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

Page

5

7

9

9

9

12

15

15

15

17

19

21

25

27

31

33

33

35

41

41

45

CA RPENTARIA

Tanami Desert

THE NORTHERN T"TERRITORY

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

Page

4

6

14

18

20

24

28

30

32

36

42

44

Figure 2. Sedimentary Basins of the Northern Territory

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.

STRATIGRAPHY

Figure 6. Georgina Basin Stratigraphic Table

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

Figure 11. Carpentaria Basin Stratigraphic Table

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.