Abstract Exploration and production in deep water (>500m) has expanded greatly during the past decade, and approximately 57 BBOE has beeen discovered, more than half since 1995. Despite this rapid emergence, deep water remains an immature frontier, accounting for less than 5% of the current world-wide total oil-equivalent resources. Only about 20% of the discovered deep water resources are developed and less than 5% have been produced. The global deep water exploration success rate was about 10% until 1985, but has since averaged approximately 30%, driven by remarkable success in the Gulf of Mexico and West Africa. Whereas the world-wide discovery of giants has fallen off in recent decades, the discovery rate of deep water giants is rapidly increasing. Most of the exploration activity has been concentrated within only three areas of the globe, as a majority of the discovered resources in the Gulf of Mexico, Brazil, and West Africa. Consequently, large portions of the world’s deep water margins remain lightly explored. Deep water gas exploration is extremely immature, reflecting current infrastructure and economic limitations but destined to become a major future focus. Most of the currently most active deep water exploration frontiers and associated resources are located along passive margins, downdip from productive Tertiary delta systems, in depocenters confined by mobile substrate. In simplest terms, petroleum systems responsible for the majority of the discovered resources can be classified as either early rift (lacustrine) or later passive margin (marine). Ninety percent of the resources are reservoired in turbidites, primarily of Cenozoic age. A key success factor is targeting “high kH” reservoirs, which have high flow rates and well ultimates. These commonly occur within ponded minibasins associated with mobile substrate, where stacked turbidites result in high net pay per area. Other key exploration success factors have been seismic DHI’s, identification of stratigraphic traps, and improved reservoir architecture prediction. Leading companies are moving into non-DHI plays and other geologic settings, including pre-Tertiary objectives and areas lacking major updip reserves. Recent trends suggest several themes for future deep water exploration: (1) a continuation of established plays, which are still at an immature stage of drilling, (2) going beyond the established formula to basins lacking updip production, unconfined basins, compressive margins, and targeting pre-Cenozoic, non-turbidite, and non-DHI objectives, (3) increased gas exploration, as pipeline networks and liquefaction technology advance in conjunction with increased consumption, (4) going deeper, both ultra-deep water and deeper drilling depth, including subsalt, sub-detachment, and sub-volcanic targets, and (5) new business opportunities which may arise in areas currently not open due to government monopolies, moratoriums, and international boundary disputes. New frontiers having these characteristics are being actively leased, but many have yet to experience significant drilling, so it remains to be seen whether the deep water play will continue to add reserves at the rate of recent years.

Abstract The Scotian Basin, under Atlantic Canada’s continental shelf and slope, encompasses a corridor 100 to 150 km wide by 900 km long on the southeastern continental slope of the province of Nova Scotia, Canada. Since 1967, a total of 103 exploration wells have been drilled in the shelf portion of the basin within the setting of the Sable subbasin. The Scotian Basin is divided into a series of geologically distinct subbasins. Opening occurred during the Middle to Late Triassic, in response to separation of North America from Africa. During this time, synrift red beds, restricted marine dolomites and halites of the Eurydice, Iroquois and Argo formations, respectively, have been deposited. From the Early Jurassic to the end of the Cretaceous, the basin continues to subside, infilling with significant quantities of fluvio-deltaic and shelf sandstones. During lowstands, incision of the shelf carries sands down the paleoslope into deep marine environments, where they are deposited within a variety of subaqueous facies. The Tertiary-aged Banquereau Formation consists of fluvial, deltaic, and deep water sandstone environments. Although tectonically passive, deep water portions of the Scotian Basin contain the Scotian salt province. This subbasin is extensively deformed by halokinetic movement of Late Triassic Argo Formation halite, which mobilized to form swells, walls, ridges, and domes. Sedimentation and play-types vary considerably along the 900 km of the salt province within water depths of 1,000 to 3,000 metres with the potential for a number of distinct petroleum systems throughout the subbasins and include potential subsalt exploration targets.

Abstract A series of conceptual Mesozoic plays was defined in the ultra-deep water U.S. Gulf of Mexico by interpreting a 2×2 mile grid of 2-D seismic data covering an area of approximately 39,000 square miles basinward of the Sigsbee salt canopy. Time maps on the seafloor, approximate Cretaceous/Tertiary boundary, Mid-Cretaceous Sequence Boundary, approximate Jurassic/Cretaceous boundary, top autochthonous salt, and “basement” seismic events were constructed and converted to depth using regional interval velocities. Conceptual plays in the western and central planning areas of the Gulf of Mexico include fold belts and buried hills; the latter have been subdivided into structural, stratigraphic-detrital, and drape plays. In the eastern planning area, a structural play that is characterized by salt rollers, autochthonous salt swells, pinnacle salt structures/vertical salt welds, and salt growth and/or salt withdrawal (turtle) features was delineated in the West Florida Salt Basin. Reservoir analogs for each play were identified by searching worldwide for fields having similar trap type and reservoirs of comparable depositional environment. Monte Carlo simulations were run to analyze and develop distributions of the analog data. Petroleum system analysis was performed to incorporate, describe, and display the elements (source, reservoir, and seal) and the processes (trap formation, generation–migration–accumulation, and critical moment) associated with each play. Play risks were evaluated, described, and presented using a “traffic light” ranking system. The results of this study suggest that in the ultra-deep water Gulf of Mexico, these and other conceptual Mesozoic plays may offer a variety of future high-potential exploration opportunities. This paper is a synopsis of over 2 years of work, and not all of the details can be presented in a paper of this length.

Abstract The hydrocarbon-prolific eastern East Maturin Basin of Trinidad and Venezuela is filled with more than 40,000 ft of deltaic, fluvial/estuarine and deep marine sands and shales deposited in a rapidly subsiding basin along the triple junction of the westward-subducting Atlantic plate and the obliquely colliding Caribbean and South American plates. The basin is characterized by several northwest-southeast-striking roller faults across which the Plio-Pleistocene expands to the northeast. Several thrust-cored anticlinal ridges trend northeast to southwest, and major hydrocarbon fields are aligned along them. The last Cretaceous shelf-break trends east to west and has an important influence on the underlying Miocene interval, which appears to thicken to the north across this paleogeomorphic feature. Increased thickness of Miocene shales along the northern margin of the basin results in increased shale diapirism in this same region. Bidirectionally thickened bow-tie anticlines form, whose crests migrate to the east as they become younger, and associated secondary roll-over faults emerge. These roll-over faults partition hydrocarbon accumulation within the bow-tie structures. Thinning of Miocene shales along the southern margin of the eastern East Maturin Basin decreases the influence of diapirism, resulting in formation of monodirectional thickening of section to the west and thinning to the east. Thus monoclinal structures contain the majority of structural traps in the footwall of younger roller faults. Shale rollers or secondary roll-over faults are rare. Understanding the nature and influence that previous paleogeography can exert on a basin’s structure, migration pathways, and accommodation distribution can lead to improved predrill and postdrill assessment of hydrocarbon systems risk.

Abstract Regional mapping and maturity modeling show distinct patterns that are characteristic of the complex petroleum system in the deep water portion of the northern Gulf of Mexico (GOM). Maturity for source rocks within the Cretaceous and Jurassic sections tends to increase from the abyssal plain to the salt canopy province as the overlying section thickens. One striking exception to this trend is the Cuba fracture zone, which extends southeast from South Pass to the southern GOM. Observed as a strong magnetic anomaly in basement maps, the Cuba fracture zone shows other impressive anomalies. Heat flows tend to increase approximately 25% along the zone relative to calibration points on either side, which suggests that it is an important crustal feature. Empirically, the Cuba fracture zone appears to be a major dividing point in the north central GOM, where on its northeast side gas appears to be much more prominent than on the southwest side. Mapping the GOM on a regional scale required the integration of 2D and 3D seismic data, gravity and magnetic data, and large-scale velocity models that include salt for proper depth conversion. Basement maps were generated from the integration of gravity and magnetic data with acoustic basement mapping from seismic in the abyssal plain. A variety of key chronostratigraphic horizon depth maps were generated from a regional velocity model that included salt and was applied to multiple time horizons. Probably the most difficult mapping task was to make accurate correlations between areas with enormous amounts of data (e.g ., 3D seismic) and those with a paucity of data ( e.g ., 2D seismic in subsalt sections). Developing maturity models required an accurate set of stratigraphic depth maps, calibration and mapping of heat flow on a large scale, and the appropriate choice of source rock horizons and associated properties to evaluate. Results from this regional evaluation indicate that there is a definite relationship between source rock maturity and major oil and gas discoveries. The timing of hydrocarbon generation and migration relative to the timing of structuring is critical to each successful discovery. This can be evaluated on a regional scale when maturity results are placed in context with general structural trends.

Abstract The Falkland Islands are surrounded by four major sedimentary basins (the Falkland Plateau basin to the east, the South Falkland basin to the south, the Malvinas basin to the west, and the North Falkland basin to the north). The basins underwent complex rifting from the ?Triassic through Valanginian, during fragmentation of Gondwanaland, before being subjected to Cretaceous thermal sag and Cenozoic uplift coincident with Andean compression and the development of overthrusting along the plate boundary to the south. Only the North Falkland basin was drilled; six wells were spudded back to back by four operators who formed a unique alliance in 1998 to undertake all of the logistics and support work to facilitate a multi-well drilling campaign. Drilling took place in water depths between 250 and 460 metres. Five of the six wells had oil shows, mostly in post-rift sandstones located immediately above the main source rock interval. Live oil was recovered at the surface from one of the Shell wells; significant levels of gas were also recorded in some wells. Although none of the wells encountered commercially viable accumulations, it is possible that up to 60 billion barrels of hydrocarbons could have been expelled in the basin. Post-mortem analyses of the petroleum system revealed why the wells were non-commercial and pointed the way to future commercial success. As well as the remaining potential of the North Falkland basin, the other large, deep water to ultradeep water basins around the Islands are under explored and are covered only by reconnaissance seismic data. Oxfordian to Aptian claystones present in DSDP boreholes indicate a potentially prolific hydrocarbon yield from Type II kerogens. Modelling suggests that the source rocks are possibly mature for oil generation at about 3,000 metres below seabed, and numerous play types can be predicted on the basis of the existing seismic data and by correlation with analogous basins. The paper will highlight the entire basin potential of the offshore Falklands region (petroleum systems, sequence stratigraphy, tectonic evolution, etc.), evaluate the pros and cons of the unique exploration sharing strategies adopted so far, and outline the exploration and production challenges posed by the particularly sensitive environmental concerns in the region.

Abstract Improved understanding of the interaction between basement structure, salt tectonics, and depositional systems can be of great value in tract evaluation and resource assessment, particularly in subsalt areas or under-explored, emerging plays. One such area is the Abyssal Fan Play of the ultra-deep water Gulf of Mexico. Here, an ordered basement fabric appears to have influenced the vertical juxtaposition of potential Mesozoic source rocks, Tertiary reservoirs, and vertical migration pathways. Examination of central Gulf of Mexico tectonic elements, structural features, salt systems, and field distributions reveals patterns of systematic right-lateral offsets along trends that approximate North Atlantic fracture zones. Regional maps of Mesozoic and Tertiary horizons generated from a modern 2x2-mile 2-D seismic grid were used to interpret transfer fault trends and delineate Mesozoic rift basins beneath the abyssal plain. These basins are seen to be right-stepping across a series of northwest-southeast trending transfer faults in southern Atwater Valley, Walker Ridge, and Lund. These basins may contain source rocks of Jurassic or Cretaceous age. Dramatically high-standing basement blocks beneath the abyssal plain may be Cretaceous volcanic edifices that exploited the transfer fault zones during a period of post-rift tectonism. Transfer fault zones may have served as sediment fairways through the salt canopy and fold belt throughout the Tertiary. Point sources for Miocene deep water fans emanate from the Mississippi Fan Fold Belt where fold axes are offset along transfer fault zones. The middle Miocene section contains an apron of fans just outboard of the Sigsbee Escarpment, but is condensed over most of southern Walker Ridge, Atwater Valley, and Lund. However, seismic facies suggest that some sand-prone middle Miocene fans were directed by basement-controlled fairways beyond the southern margin of Lund and Lund South. Across the northeastern half of the abyssal plain, within the corridor between the Cuban and Campeche fracture zones, regional dip is to the southwest. Across southwestern Lund and western Walker Ridge, to the west of the Campeche fracture zone, regional dip is to the northwest, as the section climbs toward the Yucatan block. This basin configuration has focused deposition toward southeastern Lund, where middle Miocene fans onlap the outer reaches of the Campeche rise. Combination structural-stratigraphic traps in middle Miocene fans overlying uplifted basement or Cretaceous volcanic edifices can be sourced from adjacent rift basins by a series of regional joints and fractures. These elements comprise a new play that extends the Miocene frontier 150 miles south, to the limits of U.S. waters.

Abstract Neogene-Recent arrival of the Caribbean plate and subsequent development of the southern Caribbean plate boundary zone as well as coeval deposition of Orinoco deltaic sediments in Eastern Venezuela-Trinidad have profoundly changed the region’s earlier basin setting, including some very large vertical and horizontal displacements of original tectonic elements and depositional systems. Plate kinematic analysis provides the geometric and temporal framework in which to see past these late developments and to deduce the region’s earlier paleogeographic evolution and constrains the primary setting, style, and timing of basement structure in the region’s shallow-water, and deep-water continental margins through time. Palinspastic restoration of deformations, terrane accretions, and sedimentary additions to the region’s continental areas back through time to the breakup of Pangea allows fine-tuning of the kinematics and prediction of parameters such as paleo-heatflow, paleo-sedimentary provenance, and aspects of source and reservoir potential. In Eastern Venezuela-Trinidad, Jurassic rifting has produced a serrated crustal margin, along which rift segments are oriented ~070° and separated by sinistral transfer zones at ~140°. A Late Jurassic-Cretaceous “passive” margin along the proto-Caribbean seaway developed above this basement, but sinistral shear between South American and Bahamian crusts along the Guyana Escarpment may have caused continued tectonism into Early Cretaceous, prior to truly passive margin Late Cretaceous source rock deposition. Paleogene convergence between North and South America caused uplift and erosion in Venezuela’s northern Serranía del Interior, the flyschoid depositional results of which are found in northern Trinidad. This is because the northern Trinidad depocenter, here called the Northern superterrane, was situated much closer to the Serranía at that time, as opposed to southern Trinidad. During Oligocene-middle Miocene arrival from the west and dextral-oblique arc-continent collision of Caribbean plate with the margin, the Northern superterrane strata have been translated east-southeast and imbricated with strata of the Southern superterrane, producing strong foredeep subsidence in the Maturin-early Southern basin. Coeval strike slip faults such as Coche-North Coast may have taken up some of the strike-slip component of the oblique relative motion. Since the end of middle Miocene, the southeast Caribbean plate boundary zone has been dominated by east-west simple shear and relatively minor north-south shortening and extension adjacent to faults. A 3-stage model involving variable strain partitioning describes the tectonic and basin history of Eastern Venezuela and Trinidad for the last 12Ma. The various stages of development have produced exploration settings of different aspect across the greater Trinidad region.

Abstract We present a series of 14 updated tectonic reconstructions for the Gulf of Mexico and Caribbean region since the Jurassic, giving due attention to plate kinematic and palinspastic accuracy. Primary elements of the model are A re-evaluation of the Mesozoic break-up of Pangea, to better define the Proto-Caribbean passive margin elements, the geology and kinematics of the Mexican and Colombian intra-arc basins, and the nature of the early Great Caribbean Arc; Pre-Albian circum-Caribbean rock assemblages are reconstructed into a primitive, west-facing, Mexico-Antilles-Ecuador arc (initial roots of Great Caribbean arc) during the early separation of North and South America; The subduction zone responsible for Caribbean Cretaceous HP/LT metamorphic assemblages was initiated during an Aptian subduction polarity reversal of the early Great arc; the reversal was triggered by a strong westward acceleration of the Americas relative to the mantle which threw the original arc into compression (Pindell et al. , in press); The same acceleration led to the Aptian-Albian onset of back-arc closure and “Sevier” orogenesis in Mexico, the western USA, and the northern Andes, making this a nearly hemispheric event which must have had an equally regional driver; Once the Great Caribbean arc became east-facing after the polarity reversal, continued westward drift of the Americas, relative to the mantle, caused subduction of proto-Caribbean lithosphere (which belonged to the American plates) beneath the Pacific-derived Caribbean lithosphere, and further developed the Great arc; Jurassic-Lower Cretaceous, “Pacific-derived,” Caribbean ophiolite bodies were probably dragged and stretched (arc-parallel) southeastward during the Late Jurassic to Early Cretaceous along an (Aleutian-type) arc spanning the widening gap between Mexico and Ecuador, having originated from subduction accretion complexes in western Mexico; A Kula-Farallon ridge segment is proposed to have generated at least part of the western Caribbean Plate in Aptian-Albian time, as part of the plate reorganisation associated with the polarity reversal; B” plateau basalts may relate to excessive Kula-Farallon ridge eruptions or to now unknown hotspots east of that ridge, but not to the Galapagos hotspot; A two-stage model for Maastrichtian-early Eocene intra-arc spreading is developed for Yucatán Basin; The opening mechanism of the Grenada intra-arc basin remains elusive, but a north-south component of extension is required to understand arc accretion history in western Venezuela; Paleocene and younger underthrusting of Proto-Caribbean crust beneath the northern South American margin pre-dates the arrival from the west of the Caribbean Plate along the margin; and Recognition of a late middle Miocene change in the Caribbean-North American azimuth from east to east-northeast, and the Caribbean-South American azimuth from east-southeast to east, resulted in wholesale changes in tectonic development in both the northeastern and southeastern Caribbean Plate boundary zones.

Abstract Salt along a passive margin facilitates and accommodates gravitational failure of the margin in several key ways. First, it serves as the basal detachment for a linked system of updip extension and downdip contraction that develops due to a combination of gravity gliding and gravity spreading of the sediment carapace. Second, proximal subsidence into salt and distal inflation of salt reduces the bathymetric slope and the associated gravity potential. Third, preexisting salt diapirs and massifs accommodate basinward translation of the overburden by lateral squeezing and the consequent extrusion of allochthonous salt. Fourth, allochthonous canopies can serve as additional detachment levels for gravitational failure. Deep water environments are where most of the shortening occurs, which is manifested as salt-cored folds, reverse faults, squeezed diapirs, inflated massifs, and extrusion of allochthonous salt. Extensional and strike-slip faults and associated salt deformation are also present, as are loading-induced features such as turtle structures and passive diapirs.

Abstract Recent deepwater current observations in the Gulf of Mexico suggest this environment is more energetic than previously observed. Data and modeling results suggest that the Gulf of Mexico behaves as a two-layer system. Coupling of waters above 1,000 m to waters below is still unresolved and remains a topic of further research. The upper layer circulation is dominated by the Loop Current (LC), Loop Current rings (LCR), and smaller scale eddies. Recent data reveal a rich field of eddies of 30–150 km diameters that influence the LCR and shelf-edge currents. The lower layer circulation is less understood. Currents of ~30 cm/s vertically unchanged below 1,000 m, but showing near-bottom intensification interpreted as topographic Rossby waves (TRW) are reported. These waves have 20–30 day periods, wavelengths of 150–250 km, and propagate westward at about 9 km/day. Recent current measurements at 2,000 m reveal even stronger speeds (~90 cm/s) 11 m above the bottom and a small vertical shear below 1,000 m typical of TRW with periods of ~10 days and wavelengths of 70 km. In this lower layer, models show the presence of deep cyclone-anticyclone pairs that move westward and interact with the bottom topography, creating intense bottom currents. Direct observations of large furrows, active at present, suggest strong (~100 cm/s) near-bottom currents. The role of steep slopes in the generation of large amplitude TRW’s is at present unknown. It is also unknown if the observed strong ocean currents are responsible for the large furrows at the sea floor.

Abstract The Rio Muni basin underlies the continental shelf of the west African republic of Equatorial Guinea, located between Gabon and Cameroon. The basin is situated above a section dominated by a northeast-southwest trending oceanic fracture zone and its continental extension. This fracture zone constitutes the boundary between the Equatorial Atlantic margin and the West African salt basin. Despite its location between the prolific hydrocarbon provinces of the Niger delta to the north and the Gabon coastal basin to the south, the Rio Muni basin has been overlooked by the industry for much of the last decade. Previous wells have proved a viable source rock, but no accumulations. Triton Energy licensed Blocks F & G in 1997 and drilled the Ceiba 1 discovery well in 1999, proving a new hydrocarbon system in the deep water, Late Cretaceous post rift sequence. Deformation by Santonian-Coniacian transpression caused uplift of the shelfal area and deposition of a thick, slope fan sequence. Contemporaneous salt deformation of rafted deposits and the development of a base of slope compressional belt are also evident. The resultant turbidite sequences form the reservoirs in the Ceiba discovery, which has been tested at 12,400 BOPD. Both Late Cretaceous and Tertiary turbidite reservoirs form exploration targets in the basin; these may be charged by a deep water source kitchen from which earlier, shelfal wells were shadowed.

Abstract Deep water structures at the basinward edge of African salt basins display very different geometries, some of which are directly comparable to the deep water Mississippi Fan and Perdido fold belts of the northern Gulf of Mexico. To conduct a comparative structural analysis, regional reflection seismic transects were constructed across the continental margins of Morocco, Equatorial Guinea, Gabon and Angola. All the salt-cored deep-water fold belts are driven by gravity, where updip extension is accommodated by downdip compression along a basin-wide salt detachment. Differences in the end result are attributed to several factors: (1) basins containing syn-rift salt compared to post-rift age salt basin settings generally provide a less efficient basin-wide detachment; (2) narrow and steep continental margins tend to enhance the compressional structures at the toe of the slope; (3) sharp, fault-bounded termination of the original basinward depositional limit of the salt may result in the lack of a foldbelt, regardless of the tectonic position of the salt. Whereas the Mississippi Fan fold belt is a fairly close structural analog to the Tafelney foldbelt offshore Morocco, the Perdido fold belt appears to be fairly unique and is not analogous to any fold belts in African salt basins. Conversely, from a northern Gulf of Mexico perspective, some deep water toe-thrust zones in West African salt basins may be regarded as quite unusual. Therefore salt-related exploration experience gained in the Gulf of Mexico region should be applied to West African salt basins with some caution.

Abstract The Agadir basin is situated off the Moroccan Atlantic coast and the Canary Islands. It comprises some 80,000 sq km of shelf and deep water acreage, and has been explored by 16 wells, all drilled on the shelf margin. The deep water basin remains undrilled at present. In 1998, Shell acquired 2,000 km of 2D seismic in the Agadir deep water basin, where previous exploration had revealed the presence of a mobile salt substratum in an area characterised by the presence of a world-class source rock (the Albian -Turonian Tarfaya Shale). On the Jurassic carbonate and Cretaceous clastic shelf, significant oil shows had been discovered during the seventies. Key results of the 1998 to 2000 Agadir Basin exploration are: The basin is highly structured, due to interaction of the Atlas compression with passive margin extension and halokinesis. This structuring creates a large number of potential traps. An Atlas-sourced fluvial system delivers Tertiary turbidites to the basin. Late Cretaceous and Palaeocene sandstones appear to be derived from the Moroccan Meseta. A Jurassic to Cretaceous delivery system from a more southerly source is expected to shed older turbidites into the Agadir basin. Erosional scours originating on the platform confirm that the Cretaceous shelf sands have been transported into the basin. Reservoir quality is a possible concern in an area where carbonate rocks abound in the source area. The main objective in the northern part of the Agadir basin is a Late Cretaceous to Paleogene reservoir play, which ties back to shelf and fluvial sandstones outcropping onshore in the Souss valley and predates the formation of the High Atlas range. Secondary objectives occur in the Neogene and in the Lower Cretaceous to Jurassic intervals. Geochemical modelling supported by the shows in platform wells and the abundance of oil slicks suggests that an active oil charge system is working in the basin. The world-class Tarfaya Shale is likely to be mature over large areas. Older source rocks are likely to further contribute to oil (and gas) charge. They comprise Oxfordian and Liassic shales, but also more speculative Westphalian coals and Silurian shales. Halokinesis is active over the entire area, but increasing in intensity and becoming progressively younger towards the northern part of the Agadir permit, where compressional activity has focused. Locally therefore trap integrity and/or charge timing may form an issue for truncation plays against piercing salt domes. Other play types in the Agadir basin consist of anticlinal closures over deep-seated salt swells, fault-related structures and stratigraphic traps.

Abstract Exploration success in the first two decades of deep water exploration has been highly focused on a particular basin type: Atlantic rift margin basins draped by thick deep water clastic strata, deposited downdip of large Tertiary drainage systems and above a mobile substrate of shale or salt. Most are downdip extensions of working petroleum systems on the adjacent shelf and onshore. Reasons for the preponderance of discovery volume to date in this basin type include: 1) a very high density of structural and stratigraphic/structural leads and prospects; 2) the ready availability of high quality reservoir in deep water channels and fans; and, 3) focused maturation of oil-prone source rocks caused by the Tertiary depocenters. The source rocks are varied and have been found in synrift, post-rift and deltaic settings. Trap types have included channels over deep-seated salt-or-shale structural highs, flanks and faulted flanks of salt or shale minibasins, and submarine fans draped over underlying structural highs. Exploration in plays in the upper slope portions of some of these basins is beginning to show signs of maturing, as new play development continues to move outboard and deeper. In the latter part of the last decade exploration plays have been made in the distal-most structured portions of some of these basins. Where then might the next prolific frontier basins and/or plays in the deep water theatre be found? Many ideas that are being pursued in our industry, or are still on the drawing boards, include: Moving still farther downdip of these focus basins into the largely unstructured basin floor fans that lie on the toe of slope and abyssal plain. Although analogs exist for successful traps in this setting given at least low angle structural inclination, clear difficulties include the occurrence of thermal maturity and the inferred low density of traps. Moving deeper within these focus basins, especially to non-amplitude supported and/or subsalt objectives. Moving laterally from the mobile substrate basins into less structured provinces nearby, that still have sufficient sedimentary section to provide reservoir and mature source rocks. Exploring other, similar mobile substrate basins. Exploring basins with other structural origins, for example transform margins, or fold and thrust belts in active margin settings. Exploring non-turbidite (e.g. , carbonate) reservoirs in deep water settings. These and other more novel play concepts will be required to continue the rapid growth seen in the past two decades of the deep water play.

Abstract The New Zealand Exclusive Economic Zone (EEZ) contains at least six large deep water basins: the deep water Taranaki basin, the Raukumara basin, the Pegasus basin, the Head of the Bounty trough, the Great South basin and the Solander trough. Structural styles vary from rift basins through strike-slip dominated basins to major accretionary prisms. Source rocks encountered include coal measures, black marine shales, and lacustrine facies. Sedimentary thicknesses, heat flow studies, and basin modeling supported by production and numerous seeps in the shelf and onshore, suggest that these basins may be prolific hydrocarbon producers in the future. Recent developments suggest that the most promising of these basins is the deep water Taranaki basin, outboard of New Zealand’s only producing basin to date. The petroleum histories of most of these basins began with the Late Cretaceous break-up of Gondwana and the formation of rift basins. In onshore New Zealand and on the continental shelf, many of the source rocks for the productive Taranaki basin were deposited at this time. The earliest sediments to be deposited were commonly fluvial, lacustrine, deltaic and nearshore facies followed by an increasing marine influence as the region foundered through the Paleogene. The Neogene saw the formation of the present plate boundary and the emergence of New Zealand in response to plate collision. Many of the more spectacular structures in the New Zealand sedimentary basins were formed during the Neogene. Meanwhile, the deep water basins away from the plate margin continued a quieter development. Some inversion occurred, but not to the extent of the nearshore and onshore regions. This relatively gentle structural evolution increased the likelihood of discovering large hydrocarbon fields in unbreached structural traps.