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.

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.

scholarly journals The Cambrian Henson Gletscher Formation: a mature to postmature hydrocarbon source rock sequence from North Greenland

1987 ◽  
Vol 133 ◽  
pp. 141-157
Author(s):  
F.G Christiansen ◽  
H Nøhr-Hansen ◽  
O Nykjær
Keyword(s):  
Source Rock ◽  
Source Rocks ◽  
Hydrocarbon Generation ◽  
Hydrocarbon Source Rock ◽  
Reservoir Rocks ◽  
Potential Source ◽  
Potential Reservoir ◽  
Field Season ◽  
North Greenland

During the 1985 field season the Cambrian Henson Gletscher Formation in central North Greenland was studied in detail with the aim of evaluating its potential as a hydrocarbon source rock. The formation contains organic rich shale and carbonate mudstone which are considered to be potential source rocks. These are sedimentologically coupled with a sequence of sandstones and coarse carbonates which might be potential reservoir rocks or migration conduits. Most of the rocks exposed on the surface are, however, thermally mature to postrnature with respect to hydrocarbon generation, leaving only few chances of finding trapped oil in the subsurface of the area studied in detail.

OIL GEOCHEMISTRY AND POTENTIAL SOURCE ROCKS OF THE OFFICER BASIN, SOUTH AUSTRALIA

1980 ◽  
Vol 20 (1) ◽  
pp. 68 ◽  
Author(s):  
D.M. McKirdy ◽  
A.J. Kantsler
Keyword(s):  
Organic Matter ◽  
Organic Carbon ◽  
Carbonate Rocks ◽  
Depositional Environment ◽  
South Australia ◽  
Source Rocks ◽  
Potential Source ◽  
Playa Lake ◽  
Oil Source ◽  
Extractable Organic Matter

Oil shows observed in Cambrian Observatory Hill Beds, intersected during recent stratigraphic drilling of SADME Byilkaoora-1 in the Officer Basin, indicate that oil has been generated within the basin. Shows vary in character from "light" oils exuding from fractures through to heavy viscous bitumen in vugs in carbonate rocks of a playa-lake sequence.The oils are immature and belong to two primary genetic families with some oils severely biodegraded. The less altered oils are rich in the C13 - C25 and C30 acyclic isoprenoid alkanes. Source beds within the evaporitic sequence contain 0.5 - 1.0% total organic carbon and yield up to 1900 ppm solvent-extractable organic matter. Oil-source rock correlations indicate that the oils originated within those facies drilled; this represents the first reported examples of non-marine Cambrian petroleum. The main precursor organisms were benthonic algae and various bacteria.Studies of organic matter in Cambrian strata from five other stratigraphic wells in the basin reveal regional variations in hydrocarbon source potential that relate to differences in precursor microbiota and/or depositional environment and regional maturation. Micritic carbonates of marine sabkha origin, located along the southeast margin of the basin, are rated as marginally mature to mature and good to prolific sources of oil. Further north and adjacent to the Musgrave Block, Cambrian siltstones and shales have low organic carbon values and hydrocarbon yields, and at best are only marginally mature. Varieties of organic matter recognised during petrographic studies of carbonates in the Officer Basin include lamellar alginite (alginite B) and "balls" of bitumen with reflectance in the range 0.2 to 1.4%.

SEQUENCE STRATIGRAPHY OF THE EASTERN OFFICER AND ARROWIE BASINS: A FRAMEWORK FOR CAMBRIAN OIL SEARCH

1991 ◽  
Vol 31 (1) ◽  
pp. 177 ◽  
Author(s):  
D. I. Gravestock ◽  
J.E. Hibburt
Keyword(s):  
Carbonate Reservoir ◽  
Source Rocks ◽  
Tectonic Activity ◽  
Reservoir Quality ◽  
Organic Carbon Content ◽  
The North ◽  
Subaerial Exposure ◽  
Potential Source ◽  
Shelf Slope ◽  
Playa Lake

The Early Cambrian eastern Officer and Arrowie Basins share a common sequence stratigraphic framework despite their contrasting settings. The Arrowie Basin was initially a shallow marine shelf between two land masses with moderate to abrupt shelf-ramp and shelf-slope profiles deepening to the north and south. Tectonic activity subsequently restricted open marine access to the north resulting in evaporite and red bed deposition. In the eastern Officer Basin epeiric sea sediments had open marine access only to the northeast. The palaeoslope was low and surrounding land supplied abundant siliciclastics. Following marine withdrawal alkaline playa lake and evaporitic mudflat deposits spread across the hinterland. Potential source rocks in the Arrowie Basin are thick transgressive and early high-stand deposits of the lowest three sequences. Organic carbon content may be highest (on slender evidence) where marine circulation was restricted. Carbonate reservoir quality on the shelf depends on subaerial exposure during marine lowstands. Prograding highstand sands, carbonate grainstones, and syntectonic channel deposits have untested reservoir potential. In the eastern Officer Basin potential source rocks are thin but widespread. Oil has been generated in the playa lake sediments. Fluvial, aeolian and shoreline sandstones, and those interbedded with carbonates, have excellent reservoir characteristics. The interbedded sands are thin but may be grouped near sequence boundaries. Lowstand carbonate breccias have generally unpredictable reservoir quality. Major differences in source and reservoir bed distribution between these basins, which share the same cycles of relative sea level change, are: palaeoslope, proximity to open marine conditions, duration of subaerial exposure and availability of terrigenous clastics.

PREDICTION OF CARBONATE RESERVOIRS AND TRAPS BY APPLYING SEQUENCE STRATIGRAPHY IN THE EASTERN WARBURTON BASIN, SOUTH AUSTRALIA

1998 ◽  
Vol 38 (1) ◽  
pp. 380 ◽  
Author(s):  
X.W. Sun
Keyword(s):  
Seismic Reflection ◽  
South Australia ◽  
High Amplitude ◽  
Carbonate Reservoirs ◽  
Source Rocks ◽  
Shelf Edge ◽  
Secondary Porosity ◽  
Sandy Limestone ◽  
Potential Reservoir ◽  
Early Palaeozoic

The Early Palaeozoic eastern Warburton Basin unconformably underlies the Cooper and Eromanga Basins. Four seismic sequence sets (I−IV) are interpreted. Among them, sequence set II is subdivided into four Cambro-Ordovician depositional sequences. Sequence 1, the oldest, is a shallow shelf deposit that occurs only in the Gidgealpa area. Sequences 2 and 3 were deposited in a wider area; from west to east, environments varyied from deep siliciclastic ramp, carbonate inner-shelf, peritidal, shelf edge, and slope-to-basin. Their seismic reflection configurations are high-amplitude, regionally parallel-continuous, layered patterns, locally mounded geometry, as well as divergent-fill patterns. Sequence 4, the youngest, was deposited in a mixed siliciclastic and carbonate, storm-dominate shelf. Its seismic reflection configurations are moderate amplitude, parallel-layered patterns, decreasing in amplitude upwards.Boundaries between the four sequences generated good secondary porosity in the carbonates. Karst development is interpreted to have generated much of this porosity in shelf and peritidal carbonates, and carbonate build-ups. Shoal-water sandy limestone and calcareous sandstone of Sequence 4 may be other potential reservoir rocks. Potential source rocks comprise mudstone and shale of slope and basin lithofacies. There are two kinds of stratigraphic trap. One is in Sequences 2 and 3, associated with high-relief carbonate build-ups encased in lagoonal mudstone and shelf edge sealed by transgressive siltstone and shale. The other is a transgressive marine shale enclosing porous dolostone of the karstified Sequence 1. In addition, petroleum may have migrated from Permian source rocks of the Cooper Basin to karstified carbonate reservoirs of the Warburton Basin at unconformities.

scholarly journals Oligocene-Pleistocene Paleogeography within Banyumas Basin and implication to petroleum potential

2018 ◽  
Vol 1 ◽  
pp. 00006 ◽  
Author(s):  
Eko Bayu Purwasatriya ◽  
Sugeng Sapto Surjono ◽  
Donatus Hendra Amijaya
Keyword(s):  
Depositional Environment ◽  
Tectonic Setting ◽  
Volcanic Rocks ◽  
Source Rocks ◽  
Petroleum Potential ◽  
Magmatic Arc ◽  
The North ◽  
Potential Source ◽  
Back Arc ◽  
Exploration Activity

<p>This study attempts to reconstruct paleogeography of Banyumas Basin in association with magmatic arc evolution and its implication to petroleum potential. Based on the volcanic rocks distribution, their association and relatives age, there are three alignments of a magmatic arc, that are: (1) Oligo-Miocene arc in the south (2) Mio-Pliocene arc in the middle (3) Plio-Pleistocene arc in the north. The consequences of the magmatic arc movement were tectonic setting changing during Oligocene to Pleistocene, as well as their paleogeography. During Oligo-Miocene where magmatic arc existed in the southern part, the Banyumas tectonic setting was a back-arc basin. This tectonic setting was changing to intra-arc basin during Mio-Pliocene and subsequently to fore-arc basin since Plio-Pleistocene until today. Back-arc basin is the most suitable paleogeography to create a depositional environment for potential source rocks. Exploration activity to prove the existence of source rocks during Oligo-Miocene is needed to reveal petroleum potential in Banyumas Basin.<br></p>

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.

LOWER CAMBRIAN RELIEF SANDSTONE, EASTERN OFFICER BASIN, SOUTH AUSTRALIA: AN EXAMPLE OF ECONDARY POROSITY DEVELOPMENT

1990 ◽  
Vol 30 (1) ◽  
pp. 184
Author(s):  
Chris J. Gaughan ◽  
John K. Warren
Keyword(s):  
South Australia ◽  
Source Rocks ◽  
Reservoir Quality ◽  
The West ◽  
Potential Source ◽  
Lower Reservoir ◽  
Close Proximity ◽  
Porosity And Permeability ◽  
Fluvial Environments ◽  
Live Oil

Interest in the Relief Sandstone as a potential economic oil-bearing sandstone is supported by excellent reservoir quality (up to 26.6 per cent porosity and 4839 md permeability). Potential source rocks are found above, below and interfingering with the Relief Sandstone. There are several occurrences of live oil bleeding from vugs and fractures in a stratigraphically higher carbonate. Traces of oil in the Relief sands, and the presence of live oil in relatively close proximity, suggests that the Relief Sandstone could host an economic oil accumulation.The majority of the Relief Sandstone was deposited in aeolian or braided fluvial environments with some tidal to shallow marine deposition in the west. Distribution of reservoir-quality sands is bimodal. In the east, porosity and permeability for the most part is very poor to average. In the west, porosity and permeability is generally good to excellent. The bulk of the economic porosity is secondary, a result of dissolution of cement and matrix, with minor porosity from leaching of grains. The lower reservoir quality in the east is due to diagenesis associated with compaction and authigenic illite. In the west, the porosity and permeability are high and generally due to dissolution of clay cement and primary matrix. In some cases where the clay has undergone less dissolution, it remains as grain rims and still blocks pore throats. This significantly reduces permeability although the porosity may remain high.

PETROLEUM AND GEOLOGY: A SYNTHESIS

1972 ◽  
Vol 12 (1) ◽  
pp. 36
Author(s):  
Richard E. Chapman
Keyword(s):  
Sediment Accumulation ◽  
Sedimentary Basins ◽  
Direct Consequence ◽  
Source Rocks ◽  
Reservoir Rocks ◽  
Subsurface Geology ◽  
Tectonic Events ◽  
Potential Source ◽  
Potential Reservoir ◽  
Vertical Gravity

A marine sedimentary basin typically begins with a transgressive phase and ends with a regressive phase; but there may be several cycles, and also periods in which neither is dominant.Petroleum occurrences fall into two broad stratigraphie classes: those of transgressive sequences, and those of regressive sequences. Transgressions tend to accumulate potential source rocks on top of potential reservoir rocks, and the petroleum tends to migrate downwards then laterally into stratigraphic traps, especially reefs and below unconformities. It also occurs in diachronous units that are anticlinal in form due to basement irregularities. Regressions tend to accumulate potential reservoir rocks on top of potential source rocks, and the petroleum tends to migrate upwards and then laterally into anticlines and fault traps that are typically initiated contemporaneously or penecontemporaneously with sediment accumulation. There is some evidence that oil of transgressive sequences is heavier than oil of regressive sequences.Evidence derived from subsurface geology, including petroleum occurrences, suggests that young marine sedimentary basins are typically deformed by vertical, gravity processes during and just after significant regressive phases of their development; and that these processes are a direct consequence of the accumulation of sediment in a regressive sequence. Subsequent horizontal tectonic events, in general, only modify the earlier, contemporaneous, deformation.

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