PRE-EOCENE STRATIGRAPHY, STRUCTURE, AND PETROLEUM POTENTIAL OF THE BASS BASIN

1985 ◽  
Vol 25 (1) ◽  
pp. 362 ◽  
Author(s):  
P.E. Williamson ◽  
C.J. Pigram ◽  
J.B. Colwell ◽  
A.S. Scherl ◽  
K.L. Lockwood ◽  
...  
Keyword(s):  
Mineral Resources ◽  
Hydrocarbon Exploration ◽  
Source Rocks ◽  
Seismic Survey ◽  
Normal Faults ◽  
Petroleum Potential ◽  
Northerly Direction ◽  
Potential Reservoir ◽  
Well Data ◽  
Coal Measures

Exploration in the Bass Basin has mainly concentrated on the Eocene part of the Eastern View Coal Measures with the pre-Eocene stratigraphy hardly being tested. Structural mapping using a good quality Bureau of Mineral Resources regional seismic survey and infill industry seismic data, in conjunction with seismic stratigraphy and well data, has generated an understanding of the structure and stratigraphy of the pre- Eocene basin, which suggests that exploration potential exists in structural and stratigraphic leads of both Paleocene and Cretaceous age.The Paleocene structure is influenced by the reactivation of normal faults developed at the time of the mid Cretaceous rift unconformity and reflects drape over deeper features. Consequently fault dependent structural closures often persist from Paleocene to (?)Jurassic levels. Possible stratigraphic traps are also observed against horst blocks and around the basin margins. The longitudinal fault directions are northwest and west northwest with an oblique northerly direction and a prevailing north northeasterly transverse direction.The Paieocene and Upper Cretaceous part of the Eastern View Coal Measures consists of sands, shales and coals deposited in alluvial fans, on flood plains, and in lakes. These are underlain by Early Cretaceous Otway Groups, sands, shales and volcanics. Both intervals have potential reservoir and source rocks and often occur at mature depths. No pre-Otway Group sediments have been encountered in wells in the Bass Basin. However, the Permo- Carboniferous and possibly Triassic strata that occur in Northern Tasmania exhibit reservoir and source rock potential and may extend offshore beneath the Bass Basin.Pre-Eocene structural and stratigraphic studies of the Bass Basin thus point to reservoir and hydrocarbon source potential for possible multiple hydrocarbon exploration targets.

A REVIEW OF RECENT GEOLOGICAL WORK IN THE OFFICER BASIN, SOUTH AUSTRALIA

1980 ◽  
Vol 20 (1) ◽  
pp. 209 ◽  
Author(s):  
G.M. Pitt ◽  
M.C. Benbow ◽  
Bridget C. Youngs
Keyword(s):  
South Australia ◽  
Source Rocks ◽  
Organic Carbon Content ◽  
Petroleum Potential ◽  
Geological Surveys ◽  
Potential Source ◽  
Potential Reservoir ◽  
Carbonate Sequence ◽  
Geological Work ◽  
Australian Department

The Officer Basin of South and Western Australia, in its broadest definition, contains a sequence of Late Proterozoic to pre-Permian strata with an unknown number of stratigraphic breaks. Recent investigations by the South Australian Department of Mines and Energy (SADME), which included helicopter-based geological surveys and stratigraphic drilling, have upgraded the petroleum potential of the basin.SADME Byilkaoora-1, drilled in the northeastern Officer Basin in 1979, contained hydrocarbon shows in the form of oil exuding from partly sealed vugs and fractures in argillaceous carbonates. Equivalent carbonates were intersected in SADME Marla-1A and 1B. Previously, in 1976, SADME Murnaroo-1 encountered shales and carbonates with moderate organic carbon content overlying a thick potential reservoir sandstone, while SADME Wilkinson-1, drilled in 1978, contained a carbonate sequence with marginally mature to mature oil-prone source rocks. Acritarchs extracted from the last mentioned carbonates indicate an Early Cambrian age.All ?Cambrian carbonate sequences recognised to date in the Officer Basin of South Australia are correlated with the Observatory Hill Beds, which are now considered to be the major potential source of petroleum in the eastern Officer Basin.

TECTONIC CONTROLS ON SEDIMENTATION AND MATURATION IN THE OFFSHORE NORTH PERTH BASIN

1989 ◽  
Vol 29 (1) ◽  
pp. 450 ◽  
Author(s):  
John F. Marshall ◽  
Chao- Shing Lee ◽  
Douglas C. Ramsay ◽  
Aidan M.G. Moore
Keyword(s):  
Seismic Reflection ◽  
Source Rocks ◽  
Hydrocarbon Generation ◽  
Late Permian ◽  
Early Permian ◽  
The West ◽  
Australian Continent ◽  
Multichannel Seismic Reflection ◽  
Well Data ◽  
Coal Measures

The major tectonic and stratigraphic elements of the offshore North Perth Basin have been delineated from regional BMR multichannel seismic reflection lines, together with industry seismic and well data. This analysis reveals that three sub- basins, the Edel, Abrolhos and Houtman Sub- basins, have formed as a result of three distinct episodes of rifting within the offshore North Perth Basin during the Early Permian, Late Permian and Late Jurassic respectively. During this period, rifting has propagated from east to west, and has culminated in the separation of this part of the Australian continent from Greater India.The boundaries between the sub- basins and many structures within individual sub- basins are considered to have been produced by strike- slip or oblique- slip motion. The offshore North Perth Basin is believed to be a product of transtension, possibly since the earliest phase of rifting. This has culminated in separation and seafloor spreading by oblique extension along the Wallaby Fracture Zone to form a transform passive continental margin.This style of rifting and extension has produced relatively thin syn- rift sequences, some of which have been either partly or completely removed by erosion. While the source- rock potential of the syn- rift phase is limited, post- rift marine transgressional phases and coal measures do provide adequate and relatively widespread source rocks for hydrocarbon generation. Differences in the timing of rifting across the basin have resulted in a maturation pattern whereby mature sediments become younger to the west.

Pre-Messinian Petroleum Systems and Trap Style in the Offshore Western of Nile Delta; An Integrated Geological and Geophysical Approach

2016 ◽  
Author(s):  
Mostafa Monir ◽  
Omar Shenkar
Keyword(s):  
Seismic Data ◽  
Nile Delta ◽  
Lower Pressure ◽  
Hydrocarbon Exploration ◽  
Source Rocks ◽  
Geochemical Data ◽  
Peak Oil ◽  
West Nile ◽  
Petroleum Systems ◽  
Well Data

ABSTRACT Exploration in the offshore Nile Delta province has revealed several hydrocarbon plays. Deep marine Turbidites is considered one of the most important plays for hydrocarbon exploration in the Nile Delta. These turbidites vary from submarine turbidite channels to submarine basin floor fans. An integrated exploration approach was applied for a selected area within West Delta Deep Marine (WDDM) Concession offshore western Nile Delta using a variety of geophysical, geological and geochemical data to assess the prospectivity of the Pre-Messinian sequences. This paper relies on the integration of several seismic data sets for a new detailed interpretation and characterization of the sub-Messinian structure and stratigraphy based on regional correlation of seismic markers and honoured the well data. The interpretation focused mainly on the Oligocene and Miocene mega-sequences. The seismic expression of stratigraphic sequences shows a variety of turbidite channel/canyon systems having examples from West Nile delta basin discoveries and failures. The approach is seismically based focusing on seismic stratigraphic analysis, combination of structure and stratigraphic traps and channels interpretation. Linking the geological and geophysical data together enabled the generation of different sets of geological models to reflect the spatial distribution of the reservoir units. The variety of tectonic styles and depositional patterns in the West Nile delta provide favourable trapping conditions for hydrocarbon generations and accumulations. The shallow oil and gas discoveries in the Pliocene sands and the high-grade oils in the Oligo-Miocene and Mesozoic reservoirs indicate the presence of multiple source rocks and an appropriate conditions for hydrocarbon accumulations in both biogenic and thermogenic petroleum systems. The presence of multi-overpressurized intervals in the Pliocene and Oligo-Miocene Nile delta stratigraphic column increase the depth oil window and the peak oil generation due to decrease of the effective stress. Fluids have the tendency to migrate from high pressure zones toward a lower pressure zones, either laterally or vertically. Also, hydrocarbons might migrate downward if there is a lower pressure in the deeper layers. Well data and the available geochemical database have been integrated with the interpreted seismic data to identify potential areas of future prospectivity in the study area.

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.

RECENT SEISMIC STUDIES UPGRADE THE PETROLEUM PROSPECTS OF THE TOKO SYNCLINE, GEORGINA BASIN

1979 ◽  
Vol 19 (1) ◽  
pp. 30
Author(s):  
P.L. Harrison
Keyword(s):  
Mineral Resources ◽  
Seismic Survey ◽  
Fault System ◽  
Reverse Fault ◽  
Middle Cambrian ◽  
Middle Ordovician ◽  
Upper Cambrian ◽  
Marine Carbonate ◽  
Potential Reservoir ◽  
Northeastern Flank

The Georgina Basin covers an area of 325,000 sq km in the Northern Territory and Queensland. Most of the basin contains less than 500m of Palaeozoic sediments, but the Toko Syncline, in Queensland, contains up to 5000m of Middle Cambrian to Middle Ordovician shallow marine carbonate, sandstone and shale. The syncline is bounded on its western margin by the Toomba-Craigie Fault systemHydrocarbon shows are known within the Middle Cambrian to Middle Ordovician strata and some of the rocks have fair source rock potential. Potential reservoir rocks are vuggy dolostones and sandstone. Ordovician siltstones and shales may provide cap-rocks. The southern, deepest part of the syncline appears to have been protected from flushing. AOD Ethabuka-I well, drilled in the southern part, encountered gas in the Ordovician, but drilling problems prevented penetration of the deeper section.A Bureau of Mineral Resources (BMR) seismic survey in 1977, linked lines shot on earlier surveys, tied to wells and examined the Toomba Fault system. The results show that two previously unidentified reflectors represent the top of Upper Cambrian Georgina Limestone and the base of the Middle Cambrian section. Substantial thickening of Ordovician and slight thinning of Middle and Upper Cambrian strata occurs southeast along the axis of the syncline. Southeast progradation of some Middle Cambrian strata and possible bioherms were observed. The Toomba Fault is a high-angle reverse fault and several possible anticlines are present in the adjacent folded and faulted zone. The two largest ones, the Ethabuka and Mirrica Structures, were partially outlined by Alliance Oil Development (AOD). They are shown to lie within a larger structure which has a minimum vertical closure of 700m over a minimum area of 130 sq km. Possible stratigraphic traps are located on the northeastern flank and along the axis of the syncline.The seismic work has better defined the prospective section and confirmed closure on a large structure. The next step in exploration should be to drill the Mirrica-Ethabuka Structure, where about 1500m of section remains to be tested.

APPLICATION OF THE DETACHMENT MODEL FOR CONTINENTAL EXTENSION TO HYDROCARBON EXPLORATION IN EXTENSIONAL BASINS

1989 ◽  
Vol 29 (2) ◽  
pp. 99
Author(s):  
M. A. Etheridge ◽  
P. A. Symonds ◽  
T. G. Powell
Keyword(s):  
Thermal Anomaly ◽  
Hydrocarbon Exploration ◽  
Passive Margin ◽  
Source Rocks ◽  
Normal Faults ◽  
Rift Basin ◽  
Wide Range ◽  
Continental Rifts ◽  
Half Graben ◽  
Transfer Faults

The extension of the continental lithosphere that gives rise to continental rifts and eventually to passive continental margins and their basins is considered generally to involve shear on one or more major, shallow dipping normal faults (detachments). The operation of these detachments induces a basic asymmetry into the extensional terrane that is analogous to that in thrust terranes. As a result, the two sides of a continental rift and conjugate passive margin segments are predicted to have contrasting structure, facies development, subsidence history and thermal evolution.The major structural consequence of the detachment model is that half- graben rather than full graben geometry is expected in rift basins, consistent with recent interpretations in a wide range of continental rifts and passive margins. Half- graben geometry dominates in the Bass Strait basins, the Canning Basin and in a number of Proterozoic rifts, and has been observed on most parts of the Australian continental margin. Variations in the along- strike geometry of extensional basins are accommodated by transfer faults or fault zones. Transfer faults are as important and widespread in rifts as the classical normal faults, and they have important consequences for hydrocarbon exploration (e.g. design of seismic surveys, structural interpretation of seismic data, play and lead development).The fundamental asymmetry of extensional basins, and their compartmentalisation by transfer faults also control to a large extent the distribution of both source and reservoir facies. A model for facies distribution in a typical rift basin is presented, together with its implications for the prime locations of juxtaposed sources and reservoirs. Maturation of syn- rift source rocks depends on both the regional heat flow history and the amount of post- rift subsidence (and therefore burial). Both of these factors are influenced, and are partly predictable by the detachment model. In particular, there may be substantial horizontal offset of both the maximum thermal anomaly and the locus of post- rift subsidence from the rift basin. Analysis of deep crustal geophysical data may aid in the interpretation of detachment geometry and, therefore, of the gross distribution of thermal and subsidence histories.

THE PETROLEUM PROSPECTS OF THE GREAT BARRIER REEF REGION

1980 ◽  
Vol 20 (1) ◽  
pp. 159
Author(s):  
D.D. Benbow
Keyword(s):  
Continental Shelf ◽  
Great Barrier Reef ◽  
Mineral Resources ◽  
Seismic Survey ◽  
Barrier Reef ◽  
Petroleum Potential ◽  
Small Areas ◽  
Late Tertiary ◽  
Shelf Sediments ◽  
Exploratory Wells

The Great Barrier Reef Region covers some 207 000 sq. km of Queensland continental shelf between 9° 30'S and 24°S. The Reef ranges from Late Tertiary to Recent age with reefal growth mainly over platform areas of shelf sediments or basement rocks.The Reef area is underlain in part by seven basins which are either wholly or in part offshore; these basins are from north to south, the Peninsula Trough (Jurassic to Recent), Laura Basin (Permian to Cretaceous), Halifax Basin (Cretaceous to Recent), Hillsborough Basin (Early to Middle Tertiary), Styx Basin (Cretaceous), Capricorn Basin (Cretaceous to Recent and the Maryborough Basin (Jurassic to Tertiary).The geophysical coverage of the area is regional and only small areas of several of the basins have been covered by detailed seismic. During 1973 the Bureau of Mineral Resources conducted a seismic survey over the Queensland Plateau and adjacent Barrier Reef region: the results of this survey provide the geophysical basis for the basin evaluation.Four petroleum exploratory wells have been drilled in Queensland waters; these include Anchor Cay at the northern extremity of the Reef, and three wells in the Capricorn Basin.The petroleum potential of the region will remain speculative until further drilling is carried out to assess the stratigraphic section.

STUDIES ON PETROLEUM GEOLOGY AND GEOCHEMISTRY, MIDDLE PROTEROZOIC, McARTHUR BASIN NORTHERN AUSTRALIA I: PETROLEUM POTENTIAL

1988 ◽  
Vol 28 (1) ◽  
pp. 283 ◽  
Author(s):  
J- Jackson ◽  
I. P. Sweet ◽  
T. G. Powell
Keyword(s):  
Source Rocks ◽  
Coarse Grained ◽  
Hydrocarbon Generation ◽  
Petroleum Potential ◽  
Potential Source ◽  
Quartz Arenite ◽  
Abundant Evidence ◽  
Potential Reservoir ◽  
Fluvial Environments ◽  
Middle Proterozoic

Mature, rich, potential source beds and adjacent potential reservoir beds exist in the Middle Proterozoic sequence (1400-1800 Ma) of the McArthur Basin. The McArthur and Nathan Groups consist mainly of evaporitic and stromatolitic cherty dolostones interbedded with dolomitic siltstone and shale. They were deposited in interfingering marginal marine, lacustrine and fluvial environments. Lacustrine dolomitic siltstones form potential source beds, while potential reservoirs include vuggy brecciated carbonates associated with penecontemporaneous faulting and rare coarse-grained clastics. In contrast, the younger Roper Group consists of quartz arenite, siltstone and shale that occur in more uniform facies deposited in a stable marine setting. Both source and reservoir units are laterally extensive (over 200 km).Five potential source rocks at various stages of maturity have been discovered. Two of these source rocks, the lacustrine Barney Creek Formation in the McArthur Group and the marine Velkerri Formation in the Roper Group, compare favourably in thickness and potential with rich demonstrated source rocks in major oil-producing provinces. There is abundant evidence of migration of hydrocarbons at many stratigraphic levels. The geology and reservoir characteristics of the sediments in combination with the distribution of potential source beds, timing of hydrocarbon generation, evidence for migration and chances of preservation have been used to rank the prospectivity of the various stratigraphic units in different parts of the basin.

HYDROCARBON POTENTIAL OF THE NORTH WANGANUI BASIN, NEW ZEALAND

1977 ◽  
Vol 17 (1) ◽  
pp. 94
Author(s):  
H. McQuillan
Keyword(s):  
Sediment Supply ◽  
Source Rocks ◽  
Oil Companies ◽  
The North ◽  
Clastic Sediments ◽  
Potential Reservoir ◽  
History Of ◽  
Wrench Fault ◽  
Available Information ◽  
Coal Measures

The proximity of the North Wanganui Basin to the onshore Kapuni and offshore Maui gas/condensate fields of the adjacent Taranaki Basin has attracted the interest of oil companies for some time. Exploration during the late 1950's and early 1960's delineated several prospective traps. Some of these were subsequently drilled and, apart from minor gas indications, were dry holes. Data from the sixteen wells drilled are on open file and these together with other available information are incorporated in a series of maps representing stages in the evolution of the basin.The sedimentary history of the North Wanganui Basin began early in the Oligocene when a shallow north to south marine transgression saw the infilling of structurally defined northeast-southwest trending depressions in the folded Mesozoic basement. As the relief of the peripheral landmass was reduced the former basin irregularities were smoothed out and the way was paved for the spread of carbonate rich seas from which a suite of carbonate grainstones and packstones was deposited during the middle Oligocene. Late Oligocene time saw the renewed influx of clastic sediments as movements on the dominant wrench fault basement structure brought revived relief to areas of sediment supply. At that time the southern margin of the basin possibly merged westwards with the Taranaki Basin. Punctuated by periods of vulcanicity centred west of the present coastline, a thick sequence of mud, silt and sand, dominantly marine but locally including terrestrial coal measures, makes up the Miocene succession. Sedimentation controlled by growth faulting is characteristic, and the east-west barrier of the Pipiriki High persisted in restricting the southern extension of the basin during that time. The Miocene closed with a tilting movement hinged on the Pipiriki High such that subsequent Pliocene and Pleistocene sedimentation followed a south-east migrating depocentre in the quite separate South Wanganui Basin.Hydrocarbon indications in the basin itself are few. The presence there of potential reservoir and source rocks in addition to the proven production in the adjacent Taranaki Basin are reason for some optimism in the further evaluation of the hydrocarbon prospects of the North Wanganui Basin.

THE TECTONO-STRATIGRAPHY AND PETROLEUM POTENTIAL OF THE NORTHERN ABROLHOS SUB BASIN, WESTERN AUSTRALIA

1987 ◽  
Vol 27 (1) ◽  
pp. 112 ◽  
Author(s):  
Greg C. Smith ◽  
Robert G. Cowley
Keyword(s):  
Western Australia ◽  
Alluvial Fan ◽  
Source Rocks ◽  
Normal Faults ◽  
The West ◽  
Eastern Basin ◽  
Petroleum Potential ◽  
Lower Palaeozoic ◽  
Extensional Faulting ◽  
Stratigraphic Sequences

The Abrolhos Sub-basin lies offshore in Western Australia to the west of Geraldton and has geological affinities with the northern Perth Basin and the southern Carnarvon Basin. Both of these basins contain commercial petroleum accumulations, whereas the Abrolhos Sub-basin is a frontier area which is largely unexplored. A moderate seismic coverage of the sub-basin now exists but only two wells have been drilled, both of which were dry.Four main tectono-stratigraphic sequences are recognisable above Precambrian basement:Lower Palaeozoic Pre Rift SequenceCarboniferous-Permian Synrift/Rift Sequence S Triassic-Jurassic Rift Sequence4 Cretaceous to Recent Drift Sequence.The Lower Palaeozoic is only known on the eastern basin margins where it mainly consists of Silurian fluvial and alluvial fan red beds. The Carboniferous-Permian marine and coal measure volcanogenic synrift and rift sequences are characterised by north-south, mainly east-dipping extensional faulting, followed by widespread erosion. The Triassic sequence is about 2 km thick and comprises a basal marine Kockatea Shale, overlain by the marginal marine Woodada Formation and the Lesueur Formation red bed sequence. Subsidence during the Triassic was rapid but controlled by large NNW-SSE trending, high angle west-dipping, planar normal faults with minor rotation and extension. The Jurassic is poorly known, being confined to structurally deep blocks along the Mesozoic basin axis to the south and west. A renewed phase of NNW-SSE west-dipping extensional faulting began during the Jurassic and resulted in the development of rollover anticlines. Considerable erosion and non-deposition occurred forming a regional Neocomian unconformity. The postrift or drift sequence consists of transgressive marine shelf carbonates dipping basinward without further significant structuring.The main prospect types in the sub-basin include base Triassic transgressive sandstones or top Permian sandstones sealed by the Kockatea Shale in tilted fault blocks, and Triassic-Jurassic sandstones within rollover anticlines sealed by intraformational shales or the middle Jurassic Cadda Formation. The main source rocks include the Woodada and Kockatea formations which are within the oil generative zone over much of the sub-basin. However, identification of areas with the required coincidence of source, reservoir, seal and structural timing appears elusive.

Sign in / Sign up

Export Citation Format

Share Document