DEPARTMENT OF MINES AND ENERGY
PETROLEUM GEOLOGY s,,.c: .:&*; -. G>5 .. . . .- .-*- - -=. -. ,- --.. .
QF THE NORTHERN TERRITORY O F ,
DEPARTMENT OF MINES AND ENERGY NORTHERN TERRITORY GEOLOGICAL SURVEY
INTRODUCTION
TO THE
PETROlLEUM GEOLOGY
OF THE
NORTHERN TERRITORY OF AUST IA
D. M. PEGUM
May 1997
NORTHERN TERRITORY DEPMTMENT OF MINES AND ENERGY
MINISTER: Hon. Daryl Manzie, MLA SECRETARY: P. G. Blake
NORTHERN TERRITORY GEOLOGICAL SUWEY
DIRECTOR: C. A. Mulder
ISBN 0 7245 2969 1
Published for the Northern Territory Geological Survey by the Government Printer of the Northern Territory
Printed by Government Printer of the Northern Territory.
TMLEOFCONTENTS
List of Figures
Regional Geology
History of Petroleum Exploration and Production
Introduction
Onshore Exploration and Production
Offshore Exploration and Production
Major Sedimentary Basins
Northern Proterozoic Basins
McArthur Basin
Victoria Basin
Central Australian Proterozoic to Palaeozoic Basins
Arnadeus Basin
Georgina Basin
Ngalia Basin
Wiso Basin
North Coastal Basins
Arafura Basin
Bonaparte Basin
Younger Basins
Carpentaria Basin
Eromanga Basin
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LIST OF FIGURES
The Northern Territory of Australia
Sedimentary Basins of the Northern Territory
McArthur Basin Stratigraphic Table
Victoria Basin Stratigraphic Table
Arnadeus Basin Stratigraphic Table
Georgina Basin Stratigraphic Table
Ngalia Basin Stratigraphic Table
Wiso Basin Stratigraphic Table
Arafura Basin Stratigraphic Table
Bonaparte Basin Stratigraphic Table
Carpentaria Basin Stratigraphic Table
Eromanga Basin Stratigraphic Table
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REGIONm GEOLOGY
The Northern Territory of Australia covers a land area of 1 346 200
square kilometres, one sixth of the landmass of Australia. The offshore
Northern Territory Adjacent Area covers 50 1 125 square kilometres and
the Territory of the Ashmore and Cartier Islands Ajacent Area, which is
administered by the Government of the Northern Territory covers 77 187
square kilometres.
In the northern part of the Northern Territory intensely deformed and metamorphosed rocks of Archaean to Palaeoproterozoic age are overlain
by mildly deformed unmetamorphosed sedimentary rocks of the late
Palaeoproterozoic to Neoproterozoic McArthur and Victoria basins, to
form the Northern Australian Craton.
To the south these rocks pass into the Central Australian Orogenic
Province where intense metamorphism continued into the
Neoproterozoic. These intensely metamorphosed rocks and the rocks of
the Northern Australian Craton are overlain by later sedimentary
basins.
In the Arnadeus, Ngalia, Georgina and possibly Wiso basins, which are all located over the more central parts of the craton, sedimentation
commenced in the Neoproterozoic and had ceased by the Early
Carboniferous.
On the northwestern coast of the Northern Territory Cambrian to
Permian sediments of the Bonaparte Basin crop out and extend to the
northwest under the Timor Sea where they are overlain by Mesozoic and
Cainozoic sediments.
The northern flank of the Triassic to Cainozoic Browse Basin extends into
the southern part of the Territory of the Ashmore and Cartier Islands
Adjacent Area.
Along the northern coast and extending northward under the Arafura
Sea are the Neoproterozoic to Permian and possibly Triassic moderately
deformed sediments of the Arafura Basin overlain by relatively flat lying
Jurassic to Cainozoic Money Shoal Basin sediments.
The boundaries of the Bonaparte Basin are somewhat arbitrary due to the Western Australian practice of extending structural units up through the overlying sediments rather than recognising superimposed sedimentary basins. As a result although the Bonaparte Basin forms a discrete Palaeozoic unit, Triassic to Cainozoic sediments in the Browse Basin and Jurassic to Cainozoic sediments in the Money Shoal Basin are continuous with sediments in the Bonaparte Basin. On the northeastern coast of the Northern Territory and underlying the Gulf of Carpentaria, the Late Jurassic to Early Cretaceous Carpentaria Basin overlies a little known pre-Jurassic sedimentary section and is in turn overlain by Cainozoic sediments of the Karumba Basin. In the southeastern corner of the Northern Territory the Amadeus Basin margin is overlain by Permian to Tertiary sediments of the Pedirka, Simpson and Eromanga basins. To the north of the Georgina and Wiso basins, thin Cambrian to Ordovician sediments of the Daly Basin overlie the North Australian Craton. Thin Mesozoic rocks of the Dunmarra Basin overlie the northern parts of the Georgina and Wiso basins and the southern Daly Basin.
HISTORY OF PETROLEUM EXPLORATION AND PRODUCTION
INTRODUCTION
The first recorded discovery of petroleum in Australia was made in 1839
by members of the crew of HMS Beagle beside the estuary of the Victoria
River in what is now the Northern Territory. A bituminous substance
which "ignited quickly when put into the flame of a candle" was
encountered at a depth of seven metres from the surface in two large
wells sunk to obtain fresh water.
ONSHORE EXPLORATION AND PRODUCTION
However it was not until the 1950s that extensive onshore petroleum
exploration commenced in the Northern Territory. Regional gravity and
aeromagnetic surveys outlined the principal sedimentary basins which
then became the focus for continuing exploration, especially the
Amadeus, Bonaparte, Eromanga and Georgina basins.
Georgina Basin Inflammable gas was discovered in a bore drilled for water a t Arnmaroo
Station in the western Georgina Basin in 1956. This discovery led to
extensive exploration in the basin which has not yet confirmed this
promising early indication of its petroleum potential. The only
substantial flow of petroleum so far encountered has been 200 MCFGD
from the Ethabuka- 1 well drilled in the Queensland portion of the basin
in 1974.
Amadeus Basin The first well drilled for petroleum in the Amadeus Basin, Ooraminna- 1
in 1963 encountered a subcommercial flow of 12 MCFGD . The third well
in the basin, Mereenie-1 in 1964 discovered the Mereenie Oil and Gas
Field on a large anticline 240 kilometres west of Alice Springs. The well
flowed 4.8 MMCFGD. This discovery encouraged further exploration
leading to the discovery of the Palm Valley Gas Field in1965 on a large
anticline located 120 kilometres west of Alice Springs. The discovery
well Palm Valley- 1 flowed up to 11.7 MMCFGD. Development of these
discoveries and further exploration in the basin were hampered by low
oil prices and land access problems. Active exploration resumed in
1980, leading to the discovery of the Dingo Gas Field in 1981. It has not
yet been proved to be commercial.
Mereenie oil was first produced in 1984. Production increased following
the completion of a pipeline in 1985 to Alice Springs. The oil is
transported by rail from Alice Springs to Port Stanvac refinery near
Adelaide. The Palm Valley Gas Field commenced supplying gas to Alice
Springs in 1983. In 1987 a major pipeline connecting both Palm Valley
and Mereenie fields to Darwin commenced to supply gas to Darwin,
Tennant Creek and Katherine.
Eromanga Basin Active exploration in the Northern Territory portion of the Eromanga
Basin commenced in the early 1960s and ceased in 1966 following the
drilling of two dry wells. Following the significant oil recoveries from
Poolowanna-1 drilled in 1977 in South Australia, exploration in the
region has intensified but so far without success.
Ngalia Basin Petroleum exploration has been carried out in the Ngalia Basin since the
1960s but the only petroleum exploration well, Davis- 1 drilled in 1981
proved unsuccessful.
Wiso Basin Only limited petroleum exploration consisting of aeromagnetic gravity
and seismic surveys was carried out in the Wiso Basin in the 1960s.
Bonaparte Basin In the onshore Bonaparte Basin, significant petroleum exploration
commenced in the 1960s and intensified in the 1970s following the
discovery of numerous oil and bitumen shows in shallow mineral
exploration core holes drilled near the basin margin. The Weaber Gas
Field was discovered in 1982 but has not yet been proved to be commercial. Exploration continues in the area.
McArthur Basin More recently exploration interest has extended to the Proterozoic
basins of the Northern Territory. The discovery of solid and liquid
hydrocarbons and a pocket of gas in mineral exploration drillholes in the
McArthur Basin has led to extensive exploration so far without success.
Victoria Basin The only petroleum exploration drillhole in the Victoria Basin, Bullo
River- 1 drilled in 1984 was unsuccessful.
OFFSHORE EXPLORATION AND PRODUCTION
Large scale petroleum exploration commenced in the north-western and
northern offshore waters of Australia in the early 1960s and has
continued ever since with major success.
Bonaparte Basin In the offshore Bonaparte Basin, reconnaissance gravity and
aeromagnetic surveys were followed by regional and detailed seismic
surveys and drilling. In the eastern offshore Bonaparte Basin, Northern
Territory Adjacent Area, several gas fields have been discovered, Petrel
(1969), Troubadour (1974), Sunrise (1975) and Evans Shoal (1988). Oil
was discovered a t Barnett in 1989. None of these finds has been
declared commercial.
In the western offshore Bonaparte Basin, Territory of the Ashmore and
Cartier Islands Adjacent Area, oil was discovered in 1972 in Puffin- 1,
the third well drilled in the area. Oil and gas were discovered in Swan- 1
drilled in 1972. The first commercial field in the area, Jabiru, was
discovered in 1983, with further commercial finds a t Challis (1984)
Skua (1985), Cassini (1 988), Laminaria (1994) and Corallina (1 995).
Further non-commercial oil and gas discoveries have been made a t
Oliver, Montara, Bilyara (all in 1988), Talbot (1989), Tahbilk and Maple
(1990).
The Jabiru Field commenced production in 1986 from a single subsea
well with anchored riser, using the 140 000 DWT disconnectable tanker
"Jabiru Venture". Subsequent development wells were tied in to the
"Jabiru Venture". Challis and Cassini fields were developed in 1989
using the 1 15 000 DWT purpose - built barge "Challis Venture" attached
to a gravity-based riser. Skua Field was produced using an anchored
riser and the disconnectable 132 000 DWT "Skua Venture". Production
from this field ceased in February 1997.
Exploration in the northwestern offshore Bonaparte Basin was subdued
during the 1980s, in part because of the undefined international
boundary. Following the conclusion of a treaty in 1989 between
Australia and the Republic of Indonesia establishing a Zone of
Cooperation in the area, petroleum exploration has increased rapidly,
leading to significant commercial oil discoveries at Elang and Kakatua
(1994) and the major Bayu-Undan gas condensate discovery (1995).
None of these fields is yet in production
Arafura Basin In the Arafura Basin area, initial exploration along the southern margin
of the area in 1955 to 1965 was followed in 1965 to 1975 by
aeromagnetic and seismic delineation of the basin and the drilling of an
unsuccessful exploration well. From 1980 to 1993 exploration resumed
with further seismic surveys and the drilling of a further eight
unsuccessful exploration wells.
Carpentaria Basin In the Carpentaria Basin only minor seismic exploration was carried out
prior to 1980. In the early 1980s regional seismic surveys led to the
drilling of a n unsuccessful exploration well in 1984.
STRATIGRAPHY
. X. .x. . X . . , . . . . .
- - - -
. . . . . . .
Figure 3. McArthur Basin Stratigraphic Table
MAJOR SEDIMENTARY BASINS
NORTHERN PROTEROZOIC BASINS
McARTHUR BASIN
The McArthur Basin covers an area of about 200 000 square kilometres
in the northeastern Northern Territory, and it contains an
unmetamorphosed gently folded and faulted Mesoproterozoic largely
sedimentary sequence up to about 12 000 metres in thickness.
The rocks appear to have been deposited in mostly shallow water
environments in an intracratonic basin which was dominated a t times
by a prominent north trending half graben, the Batten Trough.
A basal shallow marine to fluvial predominantly sandstone and basic
volcanic sequence, the Tawallah Group, is overlain by a shallow water
to intratidal succession of carbonates and evaporites, dolomitic
siltstones and shales, the McArthur and Nathan groups. Above a major
regional unconformity are the rocks of the Roper Group, consisting of
alternating clean quartz arenites and recessive siltstones and shales,
deposited in an environment ranging from fluvio-deltaic to deep marine.
Potential petroleum source rocks ranging from marginally mature to
overmature have been identified in the McArthur and Roper groups.
Small quantities of live oil have been recovered from poor quality
reservoirs. Considerable volumes of oil (hundreds of millions of barrels)
are thought to have been generated in these rocks but not expelled from
them.
Amoco undertook a major exploration program in the basin in 198 1-84,
culminating in the drilling of the 2 174 metre Broadmere- 1 well which
intersected middle to lower Roper Group rocks with no significant
shows, poor reservoir quality and high maturity.
Pacific Oil and Gas Pty Ltd explored the area from 1986 to 1994, drilled
23 slimhole wells which encountered an abundance of organic-rich
source rocks ranging from immature to overmature, poor to moderate
potential reservoir beds with occasional good zones and numerous oil
and gas shows.
The available structural control suggests that wells drilled to date may
not have tested valid targets, and that the potential of the basin to
contain economic accumulations of petroleum has not yet been
adequately assessed.
Selected References
JACKSON, M. J., MUIR, M.D. and PLUMB, K.A., 1987. Geology of the
southern McArthur Basin, Northern Territory. Bureau of Mineral
Resources, Australia, Bulletin 220.
JACKSON, M.J., SWEET, I.P. and POWELL, T.G., 1988. Studies on
petroleum geology and geochemistry of the Middle Proterozoic McArthur
Basin northern Australia 1: Petroleum potential. APEA Journal 28(1),
pp 283-302.
LANIGAN, K., I-IIBBIRD, S., MENPES, S. and TORKINGTON, J., 1994.
Petroleum Exploration in the Proterozoic Beetaloo Sub- basin, Northern
Territory. APEA Journal 34(1) pp 674-69 1.
PLUMB, K.A., AHMAD, M. and WYGRALAK, A.S., 1990. Mid-
Proterozoic basins of the North Australia Craton - regional geology and
mineralisation. In HUGHES, F.E., (Ed), Geology of the mineral deposits of Australia and Papua New Guinea, pp 88 1-902, Australian Institute
of Mining and Metallurgy, Melbourne.
POWELL, T.G., JACKSON, M.J., SWEET, I.P., CRICK, I.H., BOREHAM,
C. J . and SUMMONS, R.E., 1987. Petroleum geology and geochemistry
Middle Proterozoic McArthur Basin. Bureau of Mineral Resources,
Australia, Record 1987/88 (unpublished).
VICTOFUA BASIN
The Victoria Basin is a practically unexplored area of about 65 000
square kilometres containing up to 3500 metres of mainly flat lying
carbonates and terrigenous sedimentary rocks. Alternating
transgression and regression across a broad stable shelf produced
cycles of sedimentation with basal sandstones passing upward into
siltstones and carbonates. Deformation increases abruptly adjacent to
the mobile zone along the western margin of the basin where the rocks
are intensely folded and faulted.
There are historic accounts of minor oil seeps. One exploration well has
been drilled on a larger faulted surface anticline near the western
margin of the basin. It intersected an 880 metre section of shales
siltstones and sandstones with poor source and reservoir potential.
The petroleum potential of this basin is unknown.
Selected Reference
SWEET, I.P., 1977. The Precambrian geology of the Victoria River
region, Northern Territory. Bureau of Mineral Resources, Australia,
Bulletin 168.
STRATIGRAPHY ROCK TYPES AND UNIT THICKNESS
ANTRIM PLATEAU Basait; minor agglomerate, sandstone, chert, limestone
Tillite, sandstone, conglomerate, DUERDIN GRUOP siltstone, shale, dolomite
BULL0 RIVER Sandstone, conglomerate
AUVERGNE GROUP Sandstone, siltstone, dolomite,
WONDOAN HILL 1 STUBB FORMATIONS Sandstone, siltstone, mudstone
Dolomite, siltstone, chert; BULLITA GROUP minor sandstone
Sandstone, siltstone; WATTIE GROUP minor doiomite, claystone
LIMBUNYA GROUP Dolomite, siltstone, sandstone,
Figure 4. Victoria Basin Stratigraphic Table
CENTIIAL AUSTRALIAN NEOPROTEROZOIC TO PALAEOZOIC BASINS
Sedimentation in the Central Australian Amadeus, Ngalia, Georgina and
probably Wiso basins commenced in Neoproterozoic time. Marine
clastic and carbonate deposition continued into the Cambrian and
Ordovician. Younger Silurian to Carboniferous sequences are restricted
in areal extent and are non-marine.
Two fundamental sets of basement fractures, one trending roughly . northerly, and the other trending northwesterly, are thought to have
controlled the tectonic development of the region. Vertical movement of
rigid blocks is thought to have created the depocentres of the
sedimentary basins of the area and later movements have probably
caused extensive stripping of sediments from uplifted blocks. The
Arunta Inlier, a large area of basement outcrop which now separates
sediments preserved in the Amadeus, Ngalia, Georgina and Wiso basins,
may have constituted the deepest part of a depositional basin covering
much of the Central Australian region.
STRATIGRAPHY HYDROCARBON
MEREENIE SANDSTONE
CARMICHAEL SANDSTONE
STOKES SILTSTONE
PACOOTA SANDSTONE
ARUMBERA SANDSTONE
INlNDlA BEDS
BITTER SPRINGS
Figure 5. Amadeus Basin Stratigraphic Table
AMADEUS BASIN
The Arnadeus Basin extends across Central Australia for a distance of
800 kilometres in an east-west direction and 200 kilornetres from north
to south. It covers an area of 155 000 square kilornetres and has an
estimated preserved sediment thickness of up to 14 000 metres.
The first sediments deposited were Neoproterozoic sands laid down by a
marine transgression across a stable epicontinental shelf. These are
heavily silicified in outcrop and are known as the Heavitree Quartzite.
These rocks are overlain by the Bitter Springs Formation consisting of
up to 1000 metres of evaporites, carbonates and dolomites deposited in
barred basins and lagoons as the sea retreated. Uplift of the area to the
south ensued with consequent paralic deposition in the north and
paralic and possibly continental deposition in the south, with proglacial
influx from a glaciated landmass to the north.
Following a second episode of uplift, the southern region became the
main source for sedimentation consisting of shallow marine sandstones
and shales in a southern trough and carbonates and fine-grained
marine shales in a northern shelf area. Proterozoic sedimentation was
brought to a close by the major Petermann Ranges Orogeny which
uplifted and overfolded a large area in the southwest of the basin. The
younger Proterozoic sediments slid north on a decollement surface in
the Bitter Springs evaporites. Molasse sediments from the newly formed
mountains were shed to the north and northeast and deposited in a
mainly deltaic environment to form the Arumbera Sandstone, the
reservoir of the sub-economic Dingo Gas Field.
During the Cambrian, continental sedimentation continued in the west
while shallow marine shales, carbonates and evaporites were deposited
in the east. A marine transgression in the Late Cambrian deposited
widespread sands and carbonates with minor siltstones and shales
across the basin. A second Early Ordovician transgression resulted in
the deposition of euxinic muds and silts (the Horn Valley Siltstone) in
an open shelf environment, with intertidal flats and barrier bars
(Pacoota Sandstone) landward of the open shelf. These rocks are the
major source and principal reservoir of the commercial Palm Valley and
Mereenie fields. Younger Ordovician sediments were deposited in similar
environments during later transgressive and regressive cycles with final
sedimentation in a predominantly estuarine environment.
This phase of sedimentation was terminated by major uplift in the
northeast of the basin with erosion of up to 3000 metres of Cambro-
Ordovician sediments. Aeolian, fluvial and shallow marine sandstones
were deposited in the Early Devonian. Uplift of the northern margin of
the basin during the Middle to Late Devonian resulted in the deposition
of a a thick wedge of continental molasse sediments along the northern
margin of the basin and then terminated regional deposition.
Thirty nine petroleum exploration wells have been drilled in the basin resulting in the discovery of two commercial fields, Mereenie Oil and
Gas Field and Palm Valley Gas Field, the sub-commercial Dingo Gas
Field and many significant oil and gas shows from a total of thirteen
different formations.
The Palm Valley Gas Field, located in the north central part of the basin
is well expressed a t the surface as an east-west arcuate anticline, convex
to the north and about 45 kilometres long. The discovery well, Palm
Valley- 1 drilled in 1965 flowed up to 1 1.7 MMCFGD from the base of the Ordovician Horn Valley Siltstone and underlying Pacoota Sandstone.
Nine further wells have been drilled of which Palm Valley-6B recorded
a flow of 13'7 MMCFGD. There is an extensive fracture network in the
reservoir which causes uncertainty in estimation of the initial
recoverable reserves. Figures have been published ranging from 275 to
480 BCF. The Mereenie Oil and Gas Field is located in the west central part of the
basin on a northwest southeast trending anticline on the upper plate
of a thrust fault which forms the southern boundary of the field. The
discovery well Mereenie-1 drilled in 1963 produced a flow of 4.8
MMCFGD from the Ordovician Pacoota Sandstone. Oil was discovered
in the third well drilled on the field. A total of 45 wells have been drilled.
Ultimate recovery is estimated at up to 11 MMBBLS and 380 BCF.
The Dingo Gas Field is a simple unfaulted domal anticline in the north
central part of the basin. The discovery well Dingo 1 drilled in 1981
flowed 1.3 MMCFGD from the Late Neoproterozoic to Early Cambrian
Arumbera Sandstone. Three appraisal wells have been drilled. Reserves are estimated a t 25BCF recoverable.
The complexity of the basin has resulted in a large variety of attractive
prospects and play types ranging from simple domal or elongate
anticlines, fault controlled prospects often related to thrust faults, to a
sub-salt play in the basal sandstone of the basin, stratigraphic plays and a large extra-terrestrial impact feature.
Considering the successes of the past, the numerous encouraging
shows from other wells, and the size, number and quality of known
prospects and play types, it seems likely that the full potential of the
basin is yet to be realized and that further commercial discoveries are
just a matter of time and exploration effort.
Selected References
GORTER, J.D., 1984. Source Potential of the Horn Valley Siltstone,
Arnadeus Basin. APEA Journal 24(1) pp 66-90.
JACKSON, K.S., MCKIRDY, D.M. and DECKELMAN, J.A., 1984.
Hydrocarbon generation in the Arnadeus Basin, central Australia. APEA
Journal 24(1) pp 42-65.
KORSCH, R.J. and KENNARD, J.M. (Eds), 1991. Geological and
geophysical studies in the Arnadeus Basin, central Australia. Bureau of
Mineral Resources, Australia, Bulletin 236.
LINDSAY, J.F. (Ed), 1993. Geological atlas of the Arnadeus Basin.
Australian Geological Survey Organisation.
NORTHERN TERRITORY GEOLOGICAL SURVEY, 1989. Petroleum
Basin Study - Western Arnadeus Basin. Prepared by G Weste. Northern
Territory Government Printer.
NORTHERN TERRITORY GEOLOGICAL SURVEY, 1990. Petroleum
Basin Study - Eastern Arnadeus Basin. Prepared by G Weste. Northern
Territory Government Printer.
NORTHERN TERRITORY GEOLOCAL SURVEY, 1994. Petroleum Basin
Study - Arnadeus Basin Update. Prepared by G Weste. Northern
Territory Government Printer.
ROE, L.E., 1988. The Arnadeus Basin. In Petroleum in Australia: The
First Century pp 232-25 1, Australian Petroleum Exploration
Association Limited.
GEORGINA BASIN
The Georgina Basin is a broad northwest to southeast trending
intracratonic basin which covers an area of some 325 000 square
kilometres of which 60% is in the central eastern part of the Northern
Territory and the remainder in northwestern Queensland. The basin
contains up to 6000 metres of Neoproterozoic clastic sedimentary rocks
deposited in a rift environment. The Petermann Ranges Orogeny a t the
end of the Proterozoic and subsequent erosion produced a relatively
smooth unconformity surface over the area.
Cambrian and Ordovician marine carbonates and clastics and Devonian
continental sediments were deposited in a gently down-warping basin.
These sediments thicken progressively in a south-southeasterly
direction rarely exceeding 400 metres in thickness in the northern half
of the basin and reaching about 5000 metres in thickness in the south.
The basin has been deformed in the Late Devonian to Early
Carboniferous by minor to moderate folding in the south, grading to
moderate to severe folding and extensive overthrusting along the
southwestern margin. The northern part of the basin is gently
undulating with drape folding over basement highs.
The presence of frequent oil shows throughout much of the Cambrian
succession in many of the wells drilled in the southern part of the basin
demonstrates that considerable volumes of hydrocarbons have been
generated. Geochemical studies have identified the anaerobic facies of
the Middle, Cambrian Arthur Creek Formation, a highly fossiliferous
sequence of organic rich siltstones, silty limestones and silty dolostones,
as a good source rock with TOC values commonly 1 to 4% and ranging
up to 16%. Ethabuka-1 well in the Queensland part of the basin
encountered a gas flow of 250 MCFD from a porous Ordovician
limestone. Petroleum exploration in the basin is still a t the frontier stage
with little seismic control. I t s petroleum potential and the development
of leads and plays remain largely speculative. The basin is promising
and worth further exploration.
Selected References
NORTHERN TERRITORY GEOLOGICAL SURVEY, 1994. Petroleurn
Basin Study - Georgina Basin. Prepared by Questa Australia Pty Ltd.
Northern Territory Government Printer.
SHERGOLD, J .H. and DRUCE, E.C., 1980. Upper Proterozoic and Lower
Palaeozoic rocks of the Georgina Basin. In HENDERSON, R.A. and
STEPHENSON, P.J . (Eds), The Geology and Geophysics of
Northeastern Australia. Geological Society of Australia, Queensland
Division, Brisbane.
SMITH, K.G., 1972. Stratigraphy of the Georgina Basin. Bureau of
Mineral Resources, Australia, Bulletin 1 1 1.
NGAI.,IA BASIN
The Ngalia Basin is an east-west trending intracratonic basin located in
Central Australia 80 kilometres north of the Arnadeus Basin. It covers
an area of 16 000 square kilometres and has a preserved sediment
thickness of 6000 metres. The sediments are thickest near the northern
margin of the basin. The succession consists of Neoproterozoic to
Ordovician shallow marine and fluvio-glacial elastics, carbonates and
evaporites, overlain by Devonian and Carboniferous fluvial to
continental sandstones, greywackes and siltstones. The basin was
moderately deformed by Neoproterozoic and Carboniferous orogenies.
Only one petroleum exploration well has been drilled in the basin.
Davis-1 drilled in 1981 on a structure now known to lack closure at depth encountered gas-saturated water in fractures in the
Neoproterozoic Rinkabeena Shale.
With only limited exploration, the basin's petroleum potential is largely
speculative but it is considered worth considerably more exploration.
STRATIGRAPHY
. . . . . . . . . . CARBONIFEROUS
. . . . . . . . . . . . . .
--------
. . . . . . . . . . . . . . . KERRIDY SANDSTONE . . . . . . . . . . . . . . .
-------- MT. DOREEN FM.
------- - NABURULA FM.
Figure 7. Ngalia Basin Stratigraphic Table
Selected References
NORTHERN TERRITORY GEOLOGICAL SURVEY, 1989. Petroleum
Basin Study - Ngalia Basin. Prepared by Questa Australia Pty Ltd.
Northern Territory Government Printer.
WELLS, A.T. and MOSS, F.J., 1983. The Ngalia Basin, Northern
Territory: stratigraphy and structure. Bureau of Mineral Resources,
Aus-tralia, Bulletin 2 12.
STRATIGRAPHY
CARBONIFEROUS
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 1 , . . . / I . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . LAKE SURPRISE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 1 . . . . I / . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
- - - - - - -
I I I I I / I I / I I I / I / I
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Figure 8. Wiso Basin Stratigraphic Table
WISO BASIN
The Wiso Basin is a virtually unexplored basin considered to be similar
in many ways to the Georgina Basin. It occupies an area of 160 000
square kilometres in the central-western part of the Northern Territory.
The northern part of the basin contains generally less than 300 metres
of Cambrian and Ordovician sediments thickening to 3000 metres of
possibly Proterozoic to Carboniferous sediments in the extreme
southern part of the basin (Lander Trough). Sedimentation comprises both carbonate and clastic lithologies deposited in a shallow marine to
fluviatile environment.
The only reported hydrocarbon show is a tarry residue in the Cambrian
Montejinni Limestone. No petroleum exploration wells have been drilled
in the basin. Geological control is provided by shallow stratigraphic
boreholes and limited outcrop, gravity, magnetic and seismic data.
The basin's petroleum potential is highly speculative, but because of its
potential similarity to the Georgina Basin it is considered worth further
exploration.
Selected References
KENNEWELL, P.J. and HULEAIT, M.B., (1980). Geology of the Wiso
Basin, Northern Territory. Bureau of Mineral Resources, Australia,
Bulletin 205,
NORTHERN TERRITORY GEOLOGICAL SURVEY, 1989. Petroleum
Basin Study - Wiso Basin. Prepared by Questa Australia Pty Ltd. Northern Territory Government Printer.
PEGUM, D.M. and LOELIGER, M., 1990. The Lander Trough, A central
Australian frontier exploration area. MEA Journal 30(1), pp 128- 136.
LITHOLOGY STRATIGRAPHY
BATHURST ISLAND GROUP
CARBONIFEROUS
Figure 9. Arafura Basin Stratigraphic Table
NORTH COASTAL BASINS
ARAFURA BASIN
The Arafura Basin covers an area of a t least 350 000 square kilometres
on the northern coast of the Northern Territory extending north under
the waters of the Arafura Sea past the Australia - Indonesia border.
It consists of northern and southern platforms with 5000 metres of
Neoproterozoic to Permian and possibly Triassic sediments separated by
the major northwest to southeast oriented Goulburn Graben in which
over 10 000 metres of section are preserved. The graben is
approximately 400 kilometres long and varies in width between 50 and
85 kilometres. The Arafura Basin sediments are unconformably
overlain by the relatively undeformed Middle Jurassic to Recent Money
Shoal Basin sequence. The Money Shoal Basin sediments thicken
gradually from less than 200 metres at the eastern end of the basin to
over 4000 metres in the west when the succession is continuous with
sediments in the Bonaparte Basin.
Neoproterozoic sedimentation consists of shallow marine sandstone,
mudstone, and minor carbonates deposited on a stable platform.
During the Cambrian and Ordovician the basin was dominated by
carbonate deposition. Late Devonian and Late Carboniferous sediments
consist of marine and nonmarine clastics and minor carbonates.
Graben development commenced in the Early Carboniferous but the major movement on the graben's bounding faults, uplift and folding
occurred in the Perrno-Triassic.
Major erosion of the Arafura Basin took place, probably during the
Middle Triassic to Early Jurassic, to produce the essentially peneplaned
surface on which the sediments of the Money Shoal Basin were
deposited. These sediments consist of Jurassic and Cretaceous
sequences of marine and continental clastics, predominantly
sandstones with miner coals, shales, claystones and marls, overlain by
a prograding Cainozoic carbonate sequence.
Nine exploration wells have been drilled in the basin nearly all within the
Goulburn Graben. Of these, four have recorded significant oil shows in
the Palaeozoic section. Four source rock intervals have been intersected
with TOC values u p to 8.3% in the Middle Cambrian.
The majority of the basin outside the Goulburn Graben area is
essentially unexplored. Results achieved to date show that
hydrocarbons have been produced in the basin and that the basin has
the potential to produce major discoveries.
Selected References
BRADSHAW, J., NICOLL R.S. and BWSHAW, M., 1990. The Cambrian
to Perrno-Triassic Arafura Basin, northern Australia. WEA Journal
30(1) pp 107-127.
NORTHERN TERRITORY GEOLOGICAL SURVEY, 1989. Petroleum Basin
Study - Arafura Basin. Prepared by Petroconsultants Australasia Pty Ltd.
Northern Territory Government Printer.
BONfiPARTE BASIN
The Bonaparte Basin covers a triangular area of about 270 000 square
kilometres extending northwest and north from the northwestern coast
of the Northern Territory and the adjoining area in Western Australia. It
mostly underlies the waters of the Joseph Bonaparte Gulf and Timor Sea
but about 20 000 square kilometres of the basin are onshore in the
Northern Territory and Western Australia. The offshore basin covers
areas administered by the Northern Territory, including the Territory of
the Ashmore and Cartier Islands Adjacent Area, Western Australia,
Indonesia and the Australia-Indonesia Zone of Cooperation Joint
Authority.
It is a composite basin resulting from the superposition of Palaeozoic
and Mesozoic extensional regimes. The onshore basin contains over
5000 metres of Palaeozoic sediments. Basal Cambrian to Early
Ordovician shallow marine and marginal marine clastics and
carbonates were deposited in a n intracratonic setting. An evaporitic
sequence was deposited in the basin probably in the Late Siluruan to
Early Devonian.
Extensive sedimentation recommenced in the Late Devonian when
rifting initiated the Petrel Sub-basin, a Palaeozoic depocentre with a strong northwest to southeast orientation containing up to 17 kilometres
of largely Palaeozoic sediments. It mostly underlies the Joseph
Bonaparte Gulf but extends onshore in the south. Continental to
shallow marine deposits of Late Devonian to Early Carboniferous age in
the onshore areas and equivalent shallow marine shales and thin
sandstones offshore are overlain by fluvial to marine clastics with minor
carbonates.
The succeeding Late Carboniferous to Permian sequence formed
during a phase of reactivated northwest rifting in which the Petrel Sub-
basin continued to be the principal depocentre. Coarse clastic
sediments with a strong glacial influence are overlain by lacustrine to estuarine deposits onshore and equivalent marine to deltaic
siliciclastic sediments and marginal marine sands and shales with
minor limestones and coals offshore. Early to Late Permian
sedimentation consists of a regressive - transgressive cycle ii-om
prodeltaic and open marine shales to marine and deltaic clastics with
FORMATION
UNNAMED
BATHURST ISLAND GROUP
TROUGHTONGROUP . . . . .
CARBONIFEROUS WEABER GROUP - - . . - . . . ... . - .
. . , . . . . . ' CARLTON GROUP
Figure 10. Bonaparte Basin Stratigraphic Table
minor carbonates. This succession is the Hyland Bay Formation which
contains the reservoir sections of the Petrel and Tern gas fields. To the
northwest of the Petrel Sub-basin fossiliferous limestones indicate the
presence of a broad carbonate platform of Late Permian age.
The close of the Permian marked a change from the older northwest
trending Palaeozoic structures to northeast trending Mesozoic
structuring. Broad regional sags become major depocentres in the Late
Triassic. True rift basins, the Nlalita Graben near the northwestern end
of the Petrel Sub-basin, and the Vulcan Graben 150 kilometres further
west developed in the Middle Jurassic with faulting along northwest to
northeasterly trends.
Basin subsidence in the Early Triassic resulted in marine transgression
and deposition of marine siltstones and shales unconformably on the
Hyland Bay Formation. This was succeeded by a nonmarine siliciclastic
sequence in the southeastern Petrel Sub-basin and an equivalent
clastic-carbonate sequence with minor coal and volcanics deposited in
fluvio-deltaic to shallow marine conditions further to the northwest.
Estuarine channel sands of this sequence form the reservoir units of the
Challis oilfield. A Late Triassic marine regression culminated in the
deposition of a Late Triassic to Early Jurassic redbed sequence across
the basin in an arid continental environment.
Subsequent transgression in the Early to Middle Jurassic resulted in the
deposition of thick fluvial to deltaic sediments of the Plover Formation
including important reservoir sands of the Jabiru, Skua, Sunrise and
Troubadour fields.
Widespread uplift and block faulting commenced in the area to the
northwest of the Petrel Sub-basin towards the end of the Middle
Jurassic and continued a t intervals throughout the Late Jurassic,
developing a northeast to southwest structural style dominated by
horsts, grabens and tilted fault blocks. Extensive erosion on the
structural highs removed Early to Middle Jurassic sediments exposing
the underlying Triassic sequence. Sedimentation recommenced in the
Late Jurassic. The deepest grabens filled with thick sequences of
restricted marine muds and claystones. Shallow marine siliclastic
sedimentation then extended over most of the basin.
A regional unconformity in the Early Cretaceous preceded the onset of
more rapid basin subsidence and a regional marine transgression
across the basin. Rapid eustatic fluctuations resulted in poor
preservation of most of the Early Cretaceous sequence. Late Cretaceous
carbonates were buried beneath a younger thick sequence of siltstones,
mudstones and shales. Sediments became more marine prior to a series
of sea level falls in the Late Cretaceous resulting in deposition of
strandline sequences around the basin margin, shoreline sandstones on
the eastern side of the Petrel Sub-basin and more distal fine grained
sandstones and marls to the northwest.
Open shelf marine conditions in the northwest and shallower shelf
conditions in the Petrel Sub-basin continued throughout the Cainozoic.
The Early Tertiary section is sandy grading upward into shelf carbonate
development with a hiatus occurring in the Oligocene. Late Miocene to
Recent deformation associated with the collision of the Australian
continental margin with the Southeast Asia Plate developed a Late
Tertiary east-northeast to west-southwest fault system and led to the
reactivation of some northeast to southwest trending faults.
Active petroleum exploration for over forty years in the Bonaparte Basin
has led to the establishment of production from four fields, Jabiru,
Challis, Cassini and Skua, all in the Territory of the Ashmore and
Cartier Islands Adjacent Area. Many promising but yet to be developed
fields have been discovered including Bayu-Undan, Laminaria, Elang,
Kakatua, Sunrise, Troubadour, Tern and Petrel. Many other significant
oil and gas shows have been encountered in formations ranging in age
from Devonian to Tertiary.
The Jabiru Oil Field is located in the Timor Sea about 650 kilometres
west of Darwin. It lies on the northeast - southwest trending Jabiru -
Turnstone Horst, an eroded Jurassic fault block within the complex
Vulcan Graben. Structural closure is fault dependent. The discovery
well, Jabiru-lA, drilled in 1983, encountered a 57 metre thick oil
column and flowed a t rates up to 6000 STBD from Middle Jurassic
sandstones. Twelve further wells have been drilled. Initial recoverable
reserves are estimated at 96 MMSTB.
The Challis Oil Field located 2 1 kilornetres south of the Jabiru Field lies
on the northeast- southwest trending Cleghorn Horst. Early Cretaceous
claystones unconformably overlie and seal sandstone reservoirs of
Middle to Late Triassic age. The discovery well Challis- 1 drilled in 1984,
encountered a 29 metre gross oil column and flowed a t the rate of 6730
STBD. Thirteen further wells have been drilled. The Cassini Field is
located on the Cleghorn Horst five kilometres to the southwest of
Challis. The discovery well Cassini-1, drilled in 1988, encountered a
thirteen metre oil column and tested at up to 7500 STDB. This is the
sole producing well of the field. Initial recoverable reserves for the two
fields are estimated a t 56 MMSTB.
The Skua Oil Field is located 100 kilornetres southwest of Jabiru on an
Early Jurassic fault block in the Vulcan Graben. The discovery well
Skua-2 drilling in 1985 intersected a nine metre oil column at the fault
bounded edge of the field. The confirmation well Skua-3 drilled in 1987'
encountered a 46.5 metre oil column in Early Jurassic sands and flowed
oil and gas at up to 5477 STBD and 8.5 MMSCFGD. Five further wells
were drilled. Total production from the field was 20.5 MMSTB.
Production ceased in February 1997.
As well as these commercial fields, significant oil and gas discoveries
have recently been made in Jurassic sands in the Australia - Indonesia
Zone of Cooperation Area A a t Elang, Kakatua (oil) and Bayu-Undan (gas
concentrate) and in the Ashmore and Cartier Islands Adjacent Area a t
Laminaria and Corallina (oil). It is expected that these fields will be
developed.
Other undeveloped discoveries in the Northern Territory portion of the
basin are the gas concentrate accumulations in Jurassic Plover
Formation sands at Sunrise and Troubadour, the Petrel gas
accumulation in Permian sandstone of the Hyland Bay Formation and
smaller accumulations of oil and gas at Barnett and Weaber in Early
Permian and Late Devonian sandstones respectively.
The discoveries made to date in the Bonaparte Basin from limited testing
of the more obvious targets show it to be one of Australia's most
prospective exploration areas and an important hydrocarbon province of
the future.
Selected References
BOnON, P.R. and WULFF, K., 1990. Exploration Potential of the Timor
Gap Zone of Co-operation. APEA Journal 30(1), pp 68-90.
McCONACHIE, B.A., BRADSHAW, M.T. and BRADSHAW, J., 1996.
Petroleum systems of the Petrel sub-basin - an integrated approach to
basin analysis and identification of hydrocarbon exploration
opportunities. APEA Journal 36(1) pp 248-268.
NORTHERN TERRITORY GEOLOGICAL SURVEY, 1990. Petroleum
Basin Study - Bonaparte Basin. Prepared by Petroconsultants
Australasia Pty Ltd. Northern Territory Government Printer.
O'BRIEN, G.W., ETHERIDGE, M.A., WLLCOX, J.B., MORSE, M.,
SYMONDS, P., NORMAN, C. and NEEDHAM, D.J., 1993. The
structural architecture of the Timor Sea, north-western Australia:
implications for basin development and hydrocarbon exploration. APEA
Journal 33(1) pp 258-279.
PATILLO, J. and NICHOLLS, P.J., 1990. A tectonostratigraphic
framework for the Vulcan Graben, Timor Sea region. APEA Journal
30(1) pp 27-51.
VVEST, B.G. and PASSMORE, V.L., 1994. Hydrocarbon potential of the
Bathurst Island Group, northeast Bonaparte Basin: Implications for
future exploration. APEA Journal 34(1), pp 628-643.
YOUNGER BASINS
CAFWENTARIA BASIN
The Carpentaria Basin is a broad north-south trending intracratonic
basin which covers an area of about 560 000 square kilometres, about
20% of which is in Northern Territory waters. It underlies and extends
to the south and southeast of the shallow Gulf of Carpentaria off the
northeastern coast of the Northern Territory where water depths are less
than 7'0 metres.
The basin formed as a gentle intracratonic down-warp in Jurassic and
Cretaceous times and contains mainly Mesozoic clastic sediments up to
2000 metres thick. To the west these onlap Proterozoic metamorphic
basement and unmetamorphosed Proterozoic sediments of the
McArthur Basin, and to the east Palaeozoic and Proterozoic
metamorphic and igneous rocks. The basin is separated by shallow
basement highs from the Papuan Basin to the north and the Eromanga
Basin to the south. Cambro-Ordovician sediments of the Georgina
Basin crop out to the southwest and equivalents may occur in
infrabasins beneath the Mesozoic section.
Middle to Late Jurassic sediments consist of fluvial sandstones with
minor siltstone and conglomerate, restricted to prior existing structural
lows, with some marine influence in the north of the basin. By Early
Cretaceous time, fluvial sandstone deposition was widespread in the
basin. A Middle Cretaceous transgression brought paralic and then
widespread shallow marine conditions to the basin with the deposition
of a thick mudstone sequence across the basin. A major regression in
the late Middle Cretaceous resulted in a return of paralic conditions.
Block faulting and uplift in the Late Cretaceous and Early Tertiary led
to widespread erosion and minor continental deposition. Marine
conditions returned to most of the basin during the Cainozoic.
Excellent reservoir potential exists in the Early Cretaceous sandstones,
sealed by the Middle Cretaceous mudstones. Drape closures over
erosional highs and fault traps are likely to be present. Oil shows have
been encountered in these rocks on the southern margin of the basin.
Excellent source rocks are known to exist in the Mesoproterozoic of the
McArthur Basin and the Cambrian of the Georgina Basin, which may be
present in infrabasins underlying the Mesozoic Carpentaria Basin
sequence. Mature Jurassic source rocks may be present in the deepest part of the basin. Cretaceous rocks are thought likely to be too immature for oil generation.
The most prospective part of the basin may be the northeast where possible pre-Jurassic source rocks have been identified, in seismic data.
Selected References
BURGESS, I.R., 1984. Carpentaria Basin: a regional analysis with
reference to hydrocarbon potential. APEA Journal 24(1) pp 7- 18.
THOlMAS, B.M., HANSON, P., STNNFORTH, J.G., STAMFORD, P. and
TAYLOR, L., 199 1. Petroleum Geology and Exploration History of the
Carpentaria Basin, Australia and Associated Infrabasins. In
LEIGHTON, M.W., KOLATA, D.R., OLTZ, D.F. and EIDEL, J . J . (Eds), Interior Cratonic Basins pp 709-724, American Association of Petroleum
Geologists Memoir 5 1.
STRATIGRAPHY HYDROCARBONS
EYRE FORMATION
CADNA-OWIE FORMATION ShaleISandstone
ALGEBUCKINA SANDSTONE
POOLOWANNA Sandstone, Shale Poolowanna, Coson, Thomas,
Siltstone, minor Coai Kuncherina, Waikandi
walk and^, Poolowanna
Figure 12. Eromanga Basin Stratigraphic Table
EROMANGA BASIN
The Eromanga Basin covers 1 million square kilometres of Eastern
Australia of which 10% is located in the southeastern corner of the
Northern Territory. This part of the basin contains a Mesozoic section
up to 2300 metres thick overlying Late Palaeozoic and older basins. The
pre-Permian section is not well understood but over 2000 metres of
Cambrian to Devonian clastics and carbonates have been drilled in the
Northern Territory part of the basin. The section is similar to the
Arnadeus Basin section to the west.
The Pedirka Basin sequence underlies the Eromanga Basin in an area
of 55 000 square kilometres of the border region between South Australia and the Northern Territory, 60% of the basin being in the
Northern Territory. It contains up to 1000 metres of Late Carboniferous
and Early Permian fluvio-glacial, lacustrine and coal swamp deposits. It
is overlain by the thin Simpson Basin sequence of u p to 200 metres of
Triassic fluvial and lacustrine deposits. Overlying this is the Eromanga
Basin with up to 2300 metres of Jurassic fluvial and Cretaceous
continental and marine clastics, blanketed by a thin veneer of Cainozoic
continental sediments of the Lake Eyre Basin.
The Eromanga Basin has two main depocentres, one extending into the
Northern Territory overlying the Pedirka and Simpson basins and the
other further southeast overlying the Carboniferous to Triassic Cooper
Basin in the South Australia Queensland border region. Commercial oil
and gas fields have been found in the Eromanga Basin overlying and
adjacent to the Cooper Basin but so far only one non-commercial oil
accumulation has been found in the Pedirka Basin region in the basal
Jurassic sandstone of the Eromanga Basin. Good to excellent reservoir
quality sandstones are found in the Jurassic to Early Cretaceous section
and numerous oil shows have been found in wells drilled in the Northern
Territory part of the basin. Abundant organically rich source beds have
been identified in Jurassic, Triassic and Permian sediments.
Cretaceous and Middle to Late Jurassic sequences are immature to
marginally mature in many areas but Early Jurassic and Permo-Triassic
sequences have reached the main oil generation window over large parts
of the Northern Territory portion of the basin. Abundant anticlinal traps
related to deep seated faulting form the main exploration targets in the
area.
Much of the exploration to date has been in shallower parts of the basin
where reservoirs did not have access to mature source rocks. Further
exploration in and close to the deeper Eringa and Madigan trough areas
will provide a better assessment of the hydrocarbon potential of the
Northern Territory part of the Eromanga Basin.
Selected References ALEXANDER, E.M., PEGUM, D., TINGATE, P.R., STAPLES, C.J.,
MICHAELSEN, B.H. and McKIRDY, D.M., 1996. Petroleum potential of
the Eringa Trough in SA and the NT. APPEA Journal 36 (1) pp 322-349.
NORTHERN TERRITORY GEOLOGICAL SURVEY, 1990. Petroleum
Basin Study - Eromanga Basin. Prepared by Questa Australia Pty Ltd.
Northern Territory Government Printer.
SENIOR, B.R., MOND, A. and HARRISON, P.L., 1978. Geology of the
Eromanga Basin. Bureau of Mineral Resources, Australia, Bulletin 167.