GEOLOGIC EVOLUTION AND HYDROCARBON HABITAT GIPPSLAND BASIN

1972 ◽  
Vol 12 (1) ◽  
pp. 132 ◽  
Author(s):  
J. Barry Hocking
Keyword(s):  
Late Cretaceous ◽  
Upper Cretaceous ◽  
Meteoric Water ◽  
Oil And Gas ◽  
Basin Evolution ◽  
Fold Belt ◽  
Apparent Lack ◽  
Northern Flank ◽  
Southeastern Australia ◽  
Gippsland Basin

The Gippsland Basin of southeastern Australia is a post-orogenic, continental margin type of basin of Upper Cretaceous-Cainozoic age.Gippsland Basin evolution can be traced back to the establishment of the Strzelecki Basin, or ancestral Gippsland Basin, during the Jurassic. Gippsland Basin sedimentation commenced in the middle to late Cretaceous and is represented as a gross transgressive-regressive cycle consisting of the continental Latrobe Valley Group (Upper Cretaceous to Eocene or Miocene), the marine Seaspray Group (Oligocene to Pliocene or Recent), and finally the continental Sale Group (Pliocene to Recent).The hydrocarbons of the Gippsland Shelf petroleum province were generated within the Latrobe Valley Group and are trapped in porous fluvio-deltaic sandstones of the Latrobe. At Lakes Entrance, however, oil and gas are present in a marginal sandy facies of the Lakes Entrance Formation (Seaspray Group).The buried Strzelecki Basin has played a fundamental role in the development and distribution of the Cainozoic fold belt in the northern Gippsland Basin. The Gippsland Shelf hydrocarbon accumulations fall within this belt and are primarily structural traps. The apparent lack of structural accumulations onshore in Gippsland is largely due to a Plio-Pleistocene episode of cratonic uplift that was accompanied by basinward tilting of structures and meteoric water influx.The non-commercial Lakes Entrance field, located on the stable northern flank of the basin, is a stratigraphic trap and may serve as a guide for future exploration.

A NEW MODEL FOR THE MID-CRETACEOUS STRUCTURAL HISTORY OF THE NORTHERN GIPPSLAND BASIN

1991 ◽  
Vol 31 (1) ◽  
pp. 143 ◽  
Author(s):  
D.C. Lowry ◽  
I.M. Longley
Keyword(s):  
Early Cretaceous ◽  
Late Cretaceous ◽  
Second Phase ◽  
Northern Flank ◽  
Tectonic History ◽  
Structural History ◽  
Intermittent Compression ◽  
History Of ◽  
Transfer Faults ◽  
Gippsland Basin

The tectonic history of the northern flank of the offshore Gippsland Basin can be divided into three phases:an Early Cretaceous rift phase (120-98 Ma) with deposition of the Strzelecki Group and extension in a northeast-southwest direction.a mid-Cretaceous phase (98-80 Ma) with deposition of the Golden Beach Group and extension in a northwest- southeast direction anda Late Cretaceous to Tertiary sag phase with intermittent compression or wrenching.Previous workers have described the first and third phases. This paper argues for a distinctive second phase with extension at right angles to the first phase. The complex Cretaceous structure in the Kipper-Hammerhead area is interpreted in terms of a model in which transfer faults of the first phase became domino faults of the second phase.

PETROLEUM RESOURCES OF OFFSHORE SOUTHEASTERN AUSTRALIA

1975 ◽  
Vol 15 (2) ◽  
pp. 55
Author(s):  
Ian McPhee
Keyword(s):  
Oil And Gas ◽  
Full Potential ◽  
Deep Basin ◽  
Reservoir Rocks ◽  
Sedimentary Sequences ◽  
Southeastern Australia ◽  
Petroleum Resources ◽  
Giant Fields ◽  
Gippsland Basin ◽  
Great Australian Bight

THE GIPPSLAND Basin is established as a prolific producer of oil and gas from a number of giant fields and other major discoveries are yet to be developed. Further discoveries can be expected in this petroliferous basin which has good future exploration potential. The Bass Basin has been disappointing as commercial discoveries have eluded the explorers. However source and reservoir rocks are present and the basin has future promise if the key to the nature of accumulations can be found. The Otway and Great Australian Bight Basins cover a vast area and include very thick potential source formations and good reservoir facies. Thick sedimentary sequences in the deep basin have been little explored and no significant shows encountered. The basins have potential but there are exploration difficulties to be overcome before full potential can be understood.

GIPPSLAND'S OLD AND NEW OIL

1977 ◽  
Vol 17 (2) ◽  
pp. 47
Author(s):  
B.R. Brown
Keyword(s):  
Late Cretaceous ◽  
Oil And Gas ◽  
Sediment Supply ◽  
Associated Gas ◽  
Fine Grained ◽  
Early Oligocene ◽  
Gas Fields ◽  
Potential Traps ◽  
Gippsland Basin ◽  
Western Portion

The Gippsland Basin, initiated in the late Cretaceous, accumulated as much as 4,500 m. (15,000 feet) of sediment before the first major structural movement in the early Eocene, when faulted anticlinal structures and pronounced regional westerly dip were developed in the Latrobe Group.Over the next 13 m.y. of the Eocene, sediment supply was reduced and much of it trapped in the western portion of the basin. On the eastern marine edge of the basin the Tuna-Flounder Channel was cut and filled over a period of 4 m.y. Subsequent erosion, sometimes severe, particularly in the Marlin area, created the significant unconformity on top of the Latrobe Group reservoir sediments. Much of that surface was covered with fine-grained marine sediment of early Oligocene age, leaving only a few high-standing areas unsealed for a further period of 25 m.y. until the mid-Miocene.Later structural movements, in the mid-Miocene (10 m.y.B.P.), were largely vertical with some anticlinal warping. New potential traps were created then and some older structures rejuvenated. Following the latter period of anticlinal growth, a major marine channel system was formed by erosion 9 m.y.B.P. and subsequently engulfed by rapid deposition of prograded wedges of sediment on the continental margin.Oil and gas have been formed from land-derived organic matter deposited in the Latrobe Group during late Cretaceous to Eocene times (100.37 m.y.). Subsequently the oil and gas accumulations have developed their distinctive geographical distribution with the major oil fields buried deeper than the major gas fields. It appears that oil has migrated and been trapped at intervals over the last 60 m.y. under varying overburdens from about 100 m. to about 2,000 m. as indicated by the saturation pressures of the crude oils. Migration of oil into the Kingfish and Halibut fields apparently took place no later than 10 to 24 m.y.B.P. Gas migration into Marlin and associated gas fields took place later. There is evidence that oil and gas is forming at present, leading to the conclusion that both old and new oil exist in the basin.

PETROLEUM OCCURRENCE IN THE GIPPSLAND BASIN AND ITS RELATIONSHIP TO RANK AND ORGANIC MATTER TYPE

1984 ◽  
Vol 24 (1) ◽  
pp. 196 ◽  
Author(s):  
G. C. S Smith ◽  
A. C. Cook
Keyword(s):  
Organic Matter ◽  
Late Cretaceous ◽  
Upper Cretaceous ◽  
Late Eocene ◽  
Generative Capacity ◽  
Near Surface ◽  
Metamorphic History ◽  
Downhole Temperature ◽  
Gippsland Basin ◽  
Sediment Age

Coal rank, sediment age and downhole temperature data indicate that the rates of burial and palaeothermal gradients in the Gippsland Basin have varied both areally and with time over the Late Cretaceous to Recent period. The generation and occurrence of petroleum are controlled mainly by the burial metamorphic history. The inshore areas are gas prone because the Late Cainozoic burial meta-morphism is moderate and overprints an earlier phase of substantial burial metamorphism in the Late Cretaceous-Early Tertiary. The areas offshore in the Central Deep are oil prone because the earlier burial metamorphism was minor and the burial metamorphism during the last 20 Ma has been rapid and substantial.Vitrinite reflectance values (R̅vmax) vary from about 0.2 per cent at near-surface depths to over 1.2 per cent in the Upper Cretaceous sediments at depths of about 4 km and more. Exinite reflectance values (R̅emax) are about 0.05 per cent at near-surface depths increasing gradually to only 0.15 per cent at 3 km. Significant exinite metamorphism is evident at depths between 3 and 4 km, with major exinite metamorphism at 4-5 km and more at the base of the Upper Cretaceous sequence.The proportion of organic matter and its specific generative capacity increases up through the Latrobe Group. The Late Cretaceous to Early Eocene organic matter consists of orthohydrous vitrinite and diverse inertinite and is distinct from the Middle to Late Eocene coaly matter which consists of perhydrous vitrinite and minor amounts of inertinite. The Oligocene to Miocene organic matter is dominated by perhydrous vitrinites and is inertinite-poor. The overall proportion of exinite is roughly constant up through the Upper Cretaceous to Miocene terrestrial sequences although some forms of alginite are more common in the Eocene to Miocene sediments. Petrographic and geologic evidence suggests that much of the petroleum probably is generated from vitrinite in addition to exinite at low coal ranks (R̅vmax 0.4-0.8 per cent) and low burial depths (2-4 km).

BASS AND GIPPSLAND BASINS: A COMPARISON

1984 ◽  
Vol 24 (1) ◽  
pp. 101
Author(s):  
J. K. Davidson ◽  
G. J. Blackburn ◽  
K. C. Morrison
Keyword(s):  
Vertical Migration ◽  
Upper Cretaceous ◽  
Oil And Gas ◽  
Normal Fault ◽  
Gas Condensate ◽  
Normal Faults ◽  
Lower Eocene ◽  
Light Oil ◽  
Recoverable Reserve ◽  
Gippsland Basin

After two decades of exploration, one wireline test of oil, one of light oil and several of gas and gas/condensate have been recovered from the Bass Basin while the adjacent Gippsland Basin has established an estimated ultimate recoverable reserve of the order of half a billion kilolitres of liquids and a quarter of a trillion cubic metres of gas. Geologically, the basins are similar.The alluvial and nearshore deposits at the top of the Latrobe Group in Gippsland are as porous and permeable as similar deposits at the top of the Eastern View Group in Bass.The Eastern View and Latrobe Formations are regionally sealed by the Upper Eocene Demons Bluff and Oligocene Lakes Entrance Formations respectively. The intra-Latrobe section in Gippsland has significant but regionally not very extensive sealing units, whereas the Lower Eocene to Paleocene sequence in Bass is increasingly shale prone with depth, sometimes over-pressured, and constitutes an extensive seal for a base of Tertiary play. This play comprises Paleocene shales sealing Upper Cretaceous clastics with hydrocarbons potentially sourced from both units.Maturation studies (Saxby, 1980) indicate that the Upper Cretaceous is the principal source for hydrocarbons in Gippsland with possible lesser contributions from the Lower Paleocene and Lower Cretaceous. Limited data indicate the same is true in Bass and that the Paleocene and parts of the Lower Eocene are mature sources for gas/condensate and light oil. Normal faults assist vertical migration in Gippsland. In Bass, relatively few normal faults penetrate the Paleocene and Lower Eocene shales to reach the top of the Eastern View, greatly restricting the chances of vertical migration over much of the basin. Vertical migration is more likely beyond the margins of the depocentre.Eroded anticlines at the top of the Latrobe form large traps for the bulk of Gippsland's hydrocarbons. Small anticlines, wrench-related features and intra-Latrobe closures are more difficult to find. The normal fault blocks in Bass at the top of the Eastern View are wrench-modified and have proven difficult to define.The recent recognition in Bass of the base of Tertiary play and the need for careful structural and seismic interpretations is expected to lead to discoveries of oil and gas.

STRUCTURAL FRAMEWORK AND BASIN EVOLUTION OF AUSTRALIA’S SOUTHERN MARGIN

2003 ◽  
Vol 43 (1) ◽  
pp. 13 ◽  
Author(s):  
J.P. Teasdale ◽  
L.L. Pryer ◽  
P.G. Stuart-Smith ◽  
K.K. Romine ◽  
M.A. Etheridge ◽  
...  
Keyword(s):  
Late Cretaceous ◽  
Structural Control ◽  
Structural Evolution ◽  
Shear Zones ◽  
Basin Evolution ◽  
Primary Control ◽  
Fold Belt ◽  
Southern Margin ◽  
Lachlan Fold Belt ◽  
Basement Structures

The structural evolution of all of the Southern Margin Basins can be explained by episodic reactivation of basement structures in respect to a specific sequence of tectonic events. Three geological provinces dominate the basement geology of the Southern Margin basins. The Eyre, Ceduna, Duntroon and Polda Basins overlie basement of the Archean to Proterozoic Gawler-Antarctic Craton. The Otway and Sorell Basins overlie basement of the Neoproterozoic-early Palaeozoic Adelaide- Kanmantoo Fold Belt. The Bass and Gippsland Basins overlie basement of the Palaeozoic Lachlan Fold Belt. The contrasting basement terranes within the three basement provinces and the structures within and between them significantly influenced the evolution and architecture of the Southern Margin basins.The present-day geometry was established during three Mesozoic extensional basin phases:Late Jurassic–Early Cretaceous NW–SE transtension forming deep rift basins to the west and linked pullapart basins and oblique graben east of the Southwest Ceduna Accommodation Zone; Early–Mid Cretaceous NE–SW extension; and Late Cretaceous NNE–SSW extension leading to continental breakup. At least three, potentially trap forming, inversion events have variably influenced the Southern Margin basins; Mid Cretaceous, Eocene, and Miocene-Recent. Volcanism occurred along the margin during the Late Cretaceous and sporadically through the Tertiary.First-order structural control on Mesozoic rifting and breakup were east–west trending basement structures of the southern Australian fracture zone. Second-order controls include:Proterozoic basement shear zones and/or terrane boundaries in the western Gawler Craton, which controlled basin evolution in the Eyre and Ceduna Subbasins; Neoproterozoic structures, which significantly influenced basin evolution in the Ceduna sub-basin; Cambro-Ordovician basement shear zones and/or terrane boundaries, which were a primary control on basin evolution in the Otway and Sorell Basins; and Palaeozoic structures in the Lachlan Fold Belt, which controlled basin evolution in the Bass and Gippsland Basins.A SEEBASE™ (Structurally Enhanced view of Economic Basement) model for the Southern Margin basins has been constructed to show basement topography. When used in combination with a rigorous interpretation of the structural evolution of the margin, it provides a foundation for basin phase and source rock distribution, hydrocarbon fluid focal points and trap type/distribution.

scholarly journals Petroleum generation and migration in the Mesopotamian Basin and Zagros Fold Belt of Iraq: results from a basin-modeling study

GeoArabia ◽  
2004 ◽  
Vol 9 (4) ◽  
pp. 41-72 ◽  
Author(s):  
Janet K. Pitman ◽  
Douglas Steinshouer ◽  
Michael D. Lewan
Keyword(s):  
Late Cretaceous ◽  
Oil And Gas ◽  
Source Rocks ◽  
Peak Oil ◽  
Fold Belt ◽  
Hydrous Pyrolysis ◽  
Oil Generation ◽  
Petroleum Generation ◽  
And Migration ◽  
Migration Pathways

ABSTRACT A regional 3-D total petroleum-system model was developed to evaluate petroleum generation and migration histories in the Mesopotamian Basin and Zagros fold belt in Iraq. The modeling was undertaken in conjunction with Middle East petroleum assessment studies conducted by the USGS. Regional structure maps, isopach and facies maps, and thermal maturity data were used as input to the model. The oil-generation potential of Jurassic source-rocks, the principal known source of the petroleum in Jurassic, Cretaceous, and Tertiary reservoirs in these regions, was modeled using hydrous pyrolysis (Type II-S) kerogen kinetics. Results showed that oil generation in source rocks commenced in the Late Cretaceous in intrashelf basins, peak expulsion took place in the late Miocene and Pliocene when these depocenters had expanded along the Zagros foredeep trend, and generation ended in the Holocene when deposition in the foredeep ceased. The model indicates that, at present, the majority of Jurassic source rocks in Iraq have reached or exceeded peak oil generation and most rocks have completed oil generation and expulsion. Flow-path simulations demonstrate that virtually all oil and gas fields in the Mesopotamian Basin and Zagros fold belt overlie mature Jurassic source rocks (vertical migration dominated) and are situated on, or close to, modeled migration pathways. Fields closest to modeled pathways associated with source rocks in local intrashelf basins were charged earliest from Late Cretaceous through the middle Miocene, and other fields filled later when compression-related traps were being formed. Model results confirm petroleum migration along major, northwest-trending folds and faults, and oil migration loss at the surface.

GIFFSLAND HYDROCARBONS - A PERSPECTIVE FROM THE BASIN EDGE

1984 ◽  
Vol 24 (1) ◽  
pp. 91 ◽  
Author(s):  
J. G. Stainforth
Keyword(s):  
Heat Flow ◽  
Upper Cretaceous ◽  
Oil And Gas ◽  
Source Rocks ◽  
Hydrocarbon Generation ◽  
Lower Tertiary ◽  
Late Tertiary ◽  
Carbonaceous Shales ◽  
Basin Edge ◽  
Gippsland Basin

Permit VIC/P19 lies palaeogeographically seaward of the main producing part of the Gippsland Basin. Deposition of the Latrobe Group commenced with volcanics and continental 'rift-stage' sediments during the Late Cretaceous. This phase was succeeded first by paludal sedimentation in the failed rift during the Campanian and Maastrichtian, and then by cyclic paralic sedimentation during the Paleocene and Eocene.Analysis of the hydrocarbons recovered during recent exploration of permit VIC/P19 shows that they were sourced from moderately mature coals and carbonaceous shales in the Campanian/-Maastrichtian paludal sequence.A maturation model that assumes elevated but decreasing heat flow, related to sea-floor spreading, produces an excellent fit to the observed maturity data and predicts a long history of hydrocarbon generation during the Tertiary. The maturity of the Upper Cretaceous source sequence depends more on the thickness of the overlying Lower Tertiary clastic Latrobe sediments than on the thickness of the Upper Tertiary carbonate wedge. The Late Tertiary phase of burial had relatively little effect on maturation because of its rapidity and the lower heat flow and higher thermal conductivities of the deeper sequence at the time. Overpressures in mature Upper Cretaceous source rocks, resulting from hydrocarbon generation, have driven pore fluids, including hydrocarbons, laterally up-dip into normally pressured reservoirs.The main oil province of the Gippsland Basin has a greater thickness of Lower Tertiary than has VIC/P19. As a result, source rocks are more mature there, and became wholly so by the end of deposition of the Latrobe Group. This facilitated charge of traps at the top of the Latrobe Group, which contain most of the oil and gas discovered to date in the Basin.

Hanna of Wyoming—The Rockies’ Deepest Basin

2017 ◽  
Vol 54 (4) ◽  
pp. 265-293 ◽  
Author(s):  
Roger Matson ◽  
Jack Magathan
Keyword(s):  
Upper Cretaceous ◽  
Oil And Gas ◽  
Thrust Faults ◽  
Depositional History ◽  
Deep Sediment ◽  
Northern Margin ◽  
Lacustrine Shale ◽  
Hanna Basin ◽  
Fluvial Sandstone

The Hanna Basin is one of the world’s deeper intracratonic depressions. It contains exceptionally thick sequences of mature, hydrocarbon-rich Paleozoic through Eocene rocks and has the requisite structural and depositional history to be a significant petroleum province. The Tertiary Hanna and Ferris formations consist of up to 20,000 ft of organic-rich lacustrine shale, shaly mudstone, coal, and fluvial sandstone. The Upper Cretaceous Medicine Bow, Lewis, and Mesaverde formations consist of up to 10,000 ft of marine and nonmarine organic-rich shale enclosing multiple stacked beds of hydrocarbon-bearing sandstone. Significant shows of oil and gas in Upper Cretaceous and Paleocene rocks occur in the basin. Structural prospecting should be most fruitful around the edges where Laramide flank structures were created by out-of-the-basin thrust faults resulting from deformation of the basin’s unique 50-mile wide by 9-mile deep sediment package. Strata along the northern margin of the basin were compressed into conventional anticlinal folds by southward forces emanating from Emigrant Trail-Granite Mountains overthrusting. Oil and gas from Pennsylvanian to Upper Cretaceous aged rocks have been found in such structures near the Hanna Basin. Only seven wells have successfully probed the deeper part of the Hanna Basin (not including Anadarko’s #172 Durante lost hole, Sec. 17, T22N, R82W, lost in 2004, hopelessly stuck at 19,700 ft, unlogged and untested). Two of these wells tested gas at commercial rates from Upper Cretaceous rocks at depths of 10,000 to 12,000 ft. Sparse drilling along the Hanna Basin’s flanks has also revealed structures from 3,000 to 7,000 feet deep which yielded significant shows of oil and gas.

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