THE LA BELLA AND MINERVA GAS DISCOVERIES, OFFSHORE OTWAY BASIN

1995 ◽  
Vol 35 (1) ◽  
pp. 405 ◽  
Author(s):  
C.W. Luxton ◽  
S. T. Horan ◽  
D.L. Pickavance ◽  
M.S. Durham.
Keyword(s):  
Late Cretaceous ◽  
Oil And Gas ◽  
Hydrocarbon Exploration ◽  
Source Rocks ◽  
Production Test ◽  
Water Contact ◽  
Excellent Quality ◽  
Fault Block ◽  
Well Location ◽  
Gas Fields

In the past 100 years of hydrocarbon exploration in the Otway Basin more than 170 exploration wells have been drilled. Prior to 1993, success was limited to small onshore gas fields. In early 1993, the La Bella-1 and Minerva-1 wells discovered significant volumes of gas in Late Cretaceous sandstones within permits VIC/P30 and VIC/P31 in the offshore Otway Basin. They are the largest discoveries to date in the basin and have enabled new markets to be considered for Otway Basin gas. These discoveries were the culmination of a regional evaluation of the Otway Basin by BHP Petroleum which highlighted the prospectivity of VIC/P30 and VIC/P31. Key factors in this evaluation were:geochemical studies that indicated the presence of source rocks with the potential to generate both oil and gas;the development of a new reservoir/seal model; andimproved seismic data quality through reprocessing and new acquisition.La Bella-1 tested the southern fault block of a faulted anticlinal structure in the southeast corner of VIC/P30. Gas was discovered in two Late Cretaceous sandstone intervals of the Shipwreck Group (informal BHP Petroleum nomenclature). Reservoirs are of moderate to good quality and are sealed vertically, and by cross-fault seal, by Late Cretaceous claystones of the Sherbrook Group. The gas is believed to have been sourced from coals and shales of the Early Cretaceous Eumeralla Formation and the structure appears to be filled to spill as currently mapped. RFT samples recovered dry gas with 13 moI-% CO2 and minor amounts of condensate.Minerva-1 tested the northern fault block of a faulted anticline in the northwest corner of VIC/ P31. Gas was discovered in three excellent quality reservoir horizons within the Shipwreck Group. Late Cretaceous Shipwreck Group silty claystones provide vertical and cross-fault seal. The hydrocarbon source is similar to that for the La Bella accumulation and the structure appears to be filled to spill. A production test was carried out in the lower sand unit and flowed at a rig limited rate of 28.8 MMCFGD (0.81 Mm3/D) through a one-inch choke. The gas is composed mainly of methane, with minor amounts of condensate and 1.9 mol-% C02. Minerva-2A was drilled later in 1993 as an appraisal well to test the southern fault block of the structure to prove up sufficient reserves to pursue entry into developing gas markets. It encountered a similar reservoir unit of excellent quality, with a gas-water contact common with that of the northern block of the structure.The La Bella and Minerva gas discoveries have greatly enhanced the prospectivity of the offshore portion of the Otway Basin. The extension of known hydrocarbon accumulations from the onshore Port Campbell embayment to the La Bella-1 well location, 55 km offshore, demonstrates the potential of this portion of the basin.

Anabar-Lena Composite Tectono-Sedimentary Element, Northern East Siberia

2021 ◽  
pp. M57-2021-29
Author(s):  
A.K. Khudoley ◽  
S.V. Frolov ◽  
G.G. Akhmanov ◽  
E.A. Bakay ◽  
S.S. Drachev ◽  
...  
Keyword(s):  
Late Cretaceous ◽  
Oil And Gas ◽  
Foreland Basin ◽  
Early Carboniferous ◽  
Passive Margin ◽  
Source Rocks ◽  
East Siberia ◽  
Lena River ◽  
Petroleum Systems ◽  
Intracratonic Basin

AbstractAnabar-Lena Composite Tectono-Sedimentary Element (AL CTSE) is located in the northern East Siberia extending for c. 700 km along the Laptev Sea coast between the Khatanga Bay and Lena River delta. AL CTSE consists of rocks from Mesoproterozoic to Late Cretaceous in age with total thickness reaching 14 km. It evolved through the following tectonic settings: (1) Meso-Early Neoproterozoic intracratonic basin, (2) Ediacaran - Early Devonian passive margin, (3) Middle Devonian - Early Carboniferous rift, (4) late Early Carboniferous - latest Jurassic passive margin, (5) Permian foreland basin, (6) Triassic to Jurassic continental platform basin and (7) latest Jurassic - earliest Late Cretaceous foreland basin. Proterozoic and lower-middle Paleozoic successions are composed mainly by carbonate rocks while siliciclastic rocks dominate upper Paleozoic and Mesozoic sections. Several petroleum systems are assumed in the AL CTSE. Permian source rocks and Triassic sandstone reservoirs are the most important play elements. Presence of several mature source rock units and abundant oil- and gas-shows (both in wells and in outcrops), including a giant Olenek Bitumen Field, suggest that further exploration in this area may result in economic discoveries.

HYDROCARBON HABITAT OF THE SURAT/BOWEN BASIN

1982 ◽  
Vol 22 (1) ◽  
pp. 213 ◽  
Author(s):  
B. M. Thomas ◽  
D. G. Osborne ◽  
A. J. Wright
Keyword(s):  
Oil And Gas ◽  
Lower Jurassic ◽  
Source Rocks ◽  
Lateral Migration ◽  
Early Maturity ◽  
Oil And Gas Fields ◽  
Basement Rocks ◽  
Origin Of Oil ◽  
Gas Fields ◽  
Geochemical Studies

Ever since the early discoveries at Cabawin (1960) and Moonie (1961), the origin of oil and gas in the Surat/Bowen Basin has been a subject of speculation. Hydrocarbons have been found in reservoirs ranging in age from Permian to Early Jurassic; even fractured pre-Permian 'basement' rocks have occasionally recorded shows.Recent geochemical studies have identified rich source rocks within the Jurassic, Triassic and Permian sequences. The Middle Jurassic Walloon Coal Measures are thermally immature throughout the Surat Basin and are unlikely to have generated significant amounts of hydrocarbons. Lower Jurassic Evergreen Formation source rocks have reached 'nominal early maturity' (VR = 0.6) in parts of the basin. The Middle Triassic Moolayember Formation lies within the oil generation zone in the northern Taroom Trough. However, no oil has yet been confidently correlated with either a Jurassic or a Triassic source. On geochemical and geological grounds it is likely that most, if not all, of the hydrocarbons discovered to date were generated from Permian source rocks.The probability of finding gas as well as oil in Permian, Triassic or Jurassic reservoirs increases from south to north, in accord with organic maturity trends in the Permian of the Taroom Trough. On the narrow thrust-bounded eastern flank, vertical migration has occurred, resulting in oilfields at Moonie and Bennett. In contrast, extensive lateral migration of hydrocarbons across the gentle western flank of the basin is indicated by numerous small oil and gas fields on the Roma Shelf and Wunger Ridge.

THE AUSTRALIAN SEARCH FOR PETROLEUM: PATTERNS OF DISCOVERY

1999 ◽  
Vol 39 (1) ◽  
pp. 12 ◽  
Author(s):  
M.T. Bradshaw C.B. Foster ◽  
M.E. Fellows ◽  
D.C. Rowland
Keyword(s):  
Oil And Gas ◽  
Hydrocarbon Exploration ◽  
Oil Fields ◽  
Government Policies ◽  
Profit Motive ◽  
Oil And Gas Fields ◽  
Main Driver ◽  
Powerful Stimulus ◽  
Gas Fields ◽  
Exploration Activity

Three cycles of successful commercial hydrocarbon exploration and discovery have occurred in Australia since 1960, although sporadic efforts to locate oil accumulations have occurred since 1860. The first cycle of successful exploration, from 1960 to 1972, revealed most of the productive basins and all of the giant oil fields found to date. After an interval of very low drilling rates between 1973 and 1978, exploration activity returned to strong levels for a second cycle of discovery between 1978 and 1988. A third cycle commenced in 1989 when there was an increase in exploration activity and the number of hydrocarbon discoveries again, after a low point in the mid 1980s.The discovery of oil and gas fields is dependent on the rate of exploration activity, geological endowment, exploration efficiency and chance. Technology and geological knowledge influence exploration efficiency. The main driver of exploration activity is the profit motive, which is modified by government policies, oil price, markets, and perceived prospectivity. Discovery itself is a powerful stimulus to further exploration. Through the last 40 years these factors have varied in their impact on exploration and the resulting petroleum discoveries.

Tectonostratigraphic development and hydrocarbon reservoir quality on a convergent margin: East Coast, North Island, New Zealand

2009 ◽  
Vol 49 (2) ◽  
pp. 600
Author(s):  
Brad Field ◽  
Jan Baur ◽  
Kyle Bland ◽  
Greg Browne ◽  
Angela Griffin ◽  
...  
Keyword(s):  
Late Cretaceous ◽  
East Coast ◽  
Fractured Reservoirs ◽  
Hydrocarbon Exploration ◽  
Passive Margin ◽  
Source Rocks ◽  
Reservoir Quality ◽  
High Porosity ◽  
Hydrocarbon Reservoir ◽  
Reservoir Potential

Hydrocarbon exploration on the East Coast of the North Island has not yet yielded significant commercial reserves, even though the elements of a working petroleum system are all present (Field et al, 1997). Exploration has focussed on the shallow, Neogene part of the succession, built up during plate margin convergence over the last ∼24 million years. Convergent margins are generally characterised by low-total organic carbon (TOC) source rocks and poor clastic reservoir quality due to poor sorting and labile grains. However, the obliquely-convergent Hikurangi subduction margin of the East Coast has high TOC source rocks that pre-date the subduction phase, and its reservoir potential, though variable, has several aspects in its favour, namely: deep-water rocks of high porosity and permeability; preservation of pore space by overpressure; the presence of fractured reservoirs and hybrid reservoirs, where low clastic permeability is enhanced by fractures. The East Coast North Island is a Neogene oblique subduction margin, with Neogene shelf and slope basins that developed on Late Cretaceous-Paleogene passive margin marine successions. The main hydrocarbon source rocks are Late Cretaceous and Paleocene and the main reservoir potential is in the Neogene (Field et al, 2005). Miocene mudstones with good seal potential are common, as is significant over-pressuring. Neogene deformation controlled basin development and accommodation space and strongly-influenced lateral facies development and fractured reservoirs. Early to Middle Miocene thrusting was followed by later Neogene extension (e.g. Barnes et al 2002), with a return to thrusting in the Pliocene. Local wells have flow-tested gas shows.

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.

HYDROCARBON PROSPECTIVITY OF THE TORQUAY SUB-BASIN, OFFSHORE VICTORIA

1994 ◽  
Vol 34 (1) ◽  
pp. 479 ◽  
Author(s):  
Mark A. Trupp ◽  
Keith W. Spence ◽  
Michael J. Gidding
Keyword(s):  
Lower Cretaceous ◽  
Hydrocarbon Exploration ◽  
Source Rocks ◽  
Structural Deformation ◽  
Hydrocarbon Generation ◽  
Fault Block ◽  
Complex Fault ◽  
Wild Dog ◽  
Reservoir Potential ◽  
Gippsland Basin

The Torquay Sub-basin lies to the south of Port Phillip Bay in Victoria. It has two main tectonic elements; a Basin Deep area which is flanked to the southeast by the shallower Snail Terrace. It is bounded by the Otway Ranges to the northwest and shallow basement elsewhere. The stratigraphy of the area reflects the influence of two overlapping basins. The Lower Cretaceous section is equivalent to the Otway Group of the Otway Basin, whilst the Upper Cretaceous and Tertiary section is comparable with the Bass Basin stratigraphy.The Torquay Sub-basin apparently has all of the essential ingredients needed for successful hydrocarbon exploration. It has good reservoir-seal pairs, moderate structural deformation and probable source rocks in a deep kitchen. Four play types are recognised:Large Miocene age anticlines, similar to those in the Gippsland Basin, with an Eocene sandstone reservoir objective;The same reservoir in localised Oligocene anticlines associated with fault inversion;Possible Lower Cretaceous Eumeralla Formation sandstones in tilted fault blocks and faulted anticlines; andLower Cretaceous Crayfish Sub-group sandstones also in tilted fault block traps.Maturity modelling suggests that the Miocene anticlines post-date hydrocarbon generation. Poor reservoir potential and complex fault trap geometries downgrade the two Lower Cretaceous plays.The Oligocene play was tested by Wild Dog-1 which penetrated excellent Eocene age reservoir sands beneath a plastic shale seal, however, the well failed to encounter any hydrocarbons. Post-mortem analysis indicates the well tested a valid trap. The failure of the well is attributed to a lack of charge. Remaining exploration potential is limited to the deeper plays which have much greater risks associated with each play element.

THE LANDER TROUGH—A CENTRAL AUSTRALIAN FRONTIER EXPLORATION AREA

1990 ◽  
Vol 30 (1) ◽  
pp. 128 ◽  
Author(s):  
D. Pegum ◽  
M. Loeliger
Keyword(s):  
Oil And Gas ◽  
Structural Features ◽  
Source Rocks ◽  
Carbonate Sediments ◽  
Late Proterozoic ◽  
Oil And Gas Fields ◽  
Unexplored Area ◽  
Early Palaeozoic ◽  
Exploration Area ◽  
Gas Fields

The Lander Trough is an almost unexplored area of 30 000 square kilometres in the central western Northern Territory. It has very similar stratigraphy and structural features to the nearby Amadeus, Ngalia and southern Georgina Basins. They all contain fluvio-deltaic to marine sediments of Late Proterozoic to Carboniferous age and were subjected to deformation during several major periods of folding and overthrusting. They are remnants of one depositional basin which covered much of Northern Australia in the Late Proterozoic and Early Palaeozoic Eras. Producing oil and gas fields occur in the Amadeus Basin and there are many oil and gas occurrences in the southern Georgina and Ngalia Basins. The Lander Trough contains up to 3000 metres of largely marine clastic and carbonate sediments which are expected to include mature source rocks and effective reservoirs and seals. Adequate migration paths and trapping mechanisms are believed to be present. The Lander Trough has the potential for commercial petroleum discoveries.

GAS DISPLACEMENT: AN IMPORTANT CONTROL ON OIL AND GAS DISTRIBUTION IN THE TIMOR SEA?

1997 ◽  
Vol 37 (1) ◽  
pp. 259 ◽  
Author(s):  
M. Lisle ◽  
G. W. O'Brien ◽  
M. P. Brincat
Keyword(s):  
Oil And Gas ◽  
Dew Point ◽  
Oil Accumulation ◽  
Gaseous Hydrocarbon ◽  
Fault Block ◽  
Point Pressure ◽  
Timor Sea ◽  
Original Oil In Place ◽  
Dew Point Pressure ◽  
Gas Fields

A study of gas fields in the Timor Sea has shown that these traps often contain palaeo-oil columns, with a high abundance of oil bearing fluid inclusions recorded in sands which are presently gas saturated. These palaeo- oil columns are substantial, suggesting the volume of liquid hydrocarbons that has been redistributed is significant. This remobilised oil in effect constitutes an oil charge of known volume for nearby structures, with seismic mapping confidently allowing the recognition of remigration fairways into up-dip traps. For example, at Oliver-1, a 115 m relict oil column, equating to original oil in place of over 166 MMBBL, has been identified. However, estimates of current oil in place account for less than 45 MMBBL, suggesting that more than 120 MMBBL of oil has been displaced across the spill point of the Oliver structure. Remigration of this oil can be mapped into an adjacent fault block, representing a new exploration play. Significantly, the likelihood of this untested trap containing liquids is supported by the presence of an oil leg at Oliver-1, which shows that only oil has been displaced from the Oliver trap.At Keeling-1, a smaller palaeo-oil accumulation has been detected which equates to about 14 MMBBL originally in place. However, the mechanisms responsible for the passage from palaeo-oil accumulation to the present gaseous hydrocarbon phase are often complex and decisions regarding a potential oil leg need be made judiciously. For example, at Keeling-1, oil shows and hydrocarbon related diagenesis in the overlying section provide compelling evidence that oil was lost due to fault breach rather than gas displacement.In contrast, a lack of evidence for palaeo-oil accumulation at Sunrise-1 and Troubadour-1 is also significant, as it removes the potential for an oil leg displaced either down-dip within the same structure or as a remigrated oil charge to adjacent up-dip structures. Significantly, these fields presently contain condensate and would have existed as separate oil and gas legs if charge occurred before dew point pressure was reached. The absence of a palaeo-oil column implies that the traps were charged after formation pressures exceeded the dew point of the reservoired gas. At Troubadoirr-1, this observation constrains the time of charge to the last 5-10 Ma, when pressures within the trap are estimated to have reached dew point.

scholarly journals About this title

1991 ◽  
Vol 14 (1) ◽  
pp. NP-NP ◽  
Keyword(s):  
United Kingdom ◽  
Oil And Gas ◽  
Hydrocarbon Exploration ◽  
Oil And Gas Fields ◽  
The United Kingdom ◽  
Exploration And Production ◽  
Moray Firth ◽  
The Uk ◽  
Hydrocarbon Exploration And Production ◽  
Gas Fields

The United Kingdom Oil and Gas Fields has been produced to commemorate the first 25 years of hydrocarbon exploration and production in the United Kingdom North Sea. The result of this exploration has produced many benefits for the UK, its government and industry but above all for geologists and geophysicists, Articles on the 64 oil and gas fields discovered on the United Kingdom Continental Shelf are given in a standardized layout to provide easy to use databook for the petroleum geologist and geophysicist. The producing oil and gas fields have been arranged into:the Viking Graben, the Central Graben and Moray Firth, the Southern Gas Basin and Morecambe Basin. Also included are two introductory articles, the first sets the fields in a historical perspect!ve and the second places them in a stratigraphic framework.

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