NEOGENE TECTONICS IN SE AUSTRALIA: IMPLICATIONS FOR PETROLEUM SYSTEMS

2001 ◽  
Vol 41 (1) ◽  
pp. 37 ◽  
Author(s):  
J.A. Dickinson ◽  
M.W. Wallace ◽  
G.R. Holdgate ◽  
J. Daniels ◽  
S.J. Gallagher ◽  
...  
Keyword(s):  
Late Miocene ◽  
Oil And Gas ◽  
Petroleum Exploration ◽  
Petroleum Systems ◽  
Australian Plate ◽  
Late Tertiary ◽  
Petroleum Generation ◽  
History Of ◽  
Petroleum Accumulation ◽  
Gippsland Basin

The influence of Neogene tectonics in the SE Australian basins has generally been underestimated in the petroleum exploration literature. However, onshore stratigraphic and offshore seismic data indicates that significant deformation and exhumation (up to one km or more) has occurred during the late Tertiary-Quaternary. This tectonism coincides with a change in the dynamics of the Australian plate, beginning at around 12 Ma, resulting in a WNW–ESE compressional regime which has continued to the present day.Significant late Miocene tectonism is indicated by a regional angular unconformity at around the Mio-Pliocene boundary in the onshore and nearshore successions of the SE Australian basins.Evidence of on going Pliocene- Quaternary tectonism is widespread in all of the SE Australian basins. Late Tertiary tectonism has produced structures in the offshore SE Australian basins which have been favourable targets for petroleum accumulation (e.g. Nerita structure, Torquay Sub-basin; Cormorant structure, Bass Basin). In the offshore Gippsland Basin, most of the oil- and gas-bearing structures have grown during Oligocene-Recent time. Some Gippsland Basin structures were largely produced prior to the mid- Miocene, while others have a younger structural history. In areas of intense late Tertiary exhumation and uplift (e.g. proximal to the Otway and Strzelecki Ranges), burial/maturation models of petroleum generation may be significantly affected by Neogene uplift.Many structures produced by late Miocene-Pliocene deformation are dry. These relatively young structures may post-date the major maturation episodes, with the post-structure history of the basins dominated by exhumation and cooling.

About this title - Application of Analytical Techniques to Petroleum Systems

10.1144/sp484 ◽  
2020 ◽  
Vol 484 (1) ◽  
pp. NP-NP
Author(s):  
Patrick J. Dowey ◽  
Mark Osborne ◽  
Herbert Volk
Keyword(s):  
Oil And Gas ◽  
Organic Geochemistry ◽  
Analytical Techniques ◽  
Petroleum Exploration ◽  
Electricity Production ◽  
Sediment Provenance ◽  
Chemical Production ◽  
Petroleum Systems ◽  
Wide Range ◽  
Analytical Approaches

Cutting-edge techniques have always been utilized in petroleum exploration and production to reduce costs and improve efficiencies. The demand for petroleum in the form of oil and gas is expected to increase for electricity production, transport and chemical production, largely driven by an increase in energy consumption in the developing world. Innovations in analytical methods will continue to play a key role in the industry moving forwards as society shifts towards lower carbon energy systems and more advantaged oil and gas resources are targeted. This volume brings together new analytical approaches and describes how they can be applied to the study of petroleum systems. The papers within this volume cover a wide range of topics and case studies, in the fields of fluid and isotope geochemistry, organic geochemistry, imaging and sediment provenance. The work illustrates how the current, state-of-the-art technology can be effectively utilised to address ongoing challenges in petroleum geoscience.

PESA Australian exploration review 2018

2019 ◽  
Vol 59 (2) ◽  
pp. 493
Author(s):  
D. Lockhart ◽  
D. Spring
Keyword(s):  
Oil And Gas ◽  
Petroleum Exploration ◽  
3D Seismic ◽  
The North ◽  
Second Year ◽  
Gippsland Basin ◽  
2D And 3D ◽  
Conventional Oil ◽  
Exploration Activity ◽  
Offshore Petroleum

Available data for 2018 indicates that exploration activity is on the rise in Australia, compared to 2017, and this represents a second year of growth in exploration activity in Australia. There has been an increase in area under licence by 92 000 km2, reversing the downward trend in area under licence that commenced in 2014. Since 2016, exploratory drilling within Australia has seen a continued upward trend in both the number of wells drilled and the percentage of total worldwide. Onshore, 77 conventional exploration and appraisal wells were spudded during the year. Offshore, exploration and appraisal drilling matched that seen in 2017, with five new wells spudded: two in the Roebuck Basin, two in the Gippsland Basin and one in the North Carnarvon Basin. Almost 1500 km of 2D seismic and over 10 000 km2 of 3D seismic were acquired within Australia during 2018, accounting for 2.4% and 3.9% of global acquisition, respectively. This represents an increase in the amount of both 2D and 3D seismic acquired in Australia compared with 2017. Once the 2017 Offshore Petroleum Acreage Release was finalised, seven new offshore exploration permits were awarded as a result. A total of 12 bids were received for round one of the 2018 Offshore Petroleum Exploration Release, demonstrating an increase in momentum for offshore exploration in Australia. The permits are in Commonwealth waters off Western Australia, Victoria and the Ashmore and Cartier islands. In June 2018, the Queensland Government announced the release of 11 areas for petroleum exploration acreage in onshore Queensland, with tenders closing in February/March 2019; a further 11 areas will be released in early 2019. The acreage is a mix of coal seam gas and conventional oil and gas. Victoria released five areas in the offshore Otway Basin within State waters. In the Northern Territory, the moratorium on fracking was lifted in April, clearing the way for exploration to recommence in the 2019 dry season. With the increase in exploration has come an increase in success, with total reserves discovered within Australia during 2018 at just under 400 million barrels of oil equivalent, representing a significant increase from 2017. In 2018, onshore drilling resulted in 18 new discoveries, while offshore, two new discoveries were made. The most notable exploration success of 2018 was Dorado-1 drilled in March by Quadrant and Carnarvon Petroleum in the underexplored Bedout Sub-basin. Dorado is the largest oil discovery in Australia of 100 million barrels, or over, since 1996 and has the potential to reinvigorate exploration in the region.

THE SIGNIFICANCE OF SURFACE INDICATIONS OF PETROLEUM

1971 ◽  
Vol 11 (1) ◽  
pp. 126
Author(s):  
C. P. Meakin
Keyword(s):  
Gas Chromatography ◽  
Oil And Gas ◽  
Oil Fields ◽  
Petroleum Exploration ◽  
Hydrocarbon Gases ◽  
Geochemical Prospecting ◽  
Petroleum Accumulation ◽  
Petroleum Field ◽  
Gaseous Hydrocarbons ◽  
Gas Seeps

Seeps are of interest to the petroleum geologist because:—they indicate a section capable of producing hydrocarbons, and very often are related to a petroleum accumulation, andmany of the Important oil-producing regions were discovered by surface indications of petroleum.There are five main types of seeps:- those emerging from homoclinal beds exposed at the surface; those associated with beds in which the oil was formed; those arising from definite large petroleum accumulations, either bared by erosion, or ruptured by faulting; those emerging at an unconformity; and those associated with intrusions. These types of seeps are associated with, and have led to the discovery of many major oil fields throughout the world.The reports of oil and gas seeps in Australia, however, are only meagre. This may be because:—of a lack of exploration and documentation,the basins are a type that do not have the conditions necessary to produce seeps,the seeps that do exist are unrecognized. For instance, even large gas seeps may pass unnoticed in dry areas,of a lack of petroleum.The detection of the gaseous hydrocarbons, methane, ethane, propane and the butanes, in soils by gas chromatography could aid petroleum exploration because:—it would enable the detection of gas seeps over a potential petroleum field that would otherwise remain undetected, andeven for small quantities of hydrocarbon gases, low ratios of methane to higher hydrocarbons indicate a petroliferous origin.This is the technique of geochemical prospecting. It is based on three assumptions:—It must be possible for the hydrocarbons to migrate to the surface.The concentration of migrating hydrocarbons should not be altered by chemical reaction, bacteria, or hydrocarbons derived from another source.An anomalous hydrocarbon concentration at the surface can be correlated with a petroleum deposit.A search of the literature shows that, on the whole, these assumptions are correct. It would therefore appear that geochemical prospecting, particularly when used in conjunction with geological and geophysical work, can be useful for locating petroleum deposits.

PETROLEUM SYSTEMS IN TASMANIA'S FRONTIER ONSHORE BASINS

2000 ◽  
Vol 40 (1) ◽  
pp. 26
Author(s):  
M.R. Bendall C.F. Burrett ◽  
H.J. Askin
Keyword(s):  
Oil And Gas ◽  
Source Rocks ◽  
Petroleum Exploration ◽  
Late Triassic ◽  
Upper Permian ◽  
Lower Permian ◽  
Peak Oil ◽  
Petroleum Systems ◽  
Upper Proterozoic ◽  
Oil Seep

Sedimentary successions belonging to three petroleum su persy stems can be recognised in and below the Late Carboniferous to Late Triassic onshore Tasmania Basin. These are the Centralian, Larapintine and Gondwanan. The oldest (Centralian) is poorly known and contains possible mature source rocks in Upper Proterozoic dolomites. The Larapintine 2 system is represented by rocks of the Devonian fold and thrust belt beneath the Tasmania Basin. Potential source rocks are micrites and shales within the 1.8 km-thick tropical Ordovician Gordon Group carbonates. Conodont CAI plots show that the Gordon Group lies in the oil and gas windows over most of central Tasmania and probably under much of the Tasmania Basin. Potential reservoirs are the upper reefal parts of the Gordon Group, paleokarsted surfaces within the Gordon Group and the overlying sandstones of the Siluro-Devonian Tiger Range and Eldon Groups. Seal rocks include shales within the Siluro-Devonian and Upper Carboniferous-Permian tillites and shales.The Gondwanan supersystem is the most promising supersystem for petroleum exploration within the onshore Tasmania Basin. It is divided into two petroleum systems— the Early Permian Gondwanan 1 system, and the Late Permian to Triassic Gondwanan 2 system. Excellent source rocks occur in the marine Tasmanite Oil Shale and other sections within the Lower Permian Woody Island and Quamby Formations of the Gondwanan 1 system and within coals and freshwater oil shales of the Gondwanan 2 system. These sources are within the oil and gas windows across most of the basin and probably reached peak oil generation at about 100 Ma. An oil seep, sourced from a Tasmanites-rich, anoxic shale, is found within Jurassic dolerite 40 km WSW of Hobart. Potential Gondwanan 1 reservoirs are the glaciofluvial Faulkner Group sandstones and sandstones and limestones within the overlying parts of the glaciomarine Permian sequence. The Upper Permian Ferntree Mudstone Formation provides an effective regional seal. Potential Gondwanan 2 reservoirs are the sandstones of the Upper Permian to Norian Upper Parmeener Supergroup. Traps consisting of domes, anticlines and faults were formed probably during the Early Cretaceous. Preliminary interpretation of a short AGSO seismic profile in the Tasmania Basin shows that, contrary to earlier belief, structures can be mapped beneath extensive and thick (300 m) sills of Jurassic dolerite. In addition, the total section of Gondwana to Upper Proterozoic to Triassic sediments appears to be in excess of 8,500 m. These recent studies, analysis of the oil seep and drilling results show that the Tasmanian source rocks have generated both oil and gas. The Tasmania Basin is considered prospective for both petroleum and helium and is comparable in size and stratigraphy to other glaciomarine-terrestrial Gondwanan basins such as the South Oman and Cooper Basins.

Revisiting petroleum systems in the Gippsland Basin using new geochemical data

2010 ◽  
Vol 50 (2) ◽  
pp. 728 ◽  
Author(s):  
Herbert Volk ◽  
Manzur Ahmed ◽  
Chris Boreham ◽  
Peter Tingate ◽  
Neil Sherwood ◽  
...  
Keyword(s):  
Molecular Weight ◽  
Fluid Inclusions ◽  
Isotope Geochemistry ◽  
Isotopic Analysis ◽  
Oil Field ◽  
Geochemical Data ◽  
Molecular Weight Range ◽  
Petroleum Systems ◽  
History Of ◽  
Gippsland Basin

The Gippsland Basin is one of the most prolific petroleum provinces in Australia, yet the understanding of source, migration and secondary alteration of petroleum is often based on data and concepts that have been developed decades ago. For instance, the Gippsland Basin is commonly cited as an explicit example of a province dominated by oil from coal, yet there is no literature using molecular and isotope geochemistry explicitly demonstrating that generation and expulsion has been from the coal seams and not the intervening carbonaceous mudstones. In this study we will present insights from the evaluation of quantitative analyses of aromatic hydrocarbons, which will be evaluated together with low molecular weight hydrocarbon distributions from whole oil gas chromatography and aliphatic biomarker distributions of the oils. Oils are commonly incrementors of different charge events, and hence extending molecular and isotopic information from a wide molecular weight range offers a more detailed insight into the charge history of an oil field. Oil-bearing fluid inclusions are additional archives that hold keys to the fill history of petroleum reservoirs, and this contribution will also present new data on the distribution and composition of palaeo-oils trapped in fluid inclusions. Lastly, examples will be presented of how modern tools for analysis such as compound specific isotopic analysis (CSIA) of n-alkanes and isoprenoids as well as how understanding relationships between organic facies and source rock kinetics can contribute to refining our understanding of petroleum systems in the Gippsland Basin.

REVIEW OF AUSTRALIAN PETROLEUM EXPLORATION, 1967

1968 ◽  
Vol 8 (1) ◽  
pp. 8
Author(s):  
R. C. Sprigg
Keyword(s):  
Natural Gas ◽  
Western Europe ◽  
Oil And Gas ◽  
Petroleum Exploration ◽  
Search Pattern ◽  
Significant Feature ◽  
Field Development ◽  
Development Costs ◽  
Drilling Rigs ◽  
Gippsland Basin

In Australia, 1967 can aptly be termed the year of the impending energy revolution. The long-awaited upturn in the rate of oil and gas discovery eventuated and was successfully associated with a decided swing to concentration of effort on the continental shelf.Natural gas has dominated the discovery scene to such an extent that if experience in Western Europe is taken as a guide line, natural gas can be expected to supply 20 per cent of the local energy market within the next decade. This is expected to be accomplished primarily at the expense of oil, to a lesser extent of black coal and finally of brown coal. Natural gas will erode only the growth rate of these latter fuels.Natural gas will arrive in about March, 1969, at Melbourne, Brisbane, and Adelaide from the Barracouta, Roma and Gidgealpa-Moomba fields respectively. Gas reserves at Gilmore, Mereenie and Dongara remained undeveloped due principally to market difficulties. Recently a discovery has been made in the Gulf of Papua.Crude oil production from the Moonie-Alton fields increased to more than 8,750 b.p.d. during the year, and deliveries commenced from Barrow Island with production rising to 25,000 b.p.d. by the end of the year. The Marlin, Kingfish and Halibut fields in Bass Strait are expected to be in production by mid-1969.The heavy swing of exploration interest to the continental shelf was probably the most significant feature in the year's search pattern. The remarkable rate of success in the offshore Gippsland Basin was the major factor, but the Barrow-Pasco Island success strengthened this trend. The availability for the first time in Australia of a number of offshore drilling rigs, supported by greatly improved techniques in marine exploration, led to the explosion of interest in this exciting sphere. Despite this, exploration and development costs are considerably less on land, and many major basins remain very poorly explored. Important discoveries in onshore basins must be expected in the future.The passage of new offshore legislation will markedly influence future patterns of exploration. The extent to which this will result in diversification of exploration interest remains to be seen.Oil well statistics on footage drilled indicate an increase of about 43 per cent over the 1966 total, bringing the total footage figure to just over one million feet. Closer examination of these figures, however, discloses a disquieting drop in new exploration footage at the expense of field development wells. Moreover, offshore wells are being drilled to greater total depths. Of 274 wells drilled in 1967, 187 were developmental and 87 exploratory. This compares with 134 wells in 1966 of which 97 were exploratory.In conclusion it would appear that the events of 1967 have pointed to Australia becoming self-sufficient in oil by the mid-1970s, providing present discovery rates are maintained. By that time natural gas is expected to be supplying 20 per cent of the total energy requirements. All of which highlights the probability that 1968 will see the Federal Government looking far more closely at the long-term pricing of Australian crude and the eventual review of incentive formulas.

Understanding the plumbing of the Gippsland Basin: new results on fluid migration and reservoir quality

2011 ◽  
Vol 51 (2) ◽  
pp. 693
Author(s):  
Peter Tingate ◽  
Monica Campi ◽  
Geoffrey O'Brien ◽  
John Miranda ◽  
Louise Goldie Divko ◽  
...  
Keyword(s):  
Co2 Storage ◽  
Fluid Migration ◽  
Gas Field ◽  
Reservoir Characteristics ◽  
Petroleum Systems ◽  
Migration History ◽  
History Of ◽  
Hydrocarbon Charge ◽  
Gippsland Basin ◽  
Migration Pathways

Understanding the CO2 storage potential and petroleum prospectivity of the Gippsland Basin are critical to managing the resources of this region. Key controls on determining the prospectivity for CO2 storage and petroleum include understanding the fluid migration history and reservoir characteristics in the basin. Gippsland Basin hydrology, reservoir characteristics and petroleum systems are being studied to better understand how CO2 can be safely stored in the subsurface. Hydrocarbon migration pathways have been delineated using petroleum systems modelling. The latest hydrocarbon charge history data has been acquired to test the containment potential of individual structures along these migration pathways. The charge history results indicate the Golden Beach gas field has had a complex hydrocarbon fill history, and that early charge has migrated through the regional seal. The results also indicate that early oil charge was very common in the basin, including large structures that are now filled with gas (e.g. Barracouta). The results allow the regions with good CO2 containment potential to be delineated for further storage investigations. A new evaluation of the reservoir characteristics of the Latrobe Group—through porosity/permeability analysis and automated mineral analysis (AMA)—has provided insights into CO2 injectivity and capacity. The AMA results constrain the mineralogy and diagenetic history of the reservoirs and seals. In addition, the data highlights the presence of carbonates, glauconite and K-feldspar that are potentially reactive with injected CO2.

Java Volcanic Arc, what lies beneath?

2021 ◽  
Author(s):  
E. Septama
Keyword(s):  
Oil And Gas ◽  
Structural Complexity ◽  
Magnetic Data ◽  
Southern Boundary ◽  
Volcanic Arc ◽  
Rock Samples ◽  
Petroleum Systems ◽  
Gravity And Magnetic ◽  
Petroleum Generation ◽  
Gravity And Magnetic Data

Java Island is an active volcanic arc that resides in the southwestern - southern boundary of Sundaland edges. The volcanic arc consists of several volcanism episodes, with a relatively younging trend northward (Late Oligocene to Pleistocene), following the Indo-Australian plates inward migration. In contrast to the prolific neighboring Northwest and Northeast Java Basins in the Northern edges of Java Island; the basin reconstruction and development in the East-West trending depression in median ranges of Java (from Bogor to Kendeng Troughs) are overlooked and lays bare the challenge to the seismic imaging due to the structural complexity of the overthrusted Neogene unit as well as immense Quaternary volcanic eruption covers. On the other hand, oil and gas seepages around the northern and central parts of the Island confirmed the active petroleum generation. Five focused window areas are selected for this study. A total of 1,893 Km sections, 584 rock samples, 1569 gravity, and magnetic data, and 29 geochemical samples (rocks, oil, and gas samples) were acquired during the study. Geological fieldwork was focused on the stratigraphic unit composition and the observable features of deformation products from the outcrops. Due to the scarcity of the Paleogene deposit exposure in the Central-East Java area, the rock samples were also collected from the mud volcano ejected materials in the Sangiran Dome. Both Bogor and Kendeng Troughs are active petroleum systems that generate type II /III Kerogen typical to the reduction organic material derived from transition to the shallow marine environment. The result suggests that these basins are secular from the neighboring basins, The Northwest and Northeast Java Basins, characterized by oxidized terrigenous type III Kerogen. The contrasting subsurface configuration between Bogor and Kendeng Troughs mainly concerns the fold-thrust belt basement involvement and the tectonic shortening effect on the formerly rift basin.

scholarly journals Mackenzie-Peel Platform and Ellesmerian Foreland Composite Tectono-Sedimentary Element, northwestern Canada

2021 ◽  
pp. M57-2016-5
Author(s):  
Karen M. Fallas ◽  
Robert B. MacNaughton ◽  
Peter K. Hannigan ◽  
Bernard C. MacLean
Keyword(s):  
Oil And Gas ◽  
Early Carboniferous ◽  
Oil Field ◽  
Passive Margin ◽  
Petroleum Exploration ◽  
Rock Formations ◽  
Devonian Shale ◽  
History Of ◽  
The One ◽  
Uplift And Erosion

AbstractThe Mackenzie-Peel Platform tectono-sedimentary element, and the overlying Ellesmerian Foreland tectono-sedimentary element, consist of Cambrian to Early Carboniferous shelf and slope sedimentary deposits in Canada&s northern Interior Plains. In this chapter, these elements are combined into the Mackenzie-Ellesmerian Composite Tectono-Sedimentary Element. The history of the area includes early extensional faulting and subsidence in the Mackenzie Trough, passive margin deposition across the Mackenzie-Peel Platform, local uplift and erosion along the Keele Arch, subsidence and deposition in the Ellesmerian Foreland, possible minor folding during the Ellesmerian Orogeny, and folding and faulting in Cretaceous to Eocene time associated with the development of the Canadian Cordillera. Recorded petroleum discoveries are within Cambrian sandstone (Mount Clark Formation), Devonian carbonate strata (Ramparts and Fort Norman formations), and Devonian shale (Canol Formation). Additional oil and gas shows are documented from Cambrian to Silurian carbonate units (Franklin Mountain and Mount Kindle formations), Devonian carbonate units (Arnica, Landry, and Bear Rock formations), and Late Devonian to Early Carboniferous siliciclastic units (Imperial and Tuttle Formations). Petroleum exploration activity within the area has occurred in several phases since 1920, most of it associated with the one producing oil field at Norman Wells.

HYDROCARBON PROSPECTIVITY OF THE DEEPWATER GIPPSLAND BASIN, VICTORIA, AUSTRALIA

2001 ◽  
Vol 41 (1) ◽  
pp. 91 ◽  
Author(s):  
T. Bernecker ◽  
M.A. Woollands ◽  
D. Wong ◽  
D.H. Moore ◽  
M.A. Smith
Keyword(s):  
Source Rock ◽  
Oil And Gas ◽  
Data Sets ◽  
Hydrocarbon Generation ◽  
The North ◽  
Potential Source Rock ◽  
Exploration And Production ◽  
Modelling Studies ◽  
History Of ◽  
Gippsland Basin

After 35 years of successful exploration and development, the Gippsland Basin is perceived as a mature basin. Several world class fields have produced 3.6 billion (109) BBL (569 GL) oil and 5.2 TCF (148 Gm3) gas. Without additional discoveries, it is predicted that further significant decline in production will occur in the next decade.However, the Gippsland Basin is still relatively underexplored when compared to other prolific hydrocarbon provinces. Large areas are undrilled, particularly in the eastern deepwater part of the basin. Here, an interpretation of new regional aeromagnetic and deep-water seismic data sets, acquired through State and Federal government initiatives, together with stratigraphic, sedimentological and source rock maturation modelling studies have been used to delineate potential petroleum systems.In the currently gazetted deepwater blocks, eight structural trapping trends are present, each with a range of play types and considerable potential for both oil and gas. These include major channel incision plays, uplifted anticlinal and collapsed structures that contain sequences of marine sandstones and shales (deepwater analogues of the Marlin and Turrum fields), as well as large marine shale-draped basement horsts.The study has delineated an extensive near-shore marine, lower coastal plain and deltaic facies association in the Golden Beach Subgroup. These Late Cretaceous strata are comparable to similar facies of the Tertiary Latrobe Siliciclastics and extend potential source rock distribution beyond that of previous assessments. In the western portion of the blocks, overburden is thick enough to drive hydrocarbon generation and expulsion. The strata above large areas of the source kitchen generally dip to the north and west, promoting migration further into the gazetted areas.Much of the basin’s deepwater area, thus, shares the deeper stratigraphy and favourable subsidence history of the shallow water producing areas. Future exploration and production efforts will, however, be challenged by the 200–2500 m water-depths and local steep bathymetric gradients, which affect prospect depth conversion and the feasibility of development projects in the case of successful exploration.

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