THE GEOLOGY AND EVOLUTION OF THE SCOTT PLATEAU

1978 ◽  
Vol 18 (1) ◽  
pp. 34 ◽  
Author(s):  
H. M. J. Stagg
Keyword(s):  
Seismic Data ◽  
Seismic Reflection ◽  
Structural Evolution ◽  
Source Rocks ◽  
Petroleum Potential ◽  
Reservoir Rocks ◽  
Carbonate Sedimentation ◽  
Sea Bed ◽  
Adjacent Part ◽  
Water Depths

The Scott Plateau and the adjacent Rowley Terrace cover about 130,000 km2 beyond Australia's Northwest Shelf in water depths ranging from 300 m to 3000 m. The regional geology and structural evolution of the area have been interpreted from about 13,000 km of seismic reflection profiles.The Scott Plateau forms a subsided oceanward margin to the Browse Basin. For much of the period from the Carboniferous to the Middle Jurassic, preceding the breakup which formed this part of the continental margin, the Scott Plateau was probably above sea level shedding sediment into the developing Browse Basin. After breakup in the Bathonian to Callovian, the plateau subsided, until by the Late Cretaceous open marine conditions were prevalent over most of the area, with the probable exception of some structurally high areas which may have remained emergent until early in the Tertiary. Carbonate sedimentation commenced in the Santonian and has continued to the present, with major hiatuses in the Paleocene and Oligocene. Analysis of magnetic and seismic data indicates that, over much of the plateau, economic basement of possible Kimberley Block equivalents is probably no more than 3 to 4 km below sea bed. To the south of the Scott Plateau, the Rowley Terrace is underlain by a wedge of at least 6 km of Mesozoic and Tertiary sediments of the northeast- trending Rowley Sub - basin. The Rowley Sub -basin connects with the Beagle Sub-basin to the southwest and probably connects with the Browse Basin to the northeast. It has been largely unaffected by episodes of faulting, except in the southwest where faulting and folding are pronounced. The petroleum potential of the Scott Plateau is not rated highly. The potential hydrocarbon-bearing sediments here are probably no younger than Palaeozoic. These are quite likely to be only 2 to 4 km thick, and any hydrocarbons generated within them would probably have been lost during the protracted period of emergence and erosion that preceded breakup. The hydrocarbon potential appears to be greater in the Rowley Sub-basin, where Triassic to Cretaceous shale and siltstone source rocks, and Triassic to Lower Cretaceous sandstone reservoir rocks are expected to be present. However, the potential of these sequences is downgraded because hydrocarbon shows in exploration wells on the adjacent part of the Northwest Shelf have been only minor, and by the apparent scarcity of suitable traps. Exploitation of any hydrocarbons would be costly owing to the great water depths.

Bight Basin acreage release—new exploration opportunities in a deep water frontier

2009 ◽  
Vol 49 (1) ◽  
pp. 491
Author(s):  
Jennifer Totterdell ◽  
Heike Struckmeyer ◽  
Andrew Stacey
Keyword(s):  
Late Cretaceous ◽  
Seismic Data ◽  
Source Rocks ◽  
High Quality ◽  
Reservoir Rocks ◽  
Potential Source ◽  
Exploration Risk ◽  
Commonwealth Government ◽  
Exploration Drilling ◽  
Water Depths

In 2009, the Commonwealth Government is releasing six large exploration areas in the frontier Bight Basin. The areas lie in the Ceduna Sub-basin, in water depths ranging from 130 to 4,600 m. At present, no permits are held in this part of the basin. Most exploration drilling in the Bight Basin has focussed on the margins of the Ceduna Sub-basin and on the adjacent Duntroon Sub-basin. Gnarlyknots 1A, drilled by Woodside Energy and partners in 2003, is the only well to have attempted to test the thick, prospective Ceduna Sub-basin succession away from the margins of the sub-basin, but did not reach all its target horizons due to weather and ocean conditions. The key to the petroleum prospectivity of the Ceduna Sub-basin is the distribution of the Late Cretaceous marine and deltaic facies. Recent dredging of Late Cenomanian–Turonian organic-rich marine rocks has confirmed the presence of high quality source rocks in the Bight Basin and has significantly reduced exploration risk. These potential source rocks are mature in the central part of the Ceduna Sub-basin and are likely to have generated and expelled hydrocarbons since the Campanian. Excellent reservoir rocks and potential intraformational seals are present in the Late Cretaceous deltaic successions and regional seals could be provided by Late Cretaceous marine shales. Interpretation of seismic data has identified numerous play types in the basin and some structures show amplitude anomalies, providing many exploration targets for explorers.

Petroleum potential of the offshore southern Carnarvon Basin—insights from new Geoscience Australia data

2011 ◽  
Vol 51 (2) ◽  
pp. 746
Author(s):  
Irina Borissova ◽  
Gabriel Nelson
Keyword(s):  
Seismic Data ◽  
Source Rocks ◽  
Magnetic Data ◽  
Long Distance ◽  
Potential Field Data ◽  
Petroleum Potential ◽  
Gravity And Magnetic ◽  
Gravity And Magnetic Data ◽  
Insight Into ◽  
Carnarvon Basin

In 2008–9, under the Offshore Energy Security Program, Geoscience Australia (GA) acquired 650 km of seismic data, more than 3,000 km of gravity and magnetic data, and, dredge samples in the southern Carnarvon Basin. This area comprises the Paleozoic Bernier Platform and southern part of the Mesozoic Exmouth Sub-basin. The new seismic and potential field data provide a new insight into the structure and sediment thickness of the deepwater southernmost part of the Exmouth Sub-basin. Mesozoic depocentres correspond to a linear gravity low, in water depths between 1,000–2,000 m and contain between 2–3 sec (TWT) of sediments. They form a string of en-echelon northeast-southwest oriented depressions bounded by shallow-dipping faults. Seismic data indicates that these depocentres extend south to at least 24°S, where they become more shallow and overprinted by volcanics. Potential plays in this part of the Exmouth Sub-basin may include fluvio-deltaic Triassic sandstone and Lower–Middle Jurassic claystone source rocks sealed by the regional Early Cretaceous Muderong shale. On the adjoining Bernier Platform, minor oil shows in the Silurian and Devonian intervals at Pendock–1a indicate the presence of a Paleozoic petroleum system. Ordovician fluvio-deltaic sandstones sealed by the Silurian age marine shales, Devonian reef complexes and Miocene inversion anticlines are identified as potential plays. Long-distance migration may contribute to the formation of additional plays close to the boundary between the two provinces. With a range of both Mesozoic and Paleozoic plays, this under-explored region may have a significant hydrocarbon potential.

Late Cretaceous – Tertiary sediments offshore central West Greenland: lithostratigraphy, sedimentary evolution, and petroleum potential

1985 ◽  
Vol 22 (7) ◽  
pp. 1001-1019 ◽  
Author(s):  
Flemming Rolle
Keyword(s):  
Upper Cretaceous ◽  
Source Rocks ◽  
Petroleum Potential ◽  
Shallow Marine ◽  
West Greenland ◽  
Reservoir Rocks ◽  
Sedimentary Sequences ◽  
Sedimentary Evolution ◽  
Petroleum Generation ◽  
Exploratory Wells

Five dry exploratory wells were drilled through Upper Cretaceous and Tertiary sediments on the West Greenland shelf in 1976 and 1977. Two of these entered Precambrian basement, two bottomed in Paleocene or Upper Cretaceous basalt, and one in Campanian mudstone. On the basis of samples and logs supplied to the Geological Survey of Greenland the sedimentary sequence has been divided into seven new formations: the Campanian Narssarmiut Formation, consisting of coarse basement wash and black mudstone; the Campanian to Eocene Ikermiut Formation, consisting of marine organic-rich mudstone; the Upper Paleocene to Eocene Hellefisk Formation, comprising shallow-marine to paralic sandstone and mudstone; the Eocene Nukik Formation, consisting of turbiditic sandstone and mudstone; the Eocene to Oligocene Kangâmiut Formation of shelf to shallow-marine clean and argillaceous sandstone; the Oligocene to Neogene Manîtsoq Formation, consisting of coarse paralic to fan delta sandstone; and the Neogene Ataneq Formation, consisting of protected shallow-marine mudstone.The sedimentary evolution of the area fits well with earlier proposed models for the tectonic evolution of the Baffin Bay–Labrador Sea region.Potential petroleum source rocks are present in the Upper Cretaceous to Paleocene mudstone, and, even though they are largely immature in the drilled sections, they are expected to have entered the petroleum generation zone in the deeper parts of the basin. Their potential is mainly for gas, but some oil potential is also present. No reservoir rocks were encountered in the deeper parts of the sedimentary sequences, and the porous sandstones that occur higher in the sequence lack seals.

PETROLEUM POTENTIAL OF THE GREAT SOUTH BASIN, NEW ZEALAND—NEW SEISMIC DATA IMPROVES IMAGING

2007 ◽  
Vol 47 (1) ◽  
pp. 145 ◽  
Author(s):  
C. Uruski ◽  
C. Kennedy ◽  
T. Harrison ◽  
G. Maslen ◽  
R.A. Cook ◽  
...  
Keyword(s):  
New Zealand ◽  
Seismic Data ◽  
Oil And Gas ◽  
Petroleum Industry ◽  
Source Rocks ◽  
Seismic Survey ◽  
Recording Time ◽  
Petroleum Potential ◽  
South Basin ◽  
Time Migration

Much of the Great South Basin is covered by a 30,000 km grid of old seismic data, dating from the 1970s. This early exploration activity resulted in drilling eight wells, one of which, Kawau–1a, was a 461 Bcf gas-condensate discovery. Three other wells had significant oil and gas shows; in particular, Toroa–1 had extensive gas shows and 300 m oil shows. Cuttings are described in the geological logs as dripping with oil. The well was never tested due to engineering difficulties, meaning that much of the bore was accidentally filled with cement while setting casing.In early 2006, Crown Minerals, New Zealand’s petroleum industry regulating body, conducted a new 2D seismic survey in a previously lightly surveyed region across the northern part of the Great South Basin. While previous surveys were generally recorded for five seconds, sometimes six, with up to a 2,500-metre-long cable, the new survey, acquired by CGG Multiwave’s Pacific Titan, employed a 6,000-metre-long streamer and recorded for eight seconds.The dataset was processed to pre-stack time migration (PreSTM) by the GNS Science group using its access to the New Zealand Supercomputer. Increasing the recording time yielded dividends by more fully imaging, for the first time, the nature of rift faulting in the basin. Previous data showed only the tops of many fault blocks. The new data show a system of listric extensional faults, presumably soling out onto a mid-crust detachment. Sedimentary reflectors are observed to seven seconds, implying a thickness of up to 6,000 m of section, probably containing source rock units. The rotated fault blocks provide focal points for large compaction structures. The new data show amplitude anomalies and other features possibly indicating hydrocarbons associated with many of these structures. The region around the Toroa–1 well was typified by anomalously low velocities, which created a vertical zone of heavily attenuated reflections, particularly on intermediate processing products. The new data also show an amplitude anomaly at the well’s total depth (TD) which gives rise to a velocity push-down.Santonian age coaly source rocks are widespread and several reservoir units are recognised. The reservoir at Kawau–1a is the extensive Kawau Sandstone, an Early Maastrichtian transgressive unit sealed by a thick carbonate-cemented mudstone. In addition to the transgressive sandstone target, the basin also contains sandy Eocene facies, and Paleogene turbidite targets may also be attractive. Closed structures are numerous and many are very large with potential to contain billion barrel oil fields or multi-Tcf gas fields.

The role of deep seismic reflection data in understanding the architecture and petroleum potential of Australia's onshore sedimentary basins

2010 ◽  
Vol 50 (2) ◽  
pp. 726 ◽  
Author(s):  
Lidena Carr ◽  
Russell Korsch ◽  
Leonie Jones ◽  
Josef Holzschuh
Keyword(s):  
Seismic Reflection ◽  
Sedimentary Basins ◽  
Source Rocks ◽  
Petroleum Exploration ◽  
Seismic Line ◽  
Seismic Reflection Data ◽  
Petroleum Potential ◽  
Deep Seismic Reflection ◽  
Reflection Data ◽  
Stratigraphic Sequences

The onshore energy security program, funded by the Australian Government and conducted by Geoscience Australia, has acquired deep seismic reflection data across several frontier sedimentary basins to stimulate petroleum exploration in onshore Australia. Detailed interpretation of deep seismic reflection profiles from four onshore basins, focussing on overall basin geometry and internal sequence stratigraphy, will be presented here, with the aim of assessing the petroleum potential of the basins. At the southern end of the exposed part of the Mt Isa Province, northwest Queensland, a deep seismic line (06GA–M6) crosses the Burke River structural zone of the Georgina Basin. The basin here is >50 km wide, with a half graben geometry, and bounded in the west by a rift border fault. Given the overall architecture, this basin will be of interest for petroleum exploration. The Millungera Basin in northwest Queensland is completely covered by the thin Eromanga Basin and was unknown prior to being detected on two seismic lines (06GA–M4 and 06GA–M5) acquired in 2006. Following this, seismic line 07GA–IG1 imaged a 65 km wide section of the basin. The geometry of internal stratigraphic sequences and a post-depositional thrust margin indicate that the original succession was much thicker than preserved today and may have potential for a petroleum system. The Yathong Trough, in the southeast part of the Darling Basin in NSW, has been imaged in seismic line 08GA–RS2 and interpreted in detail using sequence stratigraphic principles, with several sequences being mapped. Previous studies indicate that the upper part of this basin consists of Devonian sedimentary rocks, with potential source rocks at depth. In eastern South Australia, seismic line 08GA–A1 crossed the Cambrian Arrowie Basin, which is underlain by a Neoproterozoic succession of the Adelaide Rift System. Stratigraphic sequences have been mapped and can be tied to recent drilling for mineral and geothermal exploration. Shallow drill holes from past petroleum exploration have aided the assessment of the petroleum potential of the Cambrian Hawker Group, which contains bitumen in the core, indicating the presence of source rocks in the basin system.

THE OFFSHORE CARPENTARIA BASIN-GULF OF CARPENTARIA, NORTH QUEENSLAND

1994 ◽  
Vol 34 (1) ◽  
pp. 614
Author(s):  
B.A. McConachie ◽  
P.W. Stainton ◽  
M.G. Barlow ◽  
J.N. Dunster
Keyword(s):  
Early Cretaceous ◽  
Seismic Data ◽  
Late Jurassic ◽  
Source Rocks ◽  
Low Velocity ◽  
Reservoir Rocks ◽  
Half Graben ◽  
Reservoir Sandstones ◽  
Cape York ◽  
Velocity Channel

The Carpentaria Basin is late Jurassic to early Cretaceous in age and underlies most of the Gulf of Carpentaria and surrounding onshore areas. The Carpentaria Basin is stratigraphically equivalent to the Eromanga and Papuan Basins where similar reservoir rocks produce large volumes of hydrocarbons.Drillholes Duyken–1, Jackie Ck–1 and 307RD12 provide regional lithostratigraphic and tectonic control for the Q22P permit in the offshore Carpentaria Basin. Duyken–1 penetrated the upper seal section in the Carpentaria Basin and a full sequence through the overlying Karumba Basin. Jackin Ck–1 intersected the lower reservoir units and a condensed upper seal section of the Carpentaria Basin. Coal drillhole 307RD12 tested the late Jurassic to early Cretaceous reservoir section in the Carpentaria Basin and also intersected an underlying Permian infrabasin sequence.Little is known of the pre Jurassic sedimentary section below the offshore Carpentaria Basin but at least two different rock packages appear to be present. The most encouraging are relatively small, layered, low velocity, channel and half-graben fill, possibly related to Permian or Permo-Triassic sedimentary rocks to the east in the Olive River area. The other packages consist of poorly defined, discontinuous, high velocity rocks believed to be related to those of the Bamaga Basin which have been mapped further north.During the period 1990-1993 Comalco Aluminium Limited reprocessed 2188 km of existing seismic data and acquired 2657 km of new seismic data over the offshore Carpentaria Basin. When combined with onshore seismic and the results of drilling previously undertaken by Comalco near Weipa on northwestern Cape York Peninsula, it was possible to define a significant and untested play in the Carpentaria Depression, the deepest part of the offshore Carpentaria Basin.The main play in the basin is the late Jurassic to early Cretaceous reservoir sandstones and source rocks, sealed by thick early Cretaceous mudstones. Possible pre-Jurassic source rocks are also present in discontinuous fault controlled half-grabens underlying the Carpentaria Basin. New detailed basin modelling suggests both the lower part of the Carpentaria Basin and any pre Jurassic section are mature within the depression and any source rocks present should have expelled oil.

PETROLEUM POTENTIAL OF RAGAY GULF, SOUTHEAST LUZON, PHILIPPINES

1994 ◽  
Vol 34 (1) ◽  
pp. 707
Author(s):  
C.S. Lee ◽  
M.C. Galloway ◽  
J.B. Willcox ◽  
A.M.G. Moore ◽  
A.R. Fraser ◽  
...  
Keyword(s):  
International Development ◽  
Late Miocene ◽  
Seismic Data ◽  
Department Of Energy ◽  
Source Rocks ◽  
Geochemical Data ◽  
Petroleum Potential ◽  
Separate Source ◽  
Recent Sediments ◽  
Marine Seismic

During March-May 1992, the Australian Geological Survey Organisation and the Philippine Department of Energy conducted a cooperative marine seismic and underway geochemical survey in four offshore Philippine basins which included Ragay Gulf. The project was funded and supported by the Australian International Development Assistance Bureau.The newly acquired and reprocessed seismic data from Ragay Gulf show a significant improvement in penetration and stratigraphic resolution. Seismic interpretation has revealed the existence of five sedimentary sub-basins with 2.5 – 6 seconds of Eocene to Recent sediments. Several potential traps have been evaluated for hydrocarbon reserves and new prospects are identified.No well has been drilled offshore in the Ragay Gulf. Onshore well log information and stratigraphy have assisted in the correlation and interpretation of offshore seismic data and allowed potential reservoirs to be recognised. The primary reservoir targets are the carbonate sequences of both Early and Late Miocene age. The widespread volcanoclastic sand may be an important secondary target, especially for gas reservoirs.Onshore and offshore geochemical data have confirmed the presence of mature source rocks from which generated hydrocarbons are currently migrating to the surface and, by inference, to reservoirs.A wide diversity of play types is recognised which could have been sourced from three separate source kitchens in the Bondoc, Ragay and Burlas Sub-basins. Specific entrapment possibilities are:Compressional fault-dependent traps (e.g. Anima Sola).Compressional anticlinal fault independent traps (e.g. Alibijaban and Palad).Late Miocene carbonate reefal buildups (e.g. Apud and Gorda).Early Miocene carbonate reservoirs in drape over highs (e.g. San Narciso and Bagulaya).

CROSS-SECTION BALANCING AND THERMOCHRONOLOGICAL ANALYSIS OF THE MESOZOIC DEVELOPMENT OF THE EASTERN OTWAY BASIN

1997 ◽  
Vol 37 (1) ◽  
pp. 390 ◽  
Author(s):  
G.T. Cooper ◽  
K.C. Hill
Keyword(s):  
Cross Section ◽  
Early Cretaceous ◽  
Cross Sections ◽  
Seismic Data ◽  
Vitrinite Reflectance ◽  
Geometric Analysis ◽  
Structural Evolution ◽  
Geometric Constraints ◽  
Source Rocks ◽  
Structural Style

Recent advances in cross-section balancing software have simplified the application of basic geometric constraints to the analysis of basin development. Geometric analysis of field and seismic data allows the user to verify initial interpretations and also elucidates important information about the structural evolution of a basin. Principally, computerised balancing and restoration of cross-sections assists in constraining:the amount of crustal extension;trap geometries, particularly fault geometries through time;the geometry of key horizons at any time, revealing basin morphology and migration paths;the time and amount of maximum burial and hence hydrocarbon migration; andthe likely mechanisms involved in basin evolution. In turn, these parameters can be used to further assess hydrocarbon prospectivity by providing useful data for lithospheric modelling.This study utilises 2D cross-section balancing software (Geosec™) to decompact, balance and restore a series of regional onshore-offshore cross-sections based on both reflection seismic data in the Torquay Embayment and field mapping in the Otway Ranges. The thickness of eroded strata has been constrained by Apatite Fission Track and Vitrinite Reflectance analyses. The resulting section restoration suggests that the eastern Otway Basin experienced extension of 26 per cent in the Early Cretaceous and that the Otway Ranges were subjected to −8 per cent shortening during mid-Cretaceous inversion and −4 per cent shortening during Mio-Pliocene inversion.The structural style of the Otway Ranges and Torquay Embayment is typified by steep, relatively planar, en echelon, N and NE-dipping Early Cretaceous extension faults that were subsequently inverted and eroded during the Cenomanian and Mio-Pliocene. The structural style of the region shows strong similarities with oblique- rift analogue models suggesting that the extensional history of the region was strongly controlled by prevailing basement fabric.Lower Cretaceous source rocks in the eastern Otway Basin reached maximum maturity prior to mid-Cretaceous inversion with the exception of parts of the Torquay Embayment which may not have experienced significant uplift and erosion at this time. The lack of subsidence in the eastern Otway Basin prevented the deposition of significant amounts of Upper Cretaceous sediments which are proven reservoirs in the western Otway Basin and Gippsland Basin. Subsequent Tertiary burial was insufficient, in most regions, to allow the source rocks re-enter the oil generation window.

Stratigraphic Intervals for Oil and Tar Sand Deposits in the Uinta Basin, Utah

2017 ◽  
Vol 54 (4) ◽  
pp. 227-264
Author(s):  
Ronald Johnson ◽  
Justin Birdwell ◽  
Paul Lillis
Keyword(s):  
Brackish Water ◽  
Source Rocks ◽  
Uinta Basin ◽  
Green River ◽  
Reservoir Rocks ◽  
Stratigraphic Framework ◽  
Two Samples ◽  
The Rich ◽  
And Migration ◽  
Almost All

To better understand oil and bitumen generation and migration in the Paleogene lacustrine source rocks of the Uinta Basin, Utah, analyses of 182 oil samples and tar-impregnated intervals from 82 core holes were incorporated into a well-established stratigraphic framework for the basin. The oil samples are from the U.S. Geological Survey Energy Resources Program Geochemistry Laboratory Database; the tar-impregnated intervals are from core holes drilled at the Sunnyside and P.R. Spring-Hill Creek tar sands deposits. The stratigraphic framework includes transgressive and regressive phases of the early freshwater to near freshwater lacustrine interval of Lake Uinta and the rich and lean zone architecture developed for the later brackish-to-hypersaline stages of the lake. Two types of lacustrine-sourced oil are currently recognized in the Uinta Basin: (1) Green River A oils, with high wax and low β-carotane contents thought to be generated by source rocks in the fresh-to-brackish water lacustrine interval, and (2) much less common Green River B oils, an immature asphaltic oil with high β-carotane content thought to be generated by marginally mature to mature source rocks in the hypersaline lacustrine interval. Almost all oil samples from reservoir rocks in the fresh-to-brackish water interval are Green River A oils; however four samples of Green River A oils were present in the hypersaline interval, which likely indicates vertical migration. In addition, two samples of Green River B oil are from intervals that were assumed to contain only Green River A oil. Tar sand at the P.R. Spring-Hill Creek deposit are restricted to marginal lacustrine and fluvial sandstones deposited during the hypersaline phase of Lake Uinta, suggesting a genetic relationship to Green River B oils. Tar sand at the Sunnyside deposit, in contrast, occur in marginal lacustrine and alluvial sandstones deposited from the early fresh to nearly freshwater phase of Lake Uinta through the hypersaline phase. The Sunnyside deposit occurs in an area with structural dips that range from 7 to 14 degrees, and it is possible that some tar migrated stratigraphically down section.

Sequence stratigraphy of source and reservoir rocks in the Upper Permian and Jurassic of Jameson Land, East Greenland

1998 ◽  
pp. 43-54 ◽  
Author(s):  
Lars Stemmerik ◽  
Gregers Dam ◽  
Nanna Noe-Nygaard ◽  
Stefan Piasecki ◽  
Finn Surlyk
Keyword(s):  
Sequence Stratigraphy ◽  
Middle Jurassic ◽  
Sedimentary Basins ◽  
Upper Jurassic ◽  
Oil Field ◽  
Source Rocks ◽  
Upper Permian ◽  
Shallow Marine ◽  
East Greenland ◽  
Reservoir Rocks

NOTE: This article was published in a former series of GEUS Bulletin. Please use the original series name when citing this article, for example: Stemmerik, L., Dam, G., Noe-Nygaard, N., Piasecki, S., & Surlyk, F. (1998). Sequence stratigraphy of source and reservoir rocks in the Upper Permian and Jurassic of Jameson Land, East Greenland. Geology of Greenland Survey Bulletin, 180, 43-54. https://doi.org/10.34194/ggub.v180.5085 _______________ Approximately half of the hydrocarbons discovered in the North Atlantic petroleum provinces are found in sandstones of latest Triassic – Jurassic age with the Middle Jurassic Brent Group, and its correlatives, being the economically most important reservoir unit accounting for approximately 25% of the reserves. Hydrocarbons in these reservoirs are generated mainly from the Upper Jurassic Kimmeridge Clay and its correlatives with additional contributions from Middle Jurassic coal, Lower Jurassic marine shales and Devonian lacustrine shales. Equivalents to these deeply buried rocks crop out in the well-exposed sedimentary basins of East Greenland where more detailed studies are possible and these basins are frequently used for analogue studies (Fig. 1). Investigations in East Greenland have documented four major organic-rich shale units which are potential source rocks for hydrocarbons. They include marine shales of the Upper Permian Ravnefjeld Formation (Fig. 2), the Middle Jurassic Sortehat Formation and the Upper Jurassic Hareelv Formation (Fig. 4) and lacustrine shales of the uppermost Triassic – lowermost Jurassic Kap Stewart Group (Fig. 3; Surlyk et al. 1986b; Dam & Christiansen 1990; Christiansen et al. 1992, 1993; Dam et al. 1995; Krabbe 1996). Potential reservoir units include Upper Permian shallow marine platform and build-up carbonates of the Wegener Halvø Formation, lacustrine sandstones of the Rhaetian–Sinemurian Kap Stewart Group and marine sandstones of the Pliensbachian–Aalenian Neill Klinter Group, the Upper Bajocian – Callovian Pelion Formation and Upper Oxfordian – Kimmeridgian Hareelv Formation (Figs 2–4; Christiansen et al. 1992). The Jurassic sandstones of Jameson Land are well known as excellent analogues for hydrocarbon reservoirs in the northern North Sea and offshore mid-Norway. The best documented examples are the turbidite sands of the Hareelv Formation as an analogue for the Magnus oil field and the many Paleogene oil and gas fields, the shallow marine Pelion Formation as an analogue for the Brent Group in the Viking Graben and correlative Garn Group of the Norwegian Shelf, the Neill Klinter Group as an analogue for the Tilje, Ror, Ile and Not Formations and the Kap Stewart Group for the Åre Formation (Surlyk 1987, 1991; Dam & Surlyk 1995; Dam et al. 1995; Surlyk & Noe-Nygaard 1995; Engkilde & Surlyk in press). The presence of pre-Late Jurassic source rocks in Jameson Land suggests the presence of correlative source rocks offshore mid-Norway where the Upper Jurassic source rocks are not sufficiently deeply buried to generate hydrocarbons. The Upper Permian Ravnefjeld Formation in particular provides a useful source rock analogue both there and in more distant areas such as the Barents Sea. The present paper is a summary of a research project supported by the Danish Ministry of Environment and Energy (Piasecki et al. 1994). The aim of the project is to improve our understanding of the distribution of source and reservoir rocks by the application of sequence stratigraphy to the basin analysis. We have focused on the Upper Permian and uppermost Triassic– Jurassic successions where the presence of source and reservoir rocks are well documented from previous studies. Field work during the summer of 1993 included biostratigraphic, sedimentological and sequence stratigraphic studies of selected time slices and was supplemented by drilling of 11 shallow cores (Piasecki et al. 1994). The results so far arising from this work are collected in Piasecki et al. (1997), and the present summary highlights the petroleum-related implications.

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