In 1972, based on detailed field mapping, Atlantic Richfield Company ("ARCO") ranked the Upper Palaeozoic-Mesozoic Jameson Land Basin as having the highest potential for hydrocarbon accumulations in East Greenland. For a five year period, ARCO was the operator of an approximately 10,000 km2 area over the central part of the basin, ending in 1990. During this time, ARCO accumulated a wealth of data across the entire basin through a focused and diligent exploration campaign, which culminated in the identification of a multiple play system with very attractive estimated cumulative reserves for both oil and gas. ARCO's principal focus at that time was the Upper Permian shallow marine platform carbonates and reefal build-ups of the Wegener Halvø Formation, which through seismic mapping appear to provide significant trap potential. Several drillable large closures (traps) have been identified that are surrounded and draped by oil-prone shales of the Upper Permian Ravnefjeld Formation, which provides a very favourable juxtaposition of both source and seal.
It should be noted that ARCO was a true "oil finder", particularly, in more remote frontier areas, as exemplified by their exploration record and success. In 1957, ARCO was the first company to discover oil in Alaska. In 1968, ARCO, with Exxon, discovered the largest oil field in North America – the Prudhoe Bay Oil Field, Prudhoe Bay, Alaska. In the 1980's, ARCO's international arm made the first commercial natural gas discovery in offshore China.
So why did ARCO relinquish the Jameson Land asset in 1990 after almost 20 years of considerable interest and spend? We believe this could be down to several noticeable events in ARCO's history that may be relevant to the relinquishment of the block:
- The oil price collapse in 1985 and early 1986 resulted in many of the major oil companies in the United States to shift much of their exploration and development efforts to targets outside of the United States.
- By the mid-1980's, under the chairmanship of Lodwrick M. Cook, a yet more radical strategy was devised to ensure profitability and a lessening dependence on oil: to divest ARCO of all marginally profitable enterprises and to drastically cut costs across the board. As a result, between 1985 and 1987, ARCO reduced its workforce by approximately 12,000 employees.
- Net income reached a record high in 1989 of $1.95 billion; however, within two years profits were almost one-third that, at $709 million. The primary culprits were lower gas prices and an economic recession. To cut costs, ARCO eliminated 2,100 jobs in 1991.
- As ARCO's reserves declined, it pursued several strategies to maintain its revenues over the long term. One was the purchase of proven reserves from other companies. In 1988 it purchased oil and gas properties in California from Tenneco, and in 1990 purchased properties from TXO Production in Oklahoma and from Oryx in California. Three years later, ARCO joined with Phillips Petroleum to lease 130,000 acres near Alaska's Cook Inlet.
- The company also stepped up its efforts to bring foreign reserves into production. ARCO had discovered an 85-billion-cubic-meter gas field in 1982 off the southeast coast of China, but had been unable to exploit the find. As a Chinese joint venture, the operation had to meet the Chinese regulation that it be a self-sustaining project, in effect, requiring the gas to be exported for hard currency. Finally, the operation was made feasible in 1992 when ARCO completed a deal to pipe the gas to Hong Kong for electrical power generation. ARCO held a 34.3 percent interest in the venture and managed the construction of the 480-mile Yacheng pipeline.
- ARCO's Yacheng pipeline was completed in 1996 for $1.13 billion. As the gas from that field finally began to flow, ARCO reached an agreement with the Algerian state oil company, Sonatrach, to increase production from the Rhourde El Baguel Field, the country's second largest oil field. Estimated to have had some three billion barrels of oil at its discovery in 1962, the field was slowing in production by the mid-1990's. ARCO's experience with miscible gas technology was expected to enhance the oil recovery from the field.
Despite numerous field mapping excursions, sedimentological and geochemical outcrop analyses, acquisition of seismic, gravity and magnetic data by ARCO and partners, in-depth field-based work by the Grønlands Geologiske Undersøgelse ("Greenland Geological Survey" or "GGU") and subsequently by the Geological Survey of Denmark and Greenland ("GEUS"), the Jameson Land Basin can still be regarded as largely underexplored in terms of thoroughly evaluating its exploration potential from a multitude of attractive plays identified by these studies; with no exploration wells drilled to date. As demonstrated by these studies, including more recent work published by GEUS and several academic institutions, the basin appears to contain all the key essential play elements – source, reservoir, seal, and trap – for the significant generation and accumulation of commercially viable hydrocarbons. The culmination of this work, together with the findings of an in-depth study by Greenland Gas and Oil (GGO), has resulted in the identification of several major source and reservoir intervals, and a number of potential drillable targets throughout the 17 km total stratigraphic thickness of the basin.
Essential Play Elements
Does the Jameson Land Basin have the capacity to generate hydrocarbons?
ARCO Research devoted considerable time and effort to type-sourcing the bitumen and asphalt shows from across the basin, including cores, to analysed potential source rock outcrop samples. Isotope and biomarker data for these shows in all cases can be genetically linked to the Upper Jurassic Hareelv Formation.
Despite their considerable geographic separation by Tertiary oceanic crustal spreading, it has been demonstrated using biomarker patterns and isotope curves that the Upper Jurassic oils in Jameson Land are very similar to the oils being produced in the Haltenbanken area offshore mid-Norway. The biomarker fingerprints from Jameson Land and Haltenbanken are very similar, with several prominent peaks clearly matching each other, with the chromatogram from each of these areas being virtually identical. This is also true for the isotopic type curves produced for each set of oils. The biomarker and isotope data together provide compelling evidence for a close genetic link between the Upper Jurassic organic-rich shales of Jameson Land and mid-Norway. This is not so surprising, as a pre-tectonic (pre-rift) fit of both conjugate margins, by removing the Tertiary oceanic crust in between, clearly shows their spatial relationship, with these areas adjacent to one another and, in turn, explains their strong genetic association (Figures 2 and 3). If thermal maturity conditions were favourable in the Jameson Land Basin for the maturation of Upper Jurassic organic-rich shales (and younger source intervals with similar source facies characteristics), the potential to generate substantial volumes of oil should be no different to its counterpart in mid-Norway where major discoveries for both oil and gas have been made.
Source Rock Maturation and Charge
Estimated depths of burial of the Upper Permian Ravnefjeld Formation would favour the generation of oil and/or gas prior to the significant Tertiary uplift and erosion observed across the basin. Due to the subsidence and uplift history of the basin, ARCO regarded the thermal maturity of the basin's major source rock intervals as a significant geological risk, even for the Permian. Although ARCO recognised that the Jurassic source samples analysed are very high in organic carbon content and also high in soluble organic matter content, several of their reports concluded that these source rocks were too shallow in terms of depth of burial to generate reasonable quantities of oil and/or gas. With more recent understanding of the magnitude of tectonic uplift and erosion from maturity and apatite fission track data, it is becoming clear that the basin experienced significant uplift and erosion in the order of ~ 1 km and 2-3 km, respectively. With increasing tectonic uplift to the north of the basin, this episode of uplift and denudation resulted in destruction of hydrocarbon accumulations on the flanks/highs of the basin. This relatively late stage – Tertiary – event now supports the concept that the potentially prolific oil-prone source rocks found within the Lower and Upper Jurassic successions, and possibly within the Triassic, in the central part of the basin, were originally at a depth of burial for the generation of substantial quantities of hydrocarbons.
Basin modeling results by Mathiesen et al. (1995) demonstrate that the Upper Permian and older successions are post mature in most of the Jameson Land Basin, with the exception of a narrow zone close to the northwestern margin of the basin. Due to greater subsidence in the central part of the basin, hydrocarbon generation had already reached the main oil stage during the Cretaceous. The hydrocarbons generated were either thermally degraded or may have migrated into shallow stratigraphic traps in the overlying sedimentary section during the early Tertiary. This may explain remnant oil in the Upper Permian carbonates, with subsequent flushing by hyper saline fluids displacing/destroying hydrocarbons on the flanks of basin, resulting in the oil possibly being preserved downdip. In contrast, Mathiesen et al. (1995) show that the Lower Jurassic Kap Stewart Formation has hydrocarbon and preservation potential in an extensive area in southern and central Jameson Land. The source rock was immature throughout the area at the end of the Cretaceous, and reached main oil generation during the early Tertiary. In the deeper parts of the basin, the Upper Jurassic Hareelv Formation may have also reached the oil window. This needs to be tested further with more in-depth basin modeling for all potential source intervals, and for different heat flow and uplift scenarios.
Are good quality reservoirs present in the Jameson Land Basin?
The Central and Southern Areas of the basin appear to provide the best preserved total sedimentary section from the Devonian to the Lower Cretaceous providing multiple play intervals.
The key reservoir intervals being:
- The Upper Permian shallow marine carbonate platform and reefal build-ups of the Wegener Halvø Formation;
- The fan delta and alluvial fan sands of the 'Basal Triassic Sandstone' of the Early Triassic Wordie Creek;
- Aeolian and alluvial-fluvial sandstones of the Late Triassic Gipsdalen and Fleming Fjord Formations.
- Lacustrine and fluvial-deltaic-marginal marine sandstones of the Rhaetian–Sinemurian Kap Stewart Group;
- Marine sandstones of the Pliensbachian–Aalenian Neill Klinter Group; Shallow marine-deltaic sandstones of the Upper Bajocian – Callovian Pelion Member of the Vardekloft Formation and the Upper Callovian-Middle Oxfordian Olympen Formation;
- The deep water turbidite sands of the Upper Oxfordian – Kimmeridgian Hareelv Formation.
Upper Permian shallow marine carbonate platform and reefal build-ups of the Wegener Halvø Formation
As mentioned above, the Upper Permian platform carbonates and reefal build-ups of the Wegener Halvø Formation were identified and mapped by ARCO as potentially very large stratigraphic closures; however, more recent work from field-based studies and global analogues suggest that the actual reservoir thickness of such carbonate bodies is highly variable and linked to the facies which are present at a particular location. Such lateral facies variations within the Upper Permian carbonate sequence for locations on both sides of the basin have been documented. There is also the issue of reservoir quality, with ARCO concluding in one of their final summary reports that the Permian carbonate reservoir data is inconclusive and adding that, in outcrop, reservoir characteristics are not too encouraging. To substantially improve reservoir quality they acknowledged that the following conditions would have to apply: 1) lesser depths of burial; 2) secondary porosity development such as karsting, which is possibly evident on several seismic lines; 3) the absence of late stage cement due to early migration of oil or separation from tectonic conduits for mineralising fluids; and 4) dolomitisation. Based on reservoir extent and characteristics, the potential Mesozoic clastic dominated sections analysed on the flanks of the basin and inferred from seismic to continue into the centre of the basin, may provide a more attractive set of play intervals. Both stratigraphic and structural closures may provide trapping mechanisms, with extensional faults largely defined in the south of the basin providing the possibility of (potentially lower risk) fault controlled prospects.
'Basal Triassic Sandstone' of the Early Triassic Wordie Creek Play
This sandstone unit is exposed along the western margin of Jameson Land in Triaselv and also on the eastern margin on the Wegener Peninsula. In outcrop, these conglomeratic, coarse-grained, arkosic sandstones have been observed to have channel geometries up to 35m deep and several hundreds of meters wide. In the subsurface, ARCO identified one such channel on seismic, with a width of approximately 2 km. A limited database exists for the reservoir properties of this interval, with the samples collected from fan delta and alluvial fan facies. However, based on what has been analysed using eight samples, the mean porosity of this sandstone unit is reasonably good at 12.5% (with an 8 to 16% range), with the potential to exhibit better reservoir attributes in the deeper parts of the basin where the sands would most likely become more texturally mature.
Late Triassic Gipsdalen and Fleming Fjord Plays
The data and findings in a recent paper published by Andrews et al. (2014) strongly demonstrates that the Gråklint Beds of Late Triassic (Mid-Carnian) age represents a significant oil- and gas-prone source rock in the Jameson Land Basin, coupled with alluvial-fluvial and aeolian sandstones of reservoir quality and sealing lacustrine mudstones. Our own extensive in-house review has also identified this interval (Gipsdalen and Fleming Fjord formations) as a viable potential play that warrants further investigation. This includes the identification of this play concept through the seismic interpretational work we have undertaken (using newly reprocessed seismic data), with several major potential stratigraphic trapping mechanisms identified (e.g. channel systems/incised valleys) at optimum depths for charge, trapping, preservation and drilling. Through the seismic, a package of high amplitude reflectors within the middle of the Triassic 'wedge' section may represent the organically-rich black to dark grey predominantly lacustrine mudstones of the Gråklint Beds, which contain total organic carbon (TOC) values of up to 6.3%, with very good to excellent Type II (oil and gas) source potential. Andrews et al. (2014) conclude that the Gråklint Beds were deposited in a deep lake setting with intermittent marine influence.
Lower Jurassic Sandstones of the Kap Stewart (and Neill Klinter) Play
Lower Jurassic (Hettangian-Sinemurian) lacustrine and fluvial-deltaic-marginal marine sequence sandstone reservoirs of the Kap Stewart Formation also provide an attractive target for exploration. Based on detailed petrographic studies by the University of Tulsa, it has been proposed that substantially different environments of deposition and provenance account for the lithological compositional variation in the southern and northern parts of the basin. Sediments in southern Jameson Land are inferred to represent alluvial fan and fluvial deposits derived from a southerly, "granitic" or high rank metamorphic/igneous terrane; whereas, the northern Kap Stewart sediments were deposited in a shallow marine- to transitional setting derived from older sediments to the north of Kong Oscars Fjord. As a result of these facies differences, the northern marine-coastal sands exhibit higher porosity characteristics with a mean value of 16% versus 13% for the southern alluvial-fluvial sandstones. A Lower Jurassic shelf to basin transition has been interpreted on seismic, in the northern half of the basin, where shelf margin sand accumulations (expressed by acoustically characterless zone) on the shelf edge possibly derived from a northerly source terrane and winnowed by shelf edge currents may represent an area superior reservoir quality could exist here than previously measured in outcrop. Downdip of the interpreted shelf edge sands are continuous, thinly-bedded reflectors that have been interpreted as marine shales. If organic-rich, with oil-prone kerogen, these basinal shales could charge the Lower Jurassic shelf margin sands by simple lateral updip migration. High amplitude, continuous, seismic reflectors in the basal Neill Klinter section directly above the Kap Stewart shelf margin sands may form an adequate lateral seal for such stratigraphic traps. During Pliensbachian time, a regional transgression occurred which resulted in the deposition of shallow marine sandstones of the Neill Klinter Formation. Tidal sands and shoreface sands may provide additional reservoir targets.
Middle Jurassic Pelion Member of the Vardekloft and the Olympen Plays
Middle Jurassic shallow marine-deltaic sequence sandstone reservoirs of the Pelion Member (Upper Bajocian-Middle Callovian) of the Vardekloft Formation and the Olympen Formation (Upper Callovian-Middle Oxfordian) provide attractive exploration targets, but may be limited to the central southern half of the basin, with the Vardekloft Formation exposed at the surface over most of northern Jameson Land. The Pelion Member reaches a maximum thickness of 550m and often contains greater than 70% quartz. Twenty-five sandstone samples from north-central and southern Jameson Land were examined by the University of Tulsa and fifteen had 10-30% porosity, with an average porosity of 12.2% from all the samples. Excluding those samples with more than 18% carbonate cement, the porosity averages 16.3%. It should be noted that the Pelion Formation sandstone is often used as an analogue for the Brent Group in the Viking Graben of the North Sea and correlative Garn Group of the Norwegian Shelf. In the basal Vardekloft Formation, porous sandstones of the Pelion Member unconformably overlie, and erode into, potential source rocks of the Sortehat Member. This direct contact of source and reservoir may provide ideal conditions for hydrocarbon migration and charge. It is envisaged that the trapping mechanisms will be dominantly stratigraphic, with the silty shales of the Fossilbjerget Formation providing an adequate top seal.
Upper Jurassic Massive Sandstones of the Hareelv Play
Upper Jurassic (Upper Oxfordian-Kimmeridgian) massive deep water shelf/basin turbidite sandstones of the Hareelv Formation may provide a viable option in southern Jameson Land, where unbreached stratigraphic traps may occur, together with the possibility of tilted fault block-related closures. The massive, non-graded sandstone units indicate that sand was emplaced by sediment gravity flows, probably high-density turbidity currents. The thickness of the unit ranges from approximately 200m along the eastern outcrop margin of the basin to around 500m in the west of the basin. Age equivalent formations on Traill Island are 500m thick and 600-700m thick on Wollaston Forland. The massive sandstone bodies of the Hareelv Formation are up to 50m thick and may exceed several hundred meters in width, and can be traced over 5 km. It should be noted that these turbidite sands of the Hareelv Formation are often used as analogues, for example, the Magnus oil field in the North Sea. As expected from their depositional environment, their geometries are irregular and the sandstone bodies are separated from each other by organic-rich black shale. The sandstones tend to be clean and quartz-rich, with a mean porosity for sixteen outcrop samples of 17%, ranging from 1.6-23.9%. It has been proposed (e.g., Surlyk, 1987; and more recent publications) that the Upper Jurassic Hareelv Formation has substantial potential to contain stratigraphic traps. It is clear that these thick irregular and discontinuous, yet closely spaced sandstones with excellent reservoir properties are encased in black, organic-rich shale, with excellent source rock potential. Geochemical analyses of the Hareelv Formation shales have demonstrated the quality of this source facies (TOC values ranging from 6-12% TOC) and its close genetic similarities to the age equivalent Kimmeridge Clay Formation, which is such a prolific source rock unit in the North Sea and other parts of northwest Europe. The attractiveness of this deep water turbidite fan play is that the sands are entirely surrounded by an excellent source rock allowing direct "in-situ" charging of the reservoir, with migration efficiencies in the order of 25-35%, similar to the North Sea. It should be noted, that it is likely that this play only exists in the southernmost part of the basin where the Hareelv Formation is buried to sufficient depths to be within the oil window.
It should be noted that the Jurassic clastic plays are the principal producing reservoir intervals in the North Sea and offshore Norway. The East Greenland margin, including the Jameson Land Basin, exhibits a strong genetic relationship with these hydrocarbon provinces, both in terms of tectonic and depositional history, with very similar source, reservoir and trapping styles recognised throughout the Jurassic in each basin setting. These similarities are highlighted by the large number of papers published that use field examples from the Jameson Land Basin as analogues to explain either source, reservoir and/or stratigraphic trapping styles in North Sea and offshore Norway producing fields. With adequate depth of burial, and preservation, we regard the Central and Southern Areas of the Jameson Land Basin as having high to moderate hydrocarbon potential, with very similar stratigraphic trapping mechanisms to those already producing in the North Sea.
Are these reservoirs sealed by adequate cap rocks?
All potential traps identified so far in the Jameson Land Basin are stratigraphic and, hence, require, lateral and vertical sealing by age equivalent and/or older overlying sediments, which are inferred to be shales/mudstones. The shales themselves act as the source for hydrocarbons, reducing the risk of long distance migration and seal breaching.
Adequate sealing for Upper Devonian and Carboniferous fluvial and aeolian sandstone reservoirs may be a serious problem for this play type due to the prevailing environments and coarse clastics derived from the margins of the basin and, as such, we currently do not regard them as a major reservoir intervals.
The Upper Permian Ravnefjeld Formation drapes the shallow marine carbonate platform and reefal build-ups of the Upper Permian Wegener Halvø Formation and constitutes the vertical seal for migrating hydrocarbons. Triassic flood plain and lacustrine shales of the Gipsdalen Formation may provide adequate lateral seals for the fan delta and alluvial fan sands of the 'Basal Triassic Sandstone' (Pingodal Formation) of the Early Triassic Wordie Creek Formation, and Late Triassic sandstones of the Gipsdalen and Fleming Fjord Formations. Equally, lacustrine and fluvial-deltaic- marginal marine sandstones of the Rhaetian–Sinemurian Kap Stewart Group may be stratigraphically trapped by laterally sealing lacustrine and delta plain shales of the same formation. High amplitude, continuous, seismic reflectors in the basal Pliensbachian–Aalenian Neill Klinter section directly above the Lower Jurassic Kap Stewart Formation may also form an adequate lateral seal. Middle Jurassic shallow marine-deltaic sequence sandstone reservoirs of the Pelion Member (Upper Bajocian-Middle Callovian) of the Vardekloft Formation and the Olympen Formation (Upper Callovian-Middle Oxfordian) provide attractive stratigraphic targets, with the silty shales of the Fossilbjerget Formation possibly providing an adequate top seal. The deep water turbidite sands of the Upper Oxfordian – Kimmeridgian Hareelv Formation could be completely enclosed by very effective lateral seals.
Does the Jameson Land Basin have a multiple play system capable of producing significant hydrocarbons?
The Jameson Land Basin is a multiple play system, with all of these individual plays spatially and temporally associated with good to excellent organic-rich shales that can act as major oil-prone source rocks, with the shales themselves draping the Permian carbonates or completely enclosing the Mesozoic sandstone reservoir as very effective seals. This provides the best juxtaposition of source, reservoir and seal, and significantly reduces risk and uncertainty in terms of migration pathways and timing, with all the plays cited above essentially "self-charging". Of these plays, we regard the primary exploration targets in the Jameson Land Basin to be: (1) the Middle Jurassic sandstones of the Pelion Member of the Vardekloft Formation and the Olympen Formation; and (2) Lower Jurassic sandstones of the Kap Stewart and possibly Neill Klinter Formations. Also of interest are the deep water turbidite sands of the Upper Jurassic Hareelv Formation; however, from seismic mapping and outcrop patterns, it is clear that this play interval is restricted to the southernmost part of the basin, where there is a lack of seismic data. The Late Triassic may also provide a viable attractive clastic play, with aeolian and alluvial-fluvial sandstones provided by the Gipsdalen and Fleming Fjord Formations, sourced by the organically-rich black to dark grey lacustrine mudstones of the Gråklint Beds.
The following provides a summary of the key points as to why we regard the central and southern areas of the Jameson Land Basin as having the greatest potential for hydrocarbon discoveries and lower risk factors in terms of its essential play elements.
(1) From basic principles, it is highly likely that the thickest and highest quality oil-prone, organic-rich source rocks will have been deposited in the main depocentres – Central and Southern Areas – of the basin system, away from areas polluted/contaminated by the influx of coarse clastics derived from sediment input points along the margins of the basin. The key source rock intervals being organic-rich shale units of the Upper Permian Ravnefjeld Formation, the Late Triassic Graklint Beds, the Middle Jurassic Sortehat Formation, lacustrine shales of the uppermost Triassic – lowermost Jurassic Kap Stewart Group, and the Upper Jurassic Hareelv Formation.
(2) The Central and Southern Areas of the Jameson Land Basin contain the maximum preserved sediment thickness in the basin, and tectonic uplift and denudation modelling demonstrates that these areas were the main depocentres prior to significant Tertiary uplift and erosion of 2-3 km across the basin. Basin modelling shows that several key potential source rock intervals within the Paleozoic and Mesozoic section could have attained depths of burial that will have placed them in the oil window prior to the Tertiary uplift event.
(3) Tertiary tectonic uplift was greater in the north of the basin and along its margins, resulting in significant erosion of the sedimentary section in these areas and the destruction of hydrocarbon accumulations on the flanks/highs. This may explain the remnant oil in the Upper Permian carbonates of the Wegener Halvø Formation on the flanks of basin, where subsequent flushing by hypersaline fluids has displaced/destroyed hydrocarbons; with greater chance of oil being preserved downdip in the Central and Southern Areas.
(4) The Central and Southern Areas of the basin provide the best preserved total sedimentary section from the Devonian to the Lower Cretaceous providing multiple play intervals. The key reservoir intervals being: the Upper Permian shallow marine carbonate platform and reefal build-ups of the Wegener Halvø Formation; the fan delta and alluvial fan sands of the 'Basal Triassic Sandstone' of the Early Triassic Wordie Creek; alluvial-fluvial and aeolian sandstones of the Gipsdalen and Fleming Fjord formations; lacustrine and fluvial-deltaic-marginal marine sandstones of the Rhaetian– Sinemurian Kap Stewart Group; marine sandstones of the Pliensbachian–Aalenian Neill Klinter Group; shallow marine-deltaic sandstones of the Upper Bajocian – Callovian Pelion Member of the Vardekloft Formation and the Upper Callovian-Middle Oxfordian Olympen Formation; and the deep water turbidite sands of the Upper Oxfordian – Kimmeridgian Hareelv Formation. A multiple play system, with all of these individual plays spatially and temporally associated with good to excellent organic-rich shales that can act as major oil-prone source rocks, with the shales themselves draping the Permian carbonates or completely enclosing the Mesozoic sandstone reservoir as very effective seals. This provides the best juxtaposition of source, reservoir and seal, and significantly reduces risk and uncertainty in terms of migration pathways and timing, with all the plays cited above essentially "self-charging".
(5) The growth of the Upper Permian reefal build-ups of the Wegener Halvø Formation are less likely to have been affected by clastic input in the marine-dominated central and southern parts of the basin.
(6) Depositional modelling and petrographic studies indicate that the better quality sandstone reservoirs, in particular, for the Jurassic, are likely to be in the main depocentres of the basin – Central and Southern Areas – where the sands are quartz-rich, clean and, thus, more mature than the sediments deposited in close proximity to the margins of the basin by short-headed drainage systems.
(7) A greater number of leads previously identified by ARCO and evaluated during this study occur in the Central and Southern Areas of the basin, together with several potential Triassic and Jurassic clastic leads.
In summary, the Jameson Land Basin contains an exciting multiple play system with the potential to produce significant quantities of oil and gas. All the essential play elements are present and a number of trap structures have already been identified from existing data. The next stage is to "ground- truth" these structures a little further with additional data and then drill a well!