seasonal migrations, etc.) become

more challenging to estimate and manage.

Reservoir modelling of deep-water clastic reservoirs, in

common with other clastic sedimentary environments, is con-

stantly accelerated by the ever-increasingly capacity and speed of

desktop computers. Acquisition of outcrop data allows detailed

input of metre-scale heterogeneities when describing field-scale

reservoir architecture (Gardner & Borer 2000; Gardner et al.

2003). Hence, provided that appropriate interpretation of subsur-

face data is made, numerical modelling can mitigate risk

associated with field development scenarios.

As mentioned earlier the possible destabilization of slope

environments is a safety issue both for offshore installations and

coastal centres of population. An additional risk is the environ-

mental impact of operations on slopes, which are widely believed

to be major breeding grounds for marine organisms but which are

poorly documented and understood.

Fig. 9. Deep-water confined channel systems are complex with multiple phases of channel fill. Conventional seismic data, even at high frequencies

(c. 60Hz), typically fail to resolve the internal geometry and stacking description required for reservoir development. The acquisition of high-resolution

3D (essentially 3D site surveys with up to 150Hz bandwidth) resolves many of the internal stratigraphic complexities.

A. HURST ET AL.1118

Conclusions

The massive potential for the discovery of significant hydro-carbons within ancient deep-water clastic reservoirs has borne fruitalong many modern deep-water continental margins. To enableenvironmentally acceptable and safe exploration and exploitationof these reserves, seismic and drilling technologies have madehuge advances, many of which had pioneer application in offshoreNW Europe. Continued successful exploration will depend on theglobal transfer of technology. Improved understanding of deep-water clastic systems requires greater and improved integration ofdata from the subsurface, modern seafloor and outcrops to providemore robust predictive models.

The authors would like to thank Ian Vann and Ian Stewart, who delivered

the keynote paper for the deep-water session at the conference, for allowing

us to use several of their excellent presentation materials as illustrations in

this paper. The views expressed in the paper are those of the authors and do

not necessarily represent the views of their employers.

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