Abstract 60 - Second Sprigg Symposium Frontier Basins Frontier Ideas Uni Adelaide June 2000 by GSAustralia

Geological Society of Australia

ABSTRACTS Number 60

SECOND SPRIGG SYMPOSIUM Frontier Basins, Frontier Ideas The University Of Adelaide June 29 - 30th, 2000.

GEOLOGICAL SOCIETY OF AUSTRALIA INC. SOUTH AUSTRALIAN DIVISION IN ASSOCIATION WITH THE UNIVERSITY OF ADELAIDE, PETROLEUM EXPLORATION SOCIETY OF AUSTRALIA AND NATIONAL CENTRE FOR PETROLEUM GEOLOGY & GEOPHYSICS

SECOND SPRIGG SYMPOSIUM: FRONTIER BASINS, FRONTIER IDEAS June 29 - 30th, 2000 The University of Adelaide

ABSTRACTS & PROGRAMME

G.R. Wood (Compiler)

GEOLOGICAL SOCIETY OF AUSTRALIA ABSTRACTS No. 60 2000

ISSN 0729-011X © GEOLOGICAL SOCIETY OF AUSTRALIA, INC.

The Sprigg Symposium Committee gratefully acknowledges the support of

General Conference Sponsors PRIMARY INDUSTRIES AND RESOURCES SA

BEACH PETROLEUM

Schlumbepger

A U S T R A L I A N GEOLOGICAL SURVEY <)""» G A N I 8 A T I O N

Session Sponsors A USTRALIAN P

WOODSIDE A U S T R A L I A N

E N E R G Y

PETROZ

C R C

ETROLEUM OOFERATIVE ESEARCH ENTRE

Abstract Volume Compiled by

Sprigg Symposium Committee

Santos

Co-Chairpersons: Peter Tingate & Thomas Flottmanri Secretary: Angela Crimes Treasurer: David McKirdy Technical Coordinator: Geoff Wood Field Trip Coordinator: Nicholas Lemon Acknowledgments We would also like to thank Sherry Proferes, Tony Hayball, Hazel McKinnon, Maureen Sutton, Yvonne Philp, Paul Grech and Mary Odium for their help with computing and organisational tasks associated with the conference.

2000 Sprigg Symposium

FRONTIER BASINS FRONTIER IDEAS

DR. REG SPRIGG (1919-1994) Reg Sprigg has made notable contributions to Australian scientific and economic life. They manifest an enterprising and spectacular career. From 1944 to 1954, as Assistant SA Government Geologist, he participated, and inspired others, in extensive geological mapping of South Australia and in the conduct of a variety of resources surveys involving rocks ranging in age from Archaean to Pleistocene. During this period, his scientific interests led to the discovery, in 1946, on the western margin of the Flinders Ranges, of the Ediacara biota which has stimulated a world wide review of early animal life and its relationship to the base of the Cambrian. Impatient with the limitations provided by Government employment, Sprigg left the SA Mines Department in 1954 and set up the successful Geosurveys of Australia Pty Ltd to provide basic consulting geological and geophysical services previously not available to mining and exploration enterprises in Australia. In the course of this he made use of air photography, submersible vessels, SCUBA diving, acoustic sounding and seismic profiling. He took part in the formation of Santos Ltd and spearheaded exploration for petroleum in the Cooper Basin. In 1961 he formed Beach Petroleum N.L. Later, in 1968, increasing concern with the deterioration of the natural environment led to the innovative purchase of Arkaroola (Mount Painter) pastoral lease and its conversion into a wild life sanctuary and wilderness reserve centred on a comfortable but exhilarating tourist village. Reg's achievements were recognised early by the winning of the Tate Medal in the final year of his undergraduate study, and subsequently through the award of the Verco Medal of the Royal Society of South Australia, of the Lewis G. Weeks inaugural Gold Medal from APEA, of Honorary Doctorates of Science by the Australian National University and Flinders University, and by his appointment as an Officer of the Order of Australia. He was a Fellow of the Australian Academy of Technical Sciences and Engineering as well as Honorary Member of the Geological Society of Australia. Robin Oliver

2000 Sprigg Symposium

FRONTIER BASINS FRONTIER IDEAS

PROGRAMME Thursday, June 29

Horace Lamb Lecture Theatre

8.30-9.00 Registration -00 Opening Session Sponsor APCRC Chairperson: David McKirdy 9.00 - 9.15 Symposium Welcome to Delegates 9.15 - 9.30 Opening Address : (Bob Laws, PIRSA) 9.30 - 10.00 Keynote Address : Overview of Australian Frontier Basins (John Gorter, British Borneo) 10.00 - 10.30 Keynote Address : New Techniques and New Ideas for Exploring Offshore Frontier Basins (Geoff O'Brien, AGSO) 10.30- 11.00 Coffee Break 11 00 Session 2 Sponsor Woodside Petroleum Chairperson: Richard Hillis 11.00 - 11.20 Defining the Frontiers - Towards an Inventory of Australia's Sedimentary Basins (Tony Stephenson, AGSO) 11.25 - 11.45 Hydrocarbon Prospectivity of the Bight Basin - Petroleum Systems Analysis in a Frontier Basin (Jane Blevin et al, AGSO) 1150 - 12.10 Everything Old is New Again; Magnetics in the Gippsland Basin (David Moore et al, MPV) 12.10-12.20 Short Break 12.20 Session 3 Sponsor AGSO Chairperson: Rhodri Johns 12.20 - 12.40 Stratigraphic Forward Modelling in Frontier Basins (Cedric Griffiths, CSIRO Petroleum) 12.45 - 1.05 Continental Sequence Stratigraphic Concepts - A Review (Paul Grech & Nick Lemon. NCPGG) 1.05-2.00 Lunch 2.00 Session 4 Sponsor PIRSA Chairperson: Nicholas Lemon Recognising the Base of the Cooper Basin - Attributes and Hydrocarbon Potential (David Gravestock & 2.00 - 2.20 Elinor Alexander. PIRSA) 2.25 - 2.45 Source Rock Potential and Algal Matter Abundance, Cooper Basin, South Australia (John Lindsay & David Gravestock, ANU/PIRSA) 2.50 - 3.10 Assessment of the Cambrian Stansbury Basin and Petroleum Potential (Wenlong Zang & Les Tucker, PIRSA) 3.15,-3.45 Coffee Break 3.45 Session 5 Sponsor Geotrack Chairperson Clinton Foster 3.45 - 4.05 Tectonics and Hydrocarbon Potential of Lord Howe Rise (Phillip Symonds et al, AGSO) 4.10- 4.30 Petroleum Geology of the Onshore Maryborough Basin (Paul Lipski, Magellan Petroleum) 4.30 - 4.50 The Adelaide Geosyncline as a Frontier Continental Terrace (Bob Dalgarno) 9

5.00-6.00 7.00 for 7.30

Happy Hour Symposium Dinner

Sponsor Geotrack Sponsor Beach Petroleum 4

2000 Sprigg Symposium

FRONTIER BASINS FRONTIER IDEAS

Friday 30th June, 2000 9.30 9.30 - 10.00 10.00 - 10.30 10.30- 11.00 11.00 11.00 - 11.20 11.25 - 11.45 11.50 - 12.10 12.10-12.20 12.20 12.20 - 12.40 12.45 - 1.05 1.05-2.00 2.00 2.00 - 2.20 2.25 - 2.45 2.50 - 3.10 3.10-3.40 3 40 3.40 - 4.00 4.05 - 4.25 4.30 - 4.45

Horace Lamb Lecture Theatre

Keynote Session Sponsor Beach Petroleum Chairperson Angela Crimes Keynote Address: Challenges Today in Exploring Frontier Basins (Hector Gordon, Beach Petroleum) Keynote Address: Petroleum Geology and Geological Education (Brian McGowran, University of Adelaide) Coffee Break Session 2 Sponsor Petroz Chairperson Neil Gibbins The Resource and Risk Assessment of Hydrocarbon Plays in Australian Oil & Gas Producing Basins (Rhodri Johns, Santos) Structural Configuration and Petroleum Play Potential of the Ngalia Basin (Paul Lipski, Magellan Petroleum) The Georgina and Pedirka Basins Revisited (Greg Ambrose, NTGS) Short Break Session 3 Sponsor NCPGG Chairperson Jim Jago Basin-centred Gas Accumulations: A New Geological Paradigm (Richard Hillis, NCPGG) Gas Hydrates in Australia's Marine Jurisdiction: A Potential Long-Term Resource? (Phillip Symonds et al, AGSO) Lunch Session 4 Sponsor Schlumberger Chairperson Rod Hollingsworth The Greater Amadeus Basin, Northern Territory, Australia (Jamie Burgess, NTGS) Hydrocarbons of the Western Australian Officer Basin (Greg Carlsen, GSWA) A New Approach to the Estimation of Mixing Ratios in Reservoirs Containing Multiple Oil Charges (Xinke Yu, et al, University of Adelaide / PIRSA) Coffee Break Session 5 Sponsor PIRSA Chairperson Elinor Alexander Illite, The Key to Identifying Reservoir Potential in Previously Uneconomic Basement; Cooper Basin fChris Cubitt & Alex Kaiko, NCPGG / U of SA) Natural Fracture Plays of the Southern Cooper and Eastern Warburton Basins (Xiaowen Sun, Sun Petroleum Geoservices) Presentation of Best Paper Award / Closing Address (Geoff Wood / Margaret Sprigg/ Peter Tingate)

Saturday 1st July. McLaren Vale excursion/winery tour.

OVERVIEW OF AUSTRALIAN FRONTIER BASINS John D. Gorter British-Borneo Australia Limited, West Perth, Western Australia

Introduction Australia has more than fifty currently defined sedimentary basins, onshore and offshore, which have the potential to host economic oil and gas accumulations. Twelve of these basins have produced or are presently producing oil and/or gas; another three basins have sub-economic hydrocarbon accumulations. From the perspective of North America and the North Sea, only the Surat-Bowen, offshore Gippsland, Cooper, and the inner fairway of the offshore Westralian Superbasin (Barrow and Dampier sub-basins) can be considered to be mature to semi-mature for hydrocarbon exploration. The other 35 basins have no recognisably effective petroleum system, although many of these basins have indications of hydrocarbon potential in the form of shows of oil or gas. These basins are rightly referred to as the frontier of oil and gas exploration. At this Symposium (Table 1), only 14 basins, three offshore, are presented. The number is statistically invalid for comparative purposes, but some observations may be made: most of the basins considered at the Symposium are Late Proterozoic to Cambro-Ordovician. most are located broadly in the central parts of the continent and are remote from population centres. The two completely offshore basins presented are discussed by AGSO. If we consider the Gippsland, Carnarvon, Surat-Bowen basins and the northern onshore Perth and the Vulcan Sub-basin of the northern Browse basins as mature to moderately mature for petroleum exploration, and allowing for other factors including predilection of the authors for certain basins (ie. the conference is based in Adelaide and eight of the 14 basins are represented within the bounds of South Australia) etc, there are some 36 potentially petroliferous basins that are unaccounted for in this symposium. Table 1: Basins presented at the 2000 Sprigg Symposium Author/s Location in Age Basin continent Dalgarno Peripheral LP Adelaide Burgess LP-CO Central Amadeus B levin ?J-T Offshore Bight Arouri, Alexander & Gravestock, Cubitt & C-P Central Cooper Kaiko, Lindsay & Gravestock, Sun Arouri J-K Central Eromanga Gordon, Grech, Griffiths, Johns, Stephenson General Ambrose LP-CO Central Georgina Moore, Wong & Bernecker Peripheral- K-T Gippsland offshore Stagg et al., ?K-T Offshore Lord Howe Lipski Peripheral- J-K Maryborough offshore Lipski LP-CO Central Ngalia Carlsen LP Central Officer Ambrose C-P Central Pedirka Zang & Tucker Peripheral- C Stansbury offshore Sun C-0 Central Warburton U = University, G = Government, P = private sector including consultants

Work Place G G G UPPUP U PUGPG G G G P P G G G P

Definition of a sedimentary basin What is a sedimentary basin? How many sedimentary basins does Australia have? In simple terms, a sedimentary basin may be defined as a topographic depression in which sediments accumulate, that is, a sedimentary basin is accommodation space. Inherent in this definition is the tenet that once the accommodation space is filled with sediment, there is no longer an entity called a basin. Thus, basins, by default, have a finite life. They are born in downwarp and killed prematurely by uplift, or die quietly by senescence - fulfilled.

For example, we can easily define the Collie Basin in Western Australia as a faulted remnant of a transtensional, extensional graben system of Permian age (Hocking et al., 1994). It is well defined in both age and extent. But how do we describe the Canning Basin? In its original concept, the Canning has both onshore (mainly Palaeozoic) and offshore fill (mainly Mesozoic and Tertiary). The latter has been renamed the Roebuck Basin and forms part of the Westralian Superbasin (Hocking et al., 1994). This basin has many sub-elements, variously called troughs, graben and sub-basins, each with its own fill. The fill is often of different ages. Each element in fact conforms to the notion of a basin as a topographic depression into which sediments are deposited, and each has a specific life, although some may overlap in both time and space (eg. the Barrow and Dampier sub-basins of the Carnarvon Basin). In fact, basins form heirachies, with superbasins, basins, sub-basins, troughs and depressions all forming part of a complex family linked by common genetic threads, usually structural history and depositional architecture. Forman & Wales (1981) in their study of the onshore Canning Basin, defined basin formation episodes as Intervals; sedimentary packages deposited in response to major continental flooding cycles (including major transgressive and regressive facies cycles) confined by 'time lines, lithological boundaries, facies boundaries, or basin-wide diachronous breaks in sedimentation', that is, major erosion surfaces, akin to Sloss's unconformity-bounded stratal units (1948). Today we call these second order sequences, or megasequences, and each forms a basin-fill in its own right. These basins are thus defined by the age of the bounding unconformities. Broad parallels can be drawn between the Canning Basin and the Warburton-Cooper-Simpson-Eromanga basin complex in northeastern South Australia and southwestern Queensland. Each of these eastern basins is defined by enclosing regional unconformities and each contains all, or some, of the elements of a petroleum system. In these characters, they are broadly equivalent to the Intervals in the Canning Basin, and one wonders why each Interval does not have its own discrete name. Petroleum systems Each basin-forming interval can constitute a discrete petroleum system, as recognised in the Canning Basin by Forman and Wales (1981). Petroleum systems were defined as a mature source rock and all its generated hydrocarbon accumulations within a particular sedimentary basin (Magoon & Dow, 1994). The system was anchored in the existence of the source rock and the process of migration of hydrocarbons to a trap. Klemme and Ulmishek (1991) characterised hydrocarbon productive basins as having prolific and widespread source rocks at optimum maturity to trap formation. They identified periods of effective source rock deposition during the Phanerozoic (Table 2). These are the Petroleum Systems further developed by AGSO and discussed below. Those periods in bold in Table 1 were considered by Klemme and Ulmishek (1991) to be the major effective source rock intervals in the world. Clearly Australia is lacking the major Oligo-Miocene source rocks and, with exception of the southeastern basins, namely the Gippsland, effective Aptian-Turonian sources. Our most prolific effective sources after Gippsland appear to be the Late Jurassic, most likely the Oxfordian (and possibly lower Kimmeridgian), and the PermoCarboniferous. Bradshaw (1993) and Bradshaw et al. (1994) broadened the petroleum system definition to include a continent-wide framework of basins with similar age, facies, structural history and hydrocarbon potential. They termed the expanded concept Petroleum Supersystems, for example the Larapintine Supersystem is characterised by Early Palaeozoic marine rocks, including carbonates, evaporites and intervals of organic rich facies deposited between the major global glaciations in the Late Proterozoic and the Permo-Carboniferous. Under this definition, based as it is on the age and depositional environment of the source rocks, the Larapintine Supersystem should be distributed globally. In fact, these Supersystems can be broadly correlated with the Superbasin concepts, eg. Centralian Superbasin, Westralian Superbasin etc. The Larapintine Supersystem could perhaps be redefined as the Larapintine Superbasin, the common thread being Early Palaeozoic source beds deposited in depocentres connected by seaways.

Table 2: Stratigraphic distribution of effective source rocks in Australia Age/Petroleum System Australian basins Produced hydrocarbons Mesoproterozoic McArthur Jamison 1 oil (Urapungan) Neoproterozoic Centralian Dingo gas field (Centralian 1-3) Cambro-Ordovician Canning-AmadeusPictor and Palm Valley gas fields, (Larapintine 1-2) Georgina, eastern Officer Mereenie oil field, Byilkaoora oil Silurian Unknown (Larapintine 1-2) Early-Mid Devonian Unknown (Larapintine 2) Late Devonian-Tournaisian Canning, Galilee, Bonaparte Blina oil, Galilee oil, Barnett and Turtle (Larapintine 3) oil, ? Weaber gas, waggon Creek oil Visean-Namurian A Canning, ? Bonaparte ? Yulleroo gas (Transitional) Late Carboniferous-Early Permian Bonaparte, ? Canning, Torrens oil, Petrel-Tern gas, ? Perth gas, (Transitional Gondwanan 1) Perth, Cooper, Sydney Cooper oil and gas Late Permian-Middle Jurassic Perth, Carnarvon Dongara oil and gas, Rankin Trend gas, (Gondwanan 2 to Westralian 1) Rough Range, Nebo ? Leatherback oils, gas Late Jurassic North West Shelf Many oil and gas fields (Westralian 2) ? Perth Neocomian ? North West Shelf ? Cornea, ? Elang West oils, gas (Westralian 2, Murta) Perth, ?Murta Gage Roads oil Aptian-Turonian ? Gippsland (Westralian 3, Austral) Coniacian-Eocene Gippsland, Otway Major oil and gas fields (Austral) Oligo-Miocene Unknown (Austral) Pliocene-Recent Unknown (modified after Klemme & Ulmishek, 1991, Bradshaw, 1993, Bradshaw et al., 1994) The Supersystem concept was broken down into a series of Petroleum Systems separated by tectonic events and their attendant regional unconformities - essentially the Intervals of Forman and Wales. Each System is characterised by an interval or petroleum source rock, that is, Larapintine 1 has Cambro-Ordovician sources, Larapintine 2 has Devonian sources, and Larapintine 3 has Carboniferous sources. Any Silurian source, should it be located within Australia, would presumably fit into one if the existing systems or form a subset of one of these. These Petroleum Systems can also be broken down into smaller sub-systems. In essence, each 3rd order sequence is a petroleum system combining as it does source rocks, seals and reservoirs. It may also contain structures (eg. reefs, rotated slump blocks) or stratigraphic traps (eg. basin floor fans), and lack only the maturation element of the petroleum equation. If sufficiently thick, fourth and even fifth order cycles may qualify. The concept of Petroleum Systems as used by AGSO encompasses a mix of second and third order cycles, but the uniting factor in each system is the deposition of the prime source rock facies early in the systems history. Definition of a Petroleum System using this early source criterion breaks down when hydrocarbons migrate from one of the defined systems into another where they are trapped. For example, the Warburton Basin gas discoveries at Lycosa 1 and Moolalla 1 are reservoired in a Larapintine Petroleum System, as defined by age of reservoir, but was sourced from the face-loaded Gondwana Petroleum System Patchawarra Formation strata of the Cooper Basin. Structuring to produce the trap took place by fault rejuvenation during the Permian (Taylor et al., 1991). Similarly, the Eromanga Basin Jurassic-Cretaceous Murta Supersystem reservoirs are arguably all sourced from the underlying Cooper Basin Gondwana Supersystem, with intra Eromanga traps and seals.

What is the relevance of this to Frontier basins? Well, everything to do with the definition of Basins themselves. I contend that there are more sedimentary basins throughout Australia than are shown on the usual geological maps. Some of the larger, geographically defined basins, such as the Canning Basin, are composite basins, and should be explored with attention paid to each discrete Petroleum System, rather than a basin as a whole. Perhaps the experience of the Warburton-Cooper-Eromanga serves as a lesson: originally exploration was focussed on the marine rocks of the Warburton, with the Permian and younger rocks regarded as overburden until it was belatedly recognised that the Cooper section contained hydrocarbons. The Permian was explored aggressively with little attention paid to the oil shows in the Jurassic and Cretaceous, until Strzelecki 3 was tested in 1981. Then came the Jackson oil discovery, and the hunt was on for Eromanga hydrocarbons, but not, this time to the detriment of exploration in the Cooper Basin. Hydrocarbons were subsequently found in the Cadna Owie Formation and even younger Cretaceous sandstones. Expanded definitions of frontier basins In the last decade, there has been little real advance in the understanding of petroleum systems in basins that are not part of the main exploration focus. Many of these basins are under explored for different reasons, eg. remote locations with lack of infrastructure, or previously off limits because to technological constraints or land access. These are legitimate reasons for little or no exploration in such basins. However, Frontier basins can be defined in other ways than remoteness or lack of exploration. Basins where there has been no or little exploration for hydrocarbons Table 3: Frontier Sedimentary Basins - No Exploration Drilling in Last Decade Probable Petroleum System Last well drilled Basin Shows Permian, Cambrian? Gondwanan 1986 Arckaringa Yes ?Devonian, Larapintine None in last 10 years Bancannia Yes Permian-Cretaceous?, Austral No wells offshore Bremer Cretaceous-Tertiary?, Capricorn None in last 10 years Capricorn Jurassic-Cretaceous, Austral No wells in last 10 years Ceduna Devonian-Carboniferous, Larapintine? No wells in last 10 years Drummond Unknown, Austral No wells in last 10 years Eyre Cretaceous-Tertiary? Capricorn No wells in last 10 years Hillsborough No wells in last 10 years Cretaceous, ? Capricorn Yes Maryborough ? Permian, older, Larapintine/Gondwanan No wells in last 10 years Murray No wells in last 10 years Proterozoic, Centralian Yes Officer No wells in last 10 years Cambrian?, Larapintine Yes Ord Immature sources, 1985 Jurassic, Gondwanan-Westralian? Yes Polda No wells in last 10 years ? Cretaceous, Murta? Proserpine Permian, older?, Gondwana, Larapintine? Immature sources, 1988 Yes Renmark No wells in last 10 years Permian-Jurassic, Gondwanan Yes Simpson Cretaceous, Austral No wells in last 10 years Yes? Sorrel No exploration wells Permian, Gondwanan Sydney offshore No exploration wells Ordovician, Larapintine Yes? Wiso No exploration wells ? Carboniferous, Larapintine Yarrol No wells in last 10 years Silurian? Yass Table 3 is a compilation of the basins that have seen no exploratory drilling in the last decade. Some of these basins are located in deep water and some are in environmental protection zones. Others may be off limits for political considerations. Are there any geological factors in common among these basins that suggest the reason for their unpopularity with the exploration community? Some of the basins appear to be over mature for oil, but possibly not for gas (eg. Yarrol, Drummond), and some have proven immature oil sources (eg. Polda, Renmark etc.), although there are indications of older sources beneath the younger basin fill. 9

Basins where there has been some exploration with sub-commercial success Table 4: Basins with currently non-commercial discoveries Basin Reasons why no commercial production of existing discoveries and comments Bass Bonaparte Onshore Browse Carnarvon Victoria Syncline Carnarvon Plateau

Yolla field may go onstream soon Gas market, remote, native title Gas market, remote, Scott Reef field etc. large resource probably will be exploited Deepwater gas, market saturation? large resource probably will be exploited

Deepwater gas, remote, Scarborough field, although resource down-graded by Scarborough 2 Wilga Park 1 gas discovery Sub-commercial flows, Jamison 1 oil Gas markets, large resource probably will be exploited Petrel-Tern fields, expensive drilling, remote gas, large resource probably will be exploited

Gunnedah McArthur Otway offshore Petrel

Most of the basins in Table 4 with hydrocarbons can be seen to be gas discoveries either too remote from markets or in environmentally difficult areas, especially deepwater. The larger finds will undoubtedly go on stream in the future as markets are established and exploitation technology improves.

Basins that have been off-limits to exploration in last decade Table 5: Basins off-limits to exploration Basin Shows Probable Petroleum System

Capricorn Hillsborough Proserpine Wiso

Yes

Cretaceous-Tertiary?, Austral Cretaceous-Tertiary, Austral ? Cretaceous, Murta? Ordovician, Larapintine

Last well drilled

None in last 10 years No wells in last 10 years No wells in last 10 years No exploration wells

In the last 30 years, several basins have been withdrawn from exploration due to either environmental or political considerations. The Zone of Cooperation was reopened to exploration in 1991 after a 20 year moratorium. In the last ten years (Table 5), the largest no go zone is the area associated with the Great Barrier Reef - the northeastern offshore basins. Exploration in these basins associated with the Great Barrier Reef (eg. Capricorn, Hillsborough, Proserpine) is likely to be off limits for the foreseeable future because of the perception of possible ecological damage to the reef. Possibly some of the remoter inland basins are off limits due to the perception that they are subject to native title. However, the experience of the Pitjantjatjara lands in northern South Australia shows that this is resolvable, given time and the will. Frontier basins that probably fit in this category include the Wiso and parts of the Officer Basin. Exploration has recommenced in the western Amadeus Basin with Santos taking up a large part of the basin.

Basins where new ideas and modern technology have revitalised exploration In the offshore areas, 3D seismic surveying for exploration as well as appraisal is becoming increasingly undertaken. 3D is also being used onshore (eg. Northern Perth, Cooper basins) to increase the structural understanding of the traps. Seismic techniques, like pre-stack depth migration, have been used to better define structures, resulting in improved definition of traps. The recent Corvus 1 discovery and the successful exploration of the Gipsy-Rose-Lee trend, both in the Carnarvon Basin are examples of these new seismic technologies opening up new play fairways. Geological techniques like fluid inclusion stratigraphy are being combined with airborne or satellite-conveyed sensing systems to direct exploration in new and innovative ways. In combination these, and other new ideas and technologies are allowing exploration to progress in areas previously neglected. Thus, even productive basins can be reclassified as frontier given new ideas or technological advances. Several papers at this Symposium address these issues.

Frontier Basin Exploration in the last decade In the last decade, there has been some exploratory drilling in basins outside of the productive basins (Table 6). This drilling is discussed on a year by year basis from 1990 to the present. In the last decade, the only conventional frontier area that has proven to contain producible hydrocarbons has been the Victoria Syncline region of the offshore Carnarvon Basin. These discoveries can be rightly considered as a technology driven successful leap into deeper waters rather than the application of new ideas. Otherwise, the exploration sector has been spectacularly unsuccessful with even a series of follow-up or No. 2 wells proving non-commercial. 1990 At the end of 1990, there were 420 plus petroleum exploration permits on and offshore Australia. During the year, 117 exploration and eight stratigraphic wells were drilled in these permits. Perhaps the most exciting find was the Jamison 1 oil and gas discovery from the McArthur Basin of the Northern Territory (Lanigan et al., 1994). If there ever was frontier basin, this is one - Middle Proterozoic source beds of the Urapungan Supersystem in outback Australia. One of these wells, Anna 1, was an ambitious attempt at proving a rift basin origin for Spencer Gulf. The well was programmed for 3765 m, but was plugged and abandoned in basement at 257 m. Though a failure, the well showed that some organisations were prepared to try something new. If they had been correct, a whole new play would have opened. And speaking of new plays, the Lycosa 1 and Moolalla 1 gas discoveries in the Warburton Basin Larapintine System reservoirs beneath the Cooper Basin Gondwana source beds opened a new play style in South Australia (Taylor et al., 1991). 1991 During 1991 there were 423 Exploration permits throughout Australia and 88 exploration and eight stratigraphic wells were drilled. Most were in the recognised oily basins, but a few were targeted at basins that had little past success. There were no new discoveries reported outside of the petroleum fairways of the North West Shelf or the Cooper Basin. Ross 1, in 1991, was the last test of the Georgina Basin Larapintine Supersystem. The Georgina Basin is notorious for teasers - most wells have encountered shows of oil and gas, but the big one remains elusive. The basin contains world class Early Cambrian Larapintine 1 source beds, albeit thin. However, numerous wells have failed to recover hydrocarbons on test, although some gas was flowed from Ethabuka 1 in the 1970s. Chameleon 1 tested the of the Money Shoal Basin. This was the first test of the basin since the eponymous Money Shoal 1 in 1971. The well was plugged and abandoned. Crusader drilled an unsuccessful wildcat, Broken Rope 1, in the Gondwanan Petroleum System of Queensland's Laura Basin, and Big Desert 1 was a stratigraphic hole drilled in the Murray Basin. Blinman 2 was drilled as a follow-up test of Cambrian and Neoproterozoic strata in the Arrowie Basin of South Australia, but was plugged and abandoned as a dry hole with minor gas shows. This well sought hydrocarbons derived from an Early Cambrian source in the Larapintine 1 Petroleum System and reservoired in rocks of the same system. Wandoo 1 in the Dampier Sub-basin opened up a shallow partially biodegraded oil exploration play inboard of the existing oil province (Delfos, 1994). Oil was recovered at a depth of about 600 m in Early Cretaceous shallow marine glauconitic sandstones, and showed that long distance migration from Westralian Supersystem source rocks occurred in the basin. Wandoo became the model for this play style and was successfully exploited at the nearby Stag oil field, and much further afield by the Gwydion 1 and Cornea 1 discoveries in the Browse Basin. 1992 Eighty two wildcat and one stratigraphic wells were drilled within the 363 petroleum permits extant during 1992. Egilabria 1 was the last of three dry holes drilled in the onshore Carpentaria Basin in Queensland by Comalco, a minerals exploration company turned oil explorer. Unfortunately, it too was dry. This was test of Precambrian turbidite channel sandstones of the Urapungan Petroleum System, and followed the unsuccessful Argyle Creek 1, which tested secondary porosity in Precambrian carbonates, and Desert Creek 1, a test of both play styles.

One of the few attempts of exploring for hydrocarbons in an unconventional settings was explored by Snake Flat 1, drilled in the Darling Basin of New South Wales 150 km east of Broken Hill. The well targeted Early Devonian strata of the Larapintine 2 Petroleum System. The well was 'suspended indefinitely after several delays. ,

A new fairway was established in the Barrow Sub-basin with the discovery of gas in basal Tertiary reservoirs at Maitland 1. There is no apparent structural closure to the field and stratigraphic trapping of gas leaked from a deeper Westralian Supersystem traps with Jurassic source rocks is thought to be the reason for the accumulation. The presence of a significant gas accumulation was indicated by detailed amplitude versus offset analyses and modelling (Sit et al., 1994). Maitland North 1, drilled in 1996 confirmed the large extent of the field. 1993

1993 seems to have been a particularly lean year for exploration outside of the fairways, although there were 340 extant exploration licences at tear's end. Only two of the 77 wildcat wells were drilled outside of the productive basins. Cobra 1A in the Arafura Basin was dry, as was Burdo 1 in the McArthur Basin. Cobra 1A targeted the Jurassic Plover/Flamingo sands of the Westralian Petroleum System. However, Stag 1 continued the Wandoo play success in the Dampier Sub-basin. New techniques of depth conversion propelled the discovery of the East Spar gas field in the Barrow Sub-basin. East Spar had virtually no time closure at the top of the Barrow Group target horizon but careful velocity analysis recognised time pull up of the eastern flank, masking a significant structure in depth. This concept was later employed successfully in the discovery of the Woollybutt oil field, also in the Barrow Sub-basin. In addition, Nebo 1 was the first well to flow oil from the Beagle Sub-basin and proved the existence of effective Westralian Supersystem source rocks in the Thouin Graben. 1994

1994 was even worse for exploration of basins outside the productive areas. There were 339 exploration permits active during the year. There were no petroleum exploration wells drilled at all in what we would call frontier basins despite 92 wildcats. However, a basin that had been off limits to exploration since the early 1970s showed it could contain major hydrocarbon resources. In early 1994, Elang 1 encountered commercial oil in the Zone of Cooperation in the northern Bonaparte Basin (Young et al., 1995). Elang 1 was a successful extension of the Late Jurassic sourced oil discoveries in the Vulcan Sub-basin during the 1980s. Later in the same year came the Laminaria and Kakatua oil discoveries, proving the worth of the Westralian Petroleum System across the Timor Sea. 1995

There were 370 exploration permits in existence during the year in which 102 exploration wells and eight stratigraphic tests were drilled. Coonarah 2 in the Gunnedah Basin was drilled as a follow up to the 1993 dry Coonarah 1A. The second well recorded a gas flow, showing that the Gondwanan Petroleum System proven by the Wilga Park 1 gas discovery was still alive. Carmicheal 1 was a test of the Lake Galilee Sandstone (Larapintine System) in a large simple anticline 25 km south of the Lake Galilee 1 discovery well. The well showed the presence of non-commercial gas reservoirs and confirmed the occurrence of effective source beds in the Galilee Basin. Waggon Creek 1 tested a large stratigraphic-structural trap in an embayment on the western side of the onshore Bonaparte Basin. While details are scantly, the well had an 'excellent oil flow' reported from 588-610 with a flow of an estimated 1 million cubic feet per day from the 586-601 m interval. This was the first reported oil flow from the onshore Larapintine 3 Petroleum System in this basin. The Waggon Creek 1A well, drilled in 1996, showed that deeper horizons in the Milligans Formation were gas-saturated but tight. 1996

1996 was also a year to forget for exploration outside the fairways. Ninety nine wildcats and two stratigraphic tests were drilled in the 358 permits operative. However, Livet 1 confirmed the basal Triassic oil source (Gondwana 2 Petroleum System) of the Dongara area of the northern Perth Basin extended at least 200 km to the north. A residual oil column was found in the objective Permian-Triassic sandstones. 12

1997

1997 was a comparative boom year in frontier basin exploration. One hundred and eighteen wildcats were drilled and a further three stratigraphic holes completed in the 387 petroleum licences. Lake Kool 1 was drilled in the Pedirka Basin, targeting Namur Sandstones of the Murta Petroleum System, but was unsuccessful. Three wells were drilled by Amadeus Petroleum to test the lower Centralian 3 Petroleum System in the Savory Basin (Akubra 1, Mundadjini 1, and Boondawarri 1). Minor oil shows were reported in two of these wells, proving that oil sources are present (Carlsen et al., 1999). Tasmania was rediscovered during 1997, with several wells drilled in the Tasmanian Basin targeting the Larapintine 2 petroleum system (Bendall et al., 2000). The source rocks occur in the Ordovician section, underlying Silurian reservoirs and seals. The Gondwanan 1 and 2 petroleum system is also present with the Late Carboniferous-Early Permian Tasmanites oil shales, coals and marine strata providing the source of hydrocarbons for the Permian reservoirs. These wells, Shittim 1, Jericho 1, and Gilgal 1, were given biblical names, perhaps to enhance their prospects.

1998

One hundred and twenty eight exploration walls were drilled in 1998, with 341 exploration permits existing at year's end. Two wells, Apsley North 1 and Beryl Ridge 1, were drilled targeting the Murta Petroleum System in the Galilee Basin of Queensland. Both were dry, as was the Paradise 1 test of the Lissoy Sandstone Larapintine 2 Petroleum System test in the Adavale Basin. Weak gas shows were recorded in the Cooladdi Dolomite. Minor gas was reported from Newhaven 1 in the Centralian 3 Petroleum System in the Ngalia Basin. The well encountered no hydrocarbons and the permit was not renewed on expiry in 1999 leaving the entire Ngalia Basin without an active exploration permit. 1998 also saw a welcome return of explorers to the Stansbury Basin in South Australia. The offshore Enchilada 1 well tested the Cambrian Parara Limestone in Larapintine 1 System strata, but was dry. Frijole 1, in the same permit, was also dry at the target horizons.

1999

In total, only 76 wildcat wells were drilled during the year, in the existing 368 petroleum permits. Probably as a response to plummeting oil prices and the lemming instinct of oil explorers, only one exploration well was spudded onshore outside of the productive basins. This well, Glamorgan 1, was drilled within the Clarence-Morton Basin, but failed to flow on test of the Triassic in the Esk Trough. However, exploratory drilling near the southern Victoria Syncline, northern Kangaroo Syncline, and Saturn Graben depocentres in the outer Carnarvon Basin has resulted in the discovery of several large gas fields, including Geryon 1 and Orthrus 1. Both wells are believed to have indicative gas reserves in the order of 5 trillion cubic feet. These fields produce from the Late Triassic Mungaroo Formation sandstones, and are presumably sourced from Triassic strata of the Westralian Petroleum System.

2000

The year is only half over, and already there have been important events in the exploration of the 358 exploration permits in Australian sedimentary basins. Thirty three exploration wells had been drilled to mid June. Two of these, while not directly related to exploration in frontier basins, were the maiden discoveries by Japanese-led consortia in Australian basins: Inpex with its Dinichthys 1 discovery in the Browse Basin, and Nippon with its Crux 1 success in the Vulcan Subbasin. Both discoveries relied on the acquisition of 3D seismic in the exploration phase. Urania 1 and Maenad 1 continued the gas successes in the outer Carnarvon Basin. Also, the discovery of gas in Prometheus 1 by Kerr-Magee extends the Gondwana petroleum systems significantly westward of the southern Bonaparte Basin Petrel and Tern gas fields Oil exploration recommenced in the onshore Sydney Basin with Amadeus Petroleum's first well, Glenmore 1, reporting four separate oil and gas shows, with oil bleeding from cores. The well was plugged and abandoned but is significant that it highlighted the oil potential of the Gondwanan Petroleum System in an area with the largest domestic market but no local hydrocarbon production. In the southern Perth Basin, Rutile 1 tested the Gondwanan Petroleum System Late Permian Sue Coal Measures with wireline logs indicating oil shows observed to be residual. The well, located 20 km south of the Whicher Range gas field, is important, as it is the first clear indication of oil production in this part of the basin. 13

Table 6; Frontier Sedimentary Basins - Last Decade Drilling Results Basin Source Age Last well drilled Arafura Cambrian Arrowie Cambrian Carnarvon Victoria & Kangaroo Synclin Triassic-Jurassic Carpentaria Jurassic-Cretaceous Clarence-Morton Cretaceous Cowell ? Proterozoic Darling Devonian Duntroon Cretaceous Galilee Devonian Georgina Cambrian Gunnedah Permian McArthur Mid Proterozoic Money Shoal ?Permian-Jurassic Ngalia ?Proterozoic Pedirka Permian-Triassic Perth Offshore Triassic-Cretaceous Savoury Proterozoic Stansbury Cambrian Sydney Permian Tasmanian Cambrian? Warburton Cambrian

Cobra 1A, 1993, dry Blinman 2, 1991, dry Recent major gas finds 1999-2000 Egilabria 1, 1992, dry Glamorgan 1, 1999, dry Anna 1, 1990, dry Snake Flat 1, 1992, dry Vivonne 1, 1993, dry 1998, two wells, dry Ross 1, 1991, dry Coonarah 2, 1995, dry Burdoo 1, 1993, dry Chameleon 1, 1991, dry Newhaven 1, 1998, dry Lake Kool 1, 1997, dry Felix 1, 1998, dry Three wells, dry, 1997 Enchilada 1, Frijole 1,1998, dry Glenmore 1, 2000, oil and gas shows Several wells, 1997 Face loading younger strata, 1990

CONCLUSIONS

In this broad overview, I have tried to show that the numbers of potentially hydrocarbon productive sedimentary basins in Australia, both onshore and offshore, are possibly underestimated by lack of the application of consistent definitions. I believe that there are more basins present than currently defined, and that each has its own exploration fairway. Utilisation of the Petroleum Systems concepts, while broadly applicable and useful for the description of the hydrocarbon potential throughout Australian, may allow unique petroleum systems in some of these basins to go unrecognised as explorers pursue current paradigms. Exploration is driven by success - explorers expect the best results when drilling near existing discoveries. Consequently, there is little attention paid to areas outside the productive regions, perhaps in part due to the currently perceived lack of potential under contemporary geological thinking. As stated by Wallace Pratt, 'Oil is found in the minds of men', and we need to use more imagination, as well as evolving technological sophistication in the pursuit of hydrocarbons. While the term frontier can be applied in a strictly geographic sense, to encompass remoteness of particular basins, or the lack of significant exploratory drilling, it can also be applied to productive basins where new ideas, or new technology, have allowed the development and/or access to additional reserves. I will conclude with the observation: No Australian 'frontier' basin has reached the status of productive basin within the last 10 years.

REFERENCES BENDALL, M.R., BURRETT, C.F., & ASKIN, H.J., 2000, Petroleum systems in Tasmania's onshore frontier basins, The APPEA Journal, 40 91), 26-38. BRADSHAW, M., 1993, Australian petroleum systems, PESA Journal 43-45. BRADSHAW, M., BRADSHAW, J., MURRAY, A.P., NEEDHAM, D.J., SPENCER, L., SUMMONS, R.E., WILMOT, J., & WINN, S., 1994, Petroleum systems in West Australian basins, in Purcell, P.G., & R.R., (Editors), The Sedimentary Basins of Western Australia, PESA Symposium, Perth, 93-118. CARLSEN, G.M., APAK, S.H., GHORI, K.A.R., GREY, K., & STEVENS, M.K., 1999, Petroleum potential of the Neoproterozoic western Officer Basin, Western Australia, based on a source rock model from Empress-1, The APPEA Journal, 39 (1), 322-342. DELFOS, E., 1994, Wandoo oil field - a formation evaluation case history, in Purcell, P.G., & R.R., (Editors), The Sedimentary Basins of Western Australia, PESA Symposium, Perth, 615-631. FORMAN, D.J., & WALES, D.W., 1981, Geological evolution of the Canning Basin, Western Australia, Australian Bureau of Mineral Resources, Bulletin 210. HOCKING, R.M., MORY, A.J., & WILLIAMS, I.R, 1994, An atlas of Neoproterozoic and Phanerozoic basins of Western Australia, in Purcell, P.G., & R.R., (Editors), The Sedimentary Basins of Western Australia, PESA Symposium, Perth, 21-43 LANIGAN, K., HIBBIRD, S, MENPES, S, & TORKINGTON, J., 1994, Petroleum exploration in the Proterozoic Beetaloo Sub-basin, Northern territory, The APEA Journal, 34 (1), 674-691. MAGOON, L.B., & DOW, W.G., 1994, The petroleum system, American Association of Petroleum Geologists, Memoir 60, 3-24. KLEMME, H.D., & ULMISHEK, G.F., 1991, Effective petroleum source rocks of the world: Stratigraphic distribution and controlling depositional factors, American Association of Petroleum Geologists, Bulletin 75, 1809-1851. SITT, K.H., HILLOCK, P.M., & MILLER, N.W.D., 1994, The Maitland gas discovery - a geophysical/petrophysical case history, in Purcell, P.G., & R.R., (Editors), The Sedimentary Basins of Western Australia, PESA Symposium, Perth, 597613. SLOSS, L.L., 1988, Forty years of sequence stratigraphy, Geological Society of America, Bulletin 74, 93-114. TAYLOR, S., SOLOMON, G., TUPPER, N., EVANOCHKO, J., HORTON, D., WALDECK, R , & PHILLIPS, S., 1991, Flank plays and faulted basement: new directions for the Cooper Basin, The APEA Journal, 31 (1), 56-73. YOUNG, I.F., SCHMEDJE, T.M., & MUIR, W.F., 1995, The Elang discovery established a new oil province in the eastern Timor Sea (Timor Gap Zone of Cooperation), The APEA Journal, 35, (1), 44-64. ACKNOWLEDGMENTS I thank Peter Baillie, Grant Ellis, Clinton Foster, Louise Hann, Ian Longley, Eugene Petrie, and Eva Skira for information, discussion and/or comments on this manuscript. However, the views expressed are mine and corrections of any errors will be gratefully received. Permit numbers and wells drilled were obtained from the GPInfo database and AGSO annual drilling files. Note the numbers do not always tally between the two data sets.

NEW TECHNIQUES AND NEW IDEAS FOR EXPLORING OFFSHORE FRONTIER BASINS Geoffrey W. O'Brien Petroleum and Marine Division, Australian Geological Survey Organisation (AGSO), GPO Box 378, Canberra, ACT, 2601

INTRODUCTION

The evaluation of the hydrocarbon prospectivity of offshore frontier basins presents explorers with a number of challenges. At the broadest level, the fundamental exploration uncertainty is easily defined - does the basin in question contain a petroleum system, and if so, how viable is it? Around Australia, this question needs to be refined somewhat in view of the relative distribution of known gas reserves. On the North West Shelf, tens of TCF of "stranded" gas are present within the Carnarvon and Bonaparte Basins. Consequently, whilst the presence of viable oil and gas petroleum systems is undoubted in these basins, the exploration focus there is now largely on discovering oil, rather than gas. An exception is the "brown-fields" exploration around known, commercial gas accumulations. Similarly, exploration within essentially frontier basins such as the Canning and the Browse is focussed on discovering oil, which can be produced more quickly and cheaply, and sold into a spot market, rather than gas. The situation is similar throughout almost all of the other frontier basin systems around Australia (particularly those in relatively deep water), with the only possible exception being the medium term requirement for additional gas reserves in south-eastern Australia. Given these realities, the emphasis of this discussion is on outlining some of the approaches which can potentially lead the explorer to an adequate resolution of the questions: 1. Does the basin system contain a viable petroleum system? 2. What is the likelihood that the petroleum system has a significant liquids component? And, 3. Where, at a first-order, are the most favourable hydrocarbon catchments? One particular challenge in evaluating frontier basins, particularly in deep water, is that the basins tend to be very large, but the available data coverage tends to be sparse, and be comprised of data of numerous vintages and qualities. Indeed, the nature of these regions almost guarantees that much of the data within the area will have been acquired for research purposes (such as geological surveys, DSDP and ODP holes etc) or for boundary definition (i.e. Law of the Sea purposes etc) by geoscience research institutions. As such, these data are often neither ideally located nor of the desired type and/or quality for petroleum exploration. However, given the high cost of acquiring new data in these often remote and deep-water regions, these data sets will typically comprise a key part of the data suites upon which exploration decisions are eventually made. Ultimately, these frontier basins are characterised by an almost unique, and seemingly contradictory, combination of factors, namely: • •

they have poor data coverage and are poorly understood, and exploration costs, because of the remoteness and the water depths (several tens of millions of dollars per well), are many times that of continental shelf basin systems such as the North West Shelf.

Clearly, in this situation, it is imperative that the existing data be managed well, that as robust-as-possible, but necessarily model-driven interpretations be applied to these data, and that cost-efficient new data be acquired to complement the interpretations and the existing data sets.

TOOLS AND INTERPRETATIVE APPROACHES / PREMISES FOR EVALUATING FRONTIER BASINS Conjugate Margin Reconstruction

At the broadest scale, identification of oil-prone source rocks can be attempted at the margin scale. Reconstructing the evolution of the conjugate margins within which the frontier basin system lay, particularly in relation to global anoxic events, palaeo-oceanography and palaeo-geography, can provide a powerful "first-look" at the potential of the region. More recently, such tectonic approaches can be combined with detailed oil family

biomarker studies, to provide a powerful and iterative process. For example, it is now possible to compare and contrast the oil families on the North West Shelf, and in the Perth Basin, with those from Greater India. Similarly, work is under way to compare oils from the Bassian rift with oils from New Zealand and New Caledonia. Such approaches may confirm preconceived notions of margin development. However, where significant differences do occur, for example where the conjugate oil families do not support the plate tectonic reconstructions, then perhaps the plate models themselves should be examined more closely. Similarly, the approach might identify "missing" oil systems on one side of the margin as compared to the other. Basin and Basement Architecture The most basic geoscience data set available to assist in the evaluation of frontier basins is bathymetric data. These data consist of a number of types with varying resolutions. At the broadest scale, satellite-altimeter based predicted bathymetry provides a continuous overview of the probable seafloor architecture in deep water areas. However, whilst useful at delineating broad features, these data can have large (>1,000 m) errors. The best type of seafloor bathymetry in deep water is produced by swath-mapping, which provides a continuous, highresolution coverage of the seafloor. In addition to bathymetry, swath data also provide a record of the acoustic characteristics of the seafloor sediments, which might ultimately be useful in environmental assessments, as well as in designing drilling configurations and seafloor production facilities. Finally, the capturing digitally, and merging of, disparate bathymetric data sets, such as ship-board line data (often acquired during seismic acquisition) and Navy Hydrographic data can provide very good resolution data, particularly on the shelf and upper slope. Bathymetric data, at their simplest, provide a good first-order view of the location of the major basin systems, marginal plateaux etc. However, merging of the bathymetric data with regional seismic, ship-board gravity and magnetics data, satellite-gravity data, plus aeromagnetics data if available, can also provide a good regional overview of possible primary structural highs/hydrocarbon catchments. Experience from around the Australian margin has shown that virtually all of the major basin boundaries or intra-basin boundaries, are strongly basement-involved. Basement structures which strike sub-parallel to parallel to the rift-related extensional transport direction will almost invariably localise significant fault relay systems above themselves within the syn-rift section. Due to the significant fault overlap along these trends, these basement highs often produce overlying, major, cross-basinal svn-rift highs which often become prime areas for hydrocarbon migration and entrapment. These areas are also often preferential entry points (both in the syn- and post-rift phases) for siliciclastics, particularly during low seal-level stands. Such highs are also often evident within the bathymetry data, due to differential compaction of the syn- and postrift sediments between the relay system and the flanking grabens. Given the poor seismic control in these areas, maps of the basement grain, derived from combinations of the bathymetry and potential data, can be used to predict the location of likely fault-relay systems. Bathymetric data are also ideal for mapping the locus of recent fault reactivation, be it due to flexure or convergence, and as such can assist significantly in understanding the regional geological framework of remote basin systems. Evaluating Hydrocarbon Migration and Leakage An accurate assessment of the characteristics of the petroleum system within a frontier basin can be achieved using a simple, but extremely iterative approach. Key data sets which can be used include: 1.

Remote sensing geochemical tools. These tools include: • Synthetic Aperture Radar (SAR). This satellite-based tool measures the smoothing effect of liquid hydrocarbons on the surface of the sea (slicks). SAR data can cover large areas (1,000 to 2,250 km2) at relatively low cost (~$2-4 per square kilometre), though it can only reliably detect oil seepage. It is poorer at detecting condensate (unless seepage rates are high) and cannot detect seeping gas at all. • LandSat data. This satellite-based tool can detect oil slicks by a variety of means, including the sunglint that the slick. It is broadly similar in cost to SAR, but would most probably be used to investigate slicks identified by SAR, rather than as a primary slick-detection tool. • Airborne Laser Fluorosensor (ALF). ALF is an aircraft-based tool that detects aromatic hydrocarbons on the surface of the sea by exciting them with a laser pulse. It is much more expense than SAR but can potentially provide spectral information on the hydrocarbons. ALF can detect both oil and condensate seepage. • Water Column Geochemical Sniffer (WaSi) and Towed Fluorometer. A combination of these shipbased, towed devices can provide molecular compositions and concentrations within the water, 17

subsequent isotopic analyses of the detected hydrocarbons, as well as (potentially with the fluorometer) characterisation to the oil family level. Sniffer-fluorometer data are the most expensive, but provide the most detailed information. Sniffer can detect and characterise oil, condensate and gas seepage, as well as allow the discrimination between gas of biogenic versus thermogenic origin. Sniffer data are most useful when acquired close to the seafloor (within 10-20 m), which places a realistic operating limit on the tool at about 300 m water depth. • Sea-bed coring. Sea-bed cores and grabs can be taken over suspected seepage locations. Analyses which can be undertaken include geochemical analyses of the gases, fluorometric analyses of the extracted aromatic hydrocarbons, and characterisation of the bio-geochemical processes (i.e. the microbiota) within the sediments, particularly in relation to the presence or absence of hydrocarbon-oxidising bacteria. 2. Seismic data. Direct hydrocarbon indicators (DHIs) on seismic data provide an indication of the presence of a petroleum system. DHIs include gas chimneys, seismic amplitude anomalies and hydrocarbon-related diagenetic zones (HRDZs). None of these provides any definitive indication of the viability of the petroleum system, nor do they necessarily indicate whether the system is oil-prone or gas-prone. In deep water areas, such as the Lord Howe Rise, bottom simulating reflectors or BRSs indicate the presence of large gas hydrate deposits. However, in the main, seismic data are not particularly useful for determining the saturations of hydrocarbons within the pore spaces, or the flux of hydrocarbons through gas chimneys, for example. 3. Seafloor effects. Hydrocarbons seeping at the seafloor produce a variety of physical and acoustic effects which can be evident in both bathymetric and seismic data. Seafloor pockmarks form via the rapid venting of gas and often have attendant acoustic anomalies associated with diagenetic processes. Hydrocarbon seeps also often support a large number of unique biological communities, which use the hydrocarbons as a food source. Such eco-systems are often clearly visible on side-scan sonar data, for example. 4. 3.5 kHz echo-sounders. Gas seeping from the seafloor often produces a prominent "plume" within the water column. A SIMPLE APPROACH TO BASIN EVALUATION In most frontier basins, only a limited sub-set of the required data for assessing prospectivity will be available. As such, it is important to obtain as much "leverage" as possible from the data that the explorer does have. For example, whilst most evaluations of frontier basins would employ SAR data, given the low cost and the significant multiplier effect of the data, the geochemical sniffer is unsuitable for use in deep water (> -300 m). High quality swath data will not be available regionally throughout most basins, though Navy Hydrographic data probably will. Using examples gleaned from around Australia, and throughout the world, the following represents a generalised, but appropriate, technical approach. • • •

Identify any obvious potential "sweet spots' at the margin scale from models of conjugate margin evolution. Map regional sediment thickness, with a "cut-off appropriate to the inferred thermal history. Major basement features within sedimentary basins systems are preferential relay zones and hence potentially first-order hydrocarbon catchments. As such, these potential fairways should be investigated as a priority, using combinations of available seismic, bathymetry and potential field data. • Most prolific hydrocarbon basins world-wide contain a significant number of hydrocarbon seeps, with the reverse also being true. In general, the best place to identify seeps, and to assess the hydrocarbon migration and charge characteristics of a region, is not within the axes of the basins (where source rocks are best developed), for there the regional seals tend to be thick, with high top seal capacity. Rather, seepage is typically focussed along either major fault systems bounding the depocentres, around structurally prominent basement highs (where the top seal tends to be thin), or at the up-dip limit of the migration fairway, along the regional zero-edge-of-seal. It is thus imperative that any seepage detection data be integrated fully with the regional petroleum geological framework, rather than be used as a proverbial "black box". Integration of SAR data with seismic and other geological data can provide a useful assessment of the likely character of the migrating hydrocarbons and the associated seeps within the basin systems. At the basin scale, for example, the density of SAR slicks per square kilometre does appear to reflect the overall prospectivity of the respective basin systems, at least with respect to oil - this is both true around Australian and overseas. 18

Even within individual basins, the slick density can be shown to be largely a function of whether the primary hydrocarbon is condensate (little SAR effect; low slick density) or oil (strong SAR effect; high slick density). At the finest (prospect) scale, gas chimneys might be common and extend to close to the seafloor, but there is no associated SAR response - here it may be that the seeping hydrocarbons are principally gas, or that the rates of migration and seepage are very low. In this case, examination of the seafloor for pockmarks and seismic amplitude anomalies might resolve the situation. • Once hydrocarbon seeps and their associated migration fairways have been identified using a combination of SAR, seismic and other data, a targeted remote sensing program, using more expensive, essentially "concept-testing" technologies, such as ALF, sniffer-fluorometer and sea-bed coring, might be employed prior to very expensive acquisition of detailed seismic or the drilling of wells.

DEFINING THE FRONTIERS - TOWARDS AN INVENTORY OF AUSTRALIA'S SEDIMENTARY BASINS. A. (Tony) E. Stephenson 1 Australian Geological Survey Organisation, GPO Box 378 Canberra ACT 2601 1

SUMMARY In order to understand the petroleum and other resource potential of Australia's frontier basins, it is first necessary to know the location and physical and geological attributes of those basins. Whilst much data on particularly larger basins has been collated at State/NT scale, no comprehensive inventory of basins exists at national scale. AGSO's pre-existing collation of basins contains most of the larger basins, but omits more than 200 mainly smaller basins that have been cited in the literature. In addition, recent work associated with the Law of the Sea has seen our knowledge of offshore basins in frontier areas expand considerably. AGSO's new Basin Evaluation Project is addressing these shortcomings by compiling an inventory of all known sedimentary basins in Australia and its ocean territories, to be made available on CD and via the Internet, as part of the national geoscience database. The detail available on each basin will vary with both its relative resource importance and our current level of knowledge. The inventory will also cite key references and further sources of information, and include hot-links to State/NT and other organisations' Internet sites as appropriate. It is in part designed to give an overview of Australian basins to those in the international petroleum industry not familiar with the details of Australian geology and petroleum potential. DEFINING BASINS For the purposes of the basin inventory, my definition of a basin is - A package of rocks deposited primarily in a sedimentary environment, and preserved in the geologic record. Pockets of sediment preserved in primarily volcanic provinces are not regarded as basins. Basins can be highly metamorphosed and will still be noted very briefly in the inventory (see induration indicator below). However the duality of such basins is recognised, and most will appear in the wider AGSO national databases as metamorphic provinces. Note also that the definition of basin refers to rocks preserved today, not the container in which they were originally deposited. Except in the broadest sense, there has been little agreement in Australian geoscience as to what constitutes a basin. One worker's basin is another's trough, sub-basin, depression, outlier, remnant, embayment, infrabasin, block, province, platform, shelf, rift, metabasin, (super)-sequence, fold belt or orogenic zone - the description used has varied with one's perspective. All such descriptions have merits in the appropriate context, but can cause vast confusion to those not familiar with the detail and rationale behind them. The basin inventory will note all such usages for each basin, but to put each basin into perspective a four-indicator classification scheme has been developed. Two of these indicators will not change with time: size indicator and induration indicator. The other two - knowledge indicator and genesis indicator - will probably change over time for many basins as geological knowledge and understanding of basin-forming processes improves. Size indicator Sedimentary packages are deposited over a wide range of areas, but area/thickness ratios are limited. The physical processes that form and preserve basins favour certain geometries. In other words, whilst it is possible for very thin beds or formations to cover an extensive area within a sedimentary basin, basins as geometric entities generally fall within preferred size ranges. The major bounding factors at the thin end are likely to be the effects of baselevel fluctuation during deposition, and of erosional processes after accumulation. At the thick end, the major bounding factors will be the limits of tectonic and isostatic response inherent in the physical properties of the crust. There are exceptions to any rule of thumb, and with basins this can occur when erosional processes have had insufficient time to remove thin veneers of sediment, even if those sediments are now above baselevel. The Miocene, lacustrine Billa Kalina Basin in South Australia is one example of an extensive but very thin basin. It appears likely that where baselevel (and thus accumulation and erosion) is linked to sealevel, the natural variations in global sealevel work against the long-term preservation of sedimentary packages thinner than the quanta of those sealevel variations. Basins thinner than 100 m are relatively rare, and appear to be restricted to intracratonic settings, although the possibility of sampling error in that these may be overlooked in the literature is recognised. At the other extreme, very thick basins can form in a small area in some plate tectonic settings the Burdekin Basin is an example - but again these basins are atypical end members. 20

For the purposes of the basin inventory, it has been useful to classify basins according to size and thickness using a log/log scale, as below. The same scheme can be used to categorise sub-basins or other structural elements within larger basins. Together with the induration indicator, the size indicator is designed to give an immediate impression of a basin and by implication its possible petroleum potential. More importantly, the size indicator cuts through the plethora of descriptive terms that have been used to describe sedimentary packages, and imposes a clearly understandable commonality. I have included optional descriptions for each order of magnitude of basin area, but the alphanumeric indicator incorporating maximum thickness is more useful. Category H and smaller sedimentary packages of less than 1 km in area are not included in the basin inventory. 2

Minimum area (m )

Size Indicator

(1,000,000 km )

1 x 10

(100,000 km ) 2

(10,000 km ) 2

(1,000 km ) 2

(100 km ) 2

lxlO

Megabasin* Megabasin Megabasin A2 A4 A3 Large Basin Large Basin Large Basin B2 B4 B3 Medium Basin Medium Basin Medium Basin C4 C2 C3 Small basin Small basin* Small basin D2 D4 D3 Minibasin Minibasin E4 E2 E3 Microbasin Microbasin F4 F2 F3 Tiddler G4 G2 G3 Sprat* -

A1 -

B1 1 x 10 Medium basin* CI 1x10* Small basin* D1 1 x 10 Minibasin* El l x l O Microbasin* F1 Tiddler lxlO G1 Sprat 1 x 10 H2 HI 1

lxlO

(10 km ) 2

(1 km ) 2

(0.1 km ) 2

Minimum thickness (m)

* Rare or unlikely basin area/thickness configurations.

H4 4

3 lxlO

lxlO

For example, the following size indicators apply to selected Australian basins: Minimum area (km ) 2

Eromanga A3 Carpentaria B3 Arrowie C3 . Duaringa D3 Collie E3 Insolvency F3

1,000,000

Karumba B2 St Vincent Billa Kalina C2 CI 10,000 Denman D2 D1 1,000 Calen E2 El 100 Ngarrabullgan F2 F1 10 Wilga Silver Valley G2 G1 1 100 1,000 Minimum thickness (m) 10

100,000

Westralian A4 Carnarvon B4 Drummond C4 Burdekin D4

10,000

A B C D E F G H

Induration indicator The induration indicator serves two primary purposes. Firstly, it makes the issue about when a sedimentary basin becomes so metamorphosed that it becomes a 'block', 'province' etc. irrelevant for the purposes of the basin inventory. Secondly, it gives an indication of petroleum prospectivity in the context of relative thermal maturity. Many basins, particularly where active accumulation is occurring offshore today, will have a range of induration indicators at different depths and locations, whilst others will be more homogenous. Description Loose sediment Soft sediment deformation; peat-lignite coal ranks Consolidation and primary water expulsion; sub-bituminous coal rank Mature for oil generation; high volatile bituminous coal rank Late oil generation; medium volatile bituminous coal rank Overmature for oil generation; low volatile bituminous coal rank Late gas generation; semi-anthracite to anthracite coal rank Overmature for gas generation; anthracite coal rank Low grade metamorphism (zeolite facies) High grade metamorphism (prehnite-pumpellyite facies) R0 = average vitrinite

Indicator 1 2 3 4 5 6 7 8 9 10

Likely R0 <0.2 0.2 - 0.4 0.4 - 0.6 0.6-1.1 1.1 - 1.5 1.5-1.9 1.9-3.0 >3.0 No vitrinite No vitrinite

reflectance

Knowledge indicator An important part of the basin inventory will be documentation of not only what we know, but of what we do not. This indicator is designed to indicate the degree of certainty or otherwise of our knowledge, based primarily on data density and quality. Detailed guidelines have been developed as to what constitutes 'regional/some', 'moderate', 'good' and 'detailed' geophysical, outcrop and well data, but space constraints prevent presentation of these guidelines in this abstract. The knowledge indicator for most basins will of course change over time. Likely knowledge level of basin: Data Summary Some indications that basin exists

Extent low

Thickness Sequences Lithology low

INDICATOR

Ages

Geohistory

Plays

Resources

Regional geophysical data only

moderate moderate

low

Regional geophysical; some outcrop data

moderate moderate

low

Regional geophysical; some well data*

moderate moderate

moderate

low

low/mod

low

no no

moderate moderate

Moderate geophysical data only

high

moderate

Moderate geophysical; some outcrop data

high

moderate

low/mod low/mod

low

Moderate geophysical & outcrop data

high

moderate

moderate moderate

low/mod

Moderate geophysical; good outcrop data

high

mod/high

mod/high mod/high

low/mod

Moderate geophysical; some well data*

high

mod/high mod/high

Moderate geophysical & well data*

high

low

high

low

high

moderate

low

mod/high

moderate

low/mod

Good geophysical data only

high

low

low/mod

low

Good geophysical; some well data*

high

mod/high

moderate

low/mod

Good geophysical; moderate well data*

high

mod/high

moderate

Good geophysical & well data*

high

moderate

Detailed (field) geophysical & well data

high

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15

* with or without outcrop data; wells include exploration, appraisal & stratigraphic but exclude development & most water

Genesis indicator This indicator will reflect what is currently believed to be the basin's origin, age and tectonic setting. In the basin inventory this will be a short text field rather than a single number, as theories about basins vary widely within the geoscience community, and indeed there is often disagreement about the genesis of individual basins. Conflicting theories for a basin's genesis will be noted appropriately. Because this indicator will reflect the prevailing theories of the day, particularly in regard to basin origin, like the knowledge indicator it will be updated in future as geological understanding evolves. 22

DEFINING FRONTIERS Frontiers can exist in both a geographic and geological framework. Geographically, 'frontier' has traditionally been used in petroleum exploration to describe remote, poorly known areas rather than political boundaries. Geologically, usage of 'frontier' relates mainly to the level of previous exploration and existing knowledge, and varies from country to country. Compared to the US Gulf Coast area, virtually all of Australia would be classified as 'frontier'. This is not particularly useful for policy formulation, so for the purposes of the Petroleum (Submerged Lands) Act the Australian Government has adopted the petroleum exploration status indicators proposed in Stephenson (1998). These are based on the percentage of hydrocarbons which have probably been discovered, with secondary indicators of the density of exploration activity (for this purpose, exploration wells include appraisal and stratigraphic wells but exclude development wells). There is no space to describe here the methodologies used to determine these probabilities, but they are partly based on those described in BRS (1997). • •

• •

Mature basins: >50% probability that >50% of the basin's hydrocarbons have been discovered. The average seismic grid spacing is likely to be <2 km, with >10 exploration wells drilled/1,000 km2. Submature basins: >50% probability that between 20-50% of the basin's hydrocarbons have been discovered. The average seismic grid spacing is likely to be between 2-5 km, with 1-10 exploration wells drilled/1,000 km2. Immature basins: >50% probability that <20% of the basin's hydrocarbons have been discovered. The average seismic grid spacing is likely to be >5 km, with <1 exploration well drilled/1,000 km2. Frontier basins: No hydrocarbons have been discovered. The level of exploration activity is variable in these basins, but sparse seismic coverage and very few wells are the norm.

Basins can be subdivided into areas of different exploration status if they are well enough known. For example, in the Carnarvon Basin the Barrow and Dampier Sub-basins are mature, the Exmouth Sub-basin is submature, the Beagle Sub-basin and Exmouth Plateau are immature, whilst the Dixon Sub-basin and most of the Palaeozoic sub-basins in the south are frontier. IDENTIFYING FRONTIER PETROLEUM BASINS At first glance, any basin in which potentially commercial hydrocarbons have not been discovered could be regarded as 'frontier'. This is of limited use to petroleum explorationists however, if the basin is too small, shallow, immature or metamorphosed to represent a legitimate target. Consideration of size and induration indicators can narrow the number of potential petroleum frontier basins down considerably. The thicker and more extensive the basin, the greater the likelihood that petroleum systems are or have been present. All Australian class A basins (megabasins) contain commercial hydrocarbon accumulations somewhere within their extent. At the other end of the range, no Australian class D basin or smaller contains known commercial accumulations of hydrocarbons, nor do any basins of class 1 or 2 thickness. Potential petroleum frontier basins will also need to contain significant sediment thicknesses of induration index 4 - 5 for oil, and 4 - 7 for gas. The knowledge indicator can provide a reality check before writing off basins as potential petroleum provinces, and the genesis indicator may assist those with a bias towards exploring in particular tectonic and temporal settings. Based on current, often limited knowledge, many Australian frontier offshore basins (as defined above) may meet the above size and induration criteria. These include the Arafura, Bight, Bremer, Canning, Duntroon, Maryborough, Queensland, Roebuck, Sorell, Sydney and Townsville Basins, plus some of the newly discovered basins on the Lord Howe Rise. Taking into account economic and political considerations, my view is that the Bight and Roebuck Basins may prove to be among the most prospective. Evaluation of Australian onshore basins for the AGSO basin inventory is at a very early stage, but my current assessment is that the Georgina and Officer Basins in particular may have significant untested petroleum potential. REFERENCES BRS, 1997. Oil and Gas Resources of Australia 1996. Bureau of Resource Sciences, Canberra. Stephenson, A.E., 1998. Petroleum prospectivity of Australia's continental margins. Geological Society of Australia Abstracts 49, 429. Acknowledgments: The author thanks Larry Harrington, Alan Williams, John Bain, Jim Jackson, Howard Stagg, Clinton Foster, Russell Korsch and Aiden Moore for useful comments and discussions. Published with the permission of the CEO of AGSO; Crown copyright reserved. 23

HYDROCARBON PROSPECTIVITY OF THE BIGHT BASIN PETROLEUM SYSTEMS ANALYSIS IN A FRONTIER BASIN Jane E. Blevin. Jennifer M. Totterdell, Graham A. Logan, John M. Kennard, Heike I.M. Struckmeyer & James B. Colwell. Petroleum and Marine Division, Australian Geological Survey Organisation (AGSO), GPO Box 378, Canberra, ACT, 2601

An analysis of the potential petroleum systems of the Bight Basin was undertaken by the Australian Geological Survey Organisation (AGSO) as part of a Federal Government initiative to promote petroleum exploration in Australia's frontier basins. The analysis was built on an integrated sequence stratigraphic study of seismic data and 12 exploration wells in the Bight Basin and surrounding areas (Duntroon and Denman basins, Polda Trough; Totterdell, et al., 2000). West of the Otway Basin, the Great Australian Bight region is characterised by deep water basins (1000-2000 m), sparse drilling, and patchy, variable quality datasets. These factors have dampened exploration efforts and sustained a perception of poor prospectivity, mainly due to a lack of knowledge. In the present study, new seismic datasets (Totterdell, et al., 2000), and a combined sequence stratigraphic and petroleum systems approach have been used to identify probable intervals of organic-rich rocks, to understand the regional maturity of these facies, and to identify suitable traps for hydrocarbon accumulation. The analysis also identified intervals of probable reservoir and regional seal deposition. The results presented here focus on the Ceduna and Eyre sub-basins, particularly those areas which were on offer as part of the 1999 Offshore Acreage Release Program. REGIONAL SETTING AND SEQUENCE STRATIGRAPHY The Bight Basin is a frontier offshore basin that covers an area in excess of 150,000 km2 along the central part of Australia's southern margin (Great Australian Bight). The three sub-basins that comprise the Bight Basin (Ceduna, Eyre and Recherche sub-basins) formed during lithospheric extension and subsidence phases that preceded and followed the separation of Australia and Antarctica. The sub-basins contain up to 12 km of Late Jurassic to Holocene sediment, although only a limited section of the overall basin succession has been intersected by two exploration wells (Potoroo-1, Ceduna Sub-basin; Jerboa-1, Eyre Sub-basin). The sequence stratigraphic analysis has identified ten second-order sequences (Fig. 1). The sequences are primarily technically enhanced, transgressive-regressive cycles or supersequences (Totterdell, et al., 2000). A new suite of names based on marine megafauna, some of which commonly inhabit the Bight, was adopted for the sequence framework. This new nomenclature sought to avoid the confusion arising from using existing formation names for newly-defined sequences. The sequence framework is linked to phases of basin evolution, and reflects deposition during ten accommodation cycles that relate to extension (Late Jurassic to earliest Cretaceous) and two subsequent periods of thermal subsidence (Phase 1/Berriasian to late Santonian; Phase 2/late Santonian to Holocene; Fig. 1). The initial period of thermal subsidence (Phase 1) followed the cessation of upper crustal extension, and ended with a period of accelerated subsidence (Cenomanian to late Santonian) that culminated in continental breakup and the onset of sea floor spreading. Thermal subsidence Phase 2 extends from breakup in the late Santonian to the present-day. Details on the lithology, distribution, depositional environment and stratal relationships of the ten supersequences are provided in Totterdell et al. (2000). ORGANIC CHARACTER OF PROXIMAL SEQUENCE FACIES A dataset of geochemical analyses was compiled from twelve exploration wells in the Polda Trough, and Bight and Duntroon basins (Logan, in press). The facies analysed represent a composite section of the three depocentres (with respect to age), with correlation distances between the wells often in excess of 400 km. The location of most wells on the flanks of the main depocentres has meant that the analysed facies represent the more terrestrial end-members of those facies expected in the basin. Data from the three wells (Jerboa-1; Mercury-1 and Columbia-1 in the Polda Trough) that intersected the Late Jurassic to earliest Cretaceous syn-rift section, indicate these supersequences (Sea Lion and Minke) contain Type II to Type III kerogens, with moderate to high potential for liquid generation (Logan, in press). Within the postrift section, the geochemical data indicate that coals and non-marine shales of the Bronze Whaler (Valanginian to mid-Albian), Blue Whale (mid-Albian to early Cenomanian), and White Pointer (Cenomanian) supersequences have the highest potential for liquid hydrocarbon generation. The Hammerhead, Tiger and Southern Right supersequences (Fig. 1) are characterised by predominantly Type III kerogens and are gas prone (Logan, in press). While these data are considered representative of the organic character and generative potential of facies along the margins of the Bight Basin and in the "Inner Basin" of the Duntroon Basin (Smith and Donaldson, 1995), they are not indicative of the quality of organic-rich facies that are predicted to lie in more basinal environments. In addition, factors such as bulk sampling (Potoroo-1), sample density, 24

contamination, and possible reworking (Jerboa-1) may obscure subtle evidence that could be used to predict the character of the deeper, basinal facies. A strategic sampling program to further test this hypothesis and highgrade the geochemical dataset is underway. This program will address the following three issues: 1) specifically target facies of possible marine incursion (eg, flooding surfaces and maximum flooding surfaces suggested by biostratigraphic and sequence stratigraphic evidence); 2) assess the potential contamination of Blue Whale facies by coals from the overlying White Pointer supersequence (Platypus-1); and, 3) infill and verify the existing analyses of selected non-marine shales. MODELLED INTERVALS OF POTENTIAL ORGANIC-RICH ROCKS Due to the limitations of the existing geochemical dataset, a conceptual model of basinal organic-rich rocks was derived from the tectonic setting and palaeogeography of the evolving basin, as well as the sequence stacking, seismic geometry and character of the stratigraphic succession. The influences of subsidence and eustasy on accommodation cycles were also considered. The plate configuration, palaeo-latitude and depositional environments of Australia and Antarctica from the Late Jurassic (140 Ma) to Late Cretaceous (75 Ma) have been summarised by Edwards et al. (1999). These interpretations depict the propagation of the Southern Margin Rift system, along with the presence of seaways and inland drainage systems that influenced deposition in the Bight Basin. During this period, the entire Southern Margin remained south of 60° latitude. The palaeo-latitude of the Bight Basin is an important factor in selecting a possible analogue basin model. The Jurassic to Late Cretaceous sequences were deposited during an overall transgressive/regressive cycle of approximately 100 m.y. duration. The transgressive half-cycle (165 to 84 Ma) is demonstrated by a succession of environments that began with non-marine facies (Callovian to Berriasian lacustrine shales), graded upwards into coastal plain and marginal marine facies (Valanginian to mid-Albian siltstone, shale and coals), and finally into fully marine facies (mid-Albian to late Santonian marine sandstones, siltstones and shales). The change from transgressive to regressive environments occurred in the late Santonian (base Hammerhead sequence boundary) and coincided with the proposed breakup between Australia and Antarctica at around 84 Ma (Sayers, et al., in press). The regressive half-cycle (84 to 65 Ma) is represented by the late Santonian to late Maastrichtian Hammerhead supersequence, which contains two lower progradational sequences and an upper aggradational sequence (Totterdell, et al., 2000). The transgressive half-cycle evident in the sequence stacking was principally controlled by the propagation of the Southern Rift System (Stagg et al., 1990) from west to east. The onset of marine conditions in the post-rift section (105 to 108 Ma; Mallabie-1 and Potoroo-1) coincided with a first- or second-order rise in global sea level (134 to 90 Ma; Fig. 1). These factors suggest a possible connection with the open marine conditions that existed along Australia's western margin. The peak in global sea level from the Late Albian to mid-Turonian partially coincides with a period of accelerated subsidence that preceded breakup in the Bight Basin (Totterdell, et al., 2000). The increase in subsidence rates from 97 to 84 Ma has been attributed to possible lower crustal processes, as there is presently no clear evidence of continued upper crustal extension in the Bight Basin beyond approximately 140 Ma; growth faults that are present throughout much of the Ceduna Sub-basin are related to the movement of ductile shales within the Blue Whale supersequence. The coincidence of these three factors (progressive opening of the rift system, a eustatic rise in sea level, and increased rates of tectonically-driven subsidence) resulted in a period of increased accommodation in the Bight Basin from mid-Albian to late Santonian. These conditions would have been favourable for the deposition of organic-rich rocks within an elongate, narrow seaway (approximately 105 to 84 Ma). In this scenario, the uppermost Bronze Whaler, Blue Whale, White Pointer, and Tiger supersequences are predicted to contain the highest quality marine source rocks in the basin. Within a regional petroleum systems framework, these supersequences can be combined due to the expected similarity in organic character. These supersequences are hereafter referred to as Sub-system 3 of the Austral Petroleum Supersystem, as defined by Bradshaw (1993) and Edwards et al. (1999). As exploration of the Bight Basin progresses, our knowledge of each sequence and the hydrocarbons generated may evolve to a point whereby an oil can be correlated with a specific organic-rich unit. Our present state of knowledge does not allow this differentiation. In addition, further work is required on bitumen standings, global analogues, and wells in Australia's onshore basins to define suitable source rock analogues (ie the Eucla and Eromanga basins) to advance this framework. While the lower units of the transgressive half-cycle (Southern Right and lower Bronze Whaler supersequences, Austral Sub-system 2) are also interpreted to have contained organic-rich intervals (probably of a terrestrial to

marginal marine nature), they presently lie at depths in excess of 5000 to 8000 m across much of the Ceduna Sub-basin. Given the maturity level expected at these depths, it is unlikely that any hydrocarbons generated and reservoired in these sequences would be preserved. In the Eyre Sub-basin, these supersequences are likely to be immature due to the lack of Late Cretaceous sediment and loading in this area of basin. PETROLEUM GENERATION WITHIN POTENTIAL SYSTEMS To understand the maturation of the proposed organic-rich intervals, burial and thermal geohistory modelling of 'synthetic sites' in the Eyre and Ceduna sub-basins was carried out using Winbury™ software. In the Eyre Subbasin, one site was modelled in the deep half graben that flanks the Jerboa structure. In the Ceduna Sub-basin, a total of four sites, located in increasingly basinal locations in the central Ceduna depocentre, were modelled to simulate the increasing depth of burial of progressively younger units along the axis of the depocentre. The geohistory modelling focused on the four organic-rich intervals highgraded in the assessment: 1) Late Jurassic to Berriasian Sea Lion-Minke supersequences; 2) mid-to-late Albian Blue Whale supersequence; 3) Turonian to late Santonian Tiger supersequence; and 4) lowermost progradational facies of the late Santonian to early Campanian Hammerhead supersequence. The use of appropriate kinetic parameters, based on analogue source rock facies from AGSO's source rock kinetic library, enabled an assessment of the timing of generation and expulsion of oil and gas for each organic-rich interval. In the Eyre Sub-basin, modelling suggests that oil was expelled from Late Jurassic source rocks during the Late Maastrichtian to early Eocene. This timing coincides with a period of fault reactivation and erosion in the subbasin. Although this scenario is unfavourable for the entrapment of hydrocarbons in reactivated structures, such as that tested by Jerboa-1, many other structural and stratigraphic traps exist within, and on the shoaling flanks of, the half graben. It is unlikely that potential source rocks in sequences younger than the Minke-lower Southern Right interval have been buried deeply enough to generate and expel hydrocarbons in this sub-basin. In the Ceduna Sub-basin, modelling suggests that oil expulsion from Late Jurassic source rocks occurred significantly earlier during the earliest Cretaceous (Berriasian). The seismic mapping has shown that many of the extensional structures that hosted these source rocks have undergone multiple periods of structural reactivation, so it is unlikely that hydrocarbon accumulations within the half graben have remained intact. In addition, these structures are presently buried to non-economic depths (8000 m and greater), particularly in areas basinward and east of the Potoroo-1 well. The three Albian to Campanian source intervals modelled in the Ceduna Sub-basin have all reached maturities adequate to generate and expel liquid and gaseous hydrocarbons. Sediment loading of the Late Cretaceous succession, and in particular the Hammerhead supersequence, is the critical event in the maturation of successively younger systems. Oil and gas expulsion from the modelled units occurred mainly during the midCenomanian to Maastrichtian. Figure 1 summarises the burial history and critical events identified by the modelling. The proposed regional structural gradients in the basin during the Late Cretaceous include shallowing towards the northwest (Eyre Sub-basin), the northern basin margin, and a large anticlinal structure in the outer basin. Extensive faulting around the time of breakup (late Santonian) may have facilitated the vertical movement of fluids along faults, most of which terminate at the Hammerhead sequence boundary. A similar period of minor reactivation has been dated as mid-Paleocene, and may relate to changes in the rates of sea floor spreading (Totterdell, et al., 2000; Sayers, et al., in press). Steep, planar normal faults associated with this event terminate at the Wobbegong sequence boundary, and may have facilitated a tertiary migration of hydrocarbons from preexisting traps. HYDROCARBON PLAYS IN THE EYRE AND CEDUNA SUB-BASINS A palaeo-oil column in sands of the Late Jurassic Sea Lion supersequence in the Jerboa-1 well (Edwards, et al., 1999), confirms the presence of an effective Late Jurassic petroleum system in the Eyre Sub-basin. The accumulation was breached during a period of Late Cretaceous - Early Tertiary faulting that reactivated many of intra-basin fault blocks. The well confirmed the presence of multiple reservoir/seal pairs in the upper Sea Lion, and at the sequence boundaries of the Southern Right and Bronze Whaler (Fig. 1). Mudstones within the lower Cretaceous Southern Right and Bronze Whaler supersequences are regional seals for the basin. Untested plays in this basin include (Fig. 2): 1) fault-sealed traps on the upthrown-side of reactivated structures (Quinn, 1999); 2) structural/stratigraphic plays at the base Tertiary unconformity; 3) onlap at multiple stratigraphic levels on the shoaling side of tilt blocks; and, 4) stratigraphic traps within progradational sand facies in the Wobbegong supersequence. Structural/stratigraphic plays may also be present on the relay ramps that link the two en-echelon half graben of the Eyre Sub-basin. Geohistory modelling shows that the Late Jurassic Sea Lion and lower Southern Right are likely to be the only mature source rocks in the basin. 26

The Ceduna Sub-basin offers a wide range of plays in both shallow and deep water settings. Figures 3 and 4 are play schematics based on interpreted seismic data across the western and central Ceduna Sub-basin, respectively. The western play schematic (Fig. 3) shows that the upper White Pointer and younger supersequences (lying at <5.0 s TWT) are likely to be the strata targeted for exploration. Play families in the western Ceduna Sub-basin include (Fig. 3): 1) basement onlap and drape stratigraphic plays; 2) fault-blocks juxtaposed against basement, with top seal provided by the Blue Whale supersequence; 3) pre-breakup fault blocks sealed by transgressive facies of the Tiger supersequence; 4) fault traps at the top Blue Whale supersequence, beneath rotated White Pointer growth strata; 5) stratigraphic traps within the basal Hammerhead supersequence, including faults terminating beneath incised valley systems; 6) fault blocks at the top of Hammerhead supersequence, with tertiary migration from deeper accumulations; and 7) fault-closed anticlinal structures at the top Tiger supersequence, sealed by downlapping facies of the Hammerhead supersequence. The schematic across the central Ceduna Sub-basin (Fig. 4) shows that the upper Tiger and younger supersequences are within presently viable exploration depths (<5.5 s TWT). A massive thickening of the Hammerhead supersequence from west to east provided the sediment loading that was largely responsible for the maturation of organic-rich rocks within progressively younger sequences. Play families in the central Ceduna Sub-basin include (Fig. 4): 1) fault blocks and anticlinal closures at an intra-Tiger sequence boundary; 2) fault blocks at the top White Pointer supersequence, although these plays may only be preserved near the northern basin margin; 3) pre-breakup fault blocks and anticlinal structures at the top Tiger horizon, sealed by downlapping facies of the Hammerhead supersequence; 4) stratigraphic plays such as lowstand fans within the Tiger supersequence; 5) fault blocks at the top Tiger supersequence; 6) large anticlinal structures that formed near the top White Pointer supersequence (note that depth converted sections show that this feature lies at a depth of approximately 6.0 km); 7) fault blocks within the Hammerhead supersequence, with fault seal provided by juxtaposition against younger downlapping facies; 8) fault blocks at the top of the Hammerhead supersequence, with tertiary migration from deeper accumulations; and 9) multiple stratigraphic plays within progradational and aggradational facies of the Hammerhead supersequence. The best reservoir units are expected to lie in the Wobbegong (lowstand facies) and Hammerhead supersequences, and at the basal Tiger and intraTiger sequence boundaries. Highstand facies within the Tiger supersequence are the uppermost regional marine shale (seal facies), while sealing units within the Hammerhead are expected to be largely intra-formational. A combined sequence stratigraphic and petroleum systems approach has allowed the identification of four potential organic-rich intervals in the Bight Basin. Together with the spatial distribution and modelled maturity of these intervals, a framework of play families and exploration concepts has been derived for this frontier region. REFERENCES Bradshaw, M.T., 1993. Australian petroleum systems. PESA Journal, 21, 43-53. Edwards, D.S., Struckmeyer, H.I.M., Bradshaw, M.T. & Skinner, J.E., 1999. Geochemical characteristics of Australia's southern margin petroleum systems. APPEA Journal, 39 (1), 297-321. Logan, G.A., in press. Hydrocarbon potential of the Great Australian Bight. Petroleum Geology of South Australia. Volume 5: Great Australian Bight. Primary Industries and Resources, South Australia. Quinn, D.M.T., 1999. An evaluation of seals, reservoirs, and fault sealing potential in the Eyre Sub-basin, Great Australian Bight. BSc Honours Thesis, University of Adelaide, National Centre for Petroleum Geology and Geophysics (unpublished). Sayers, J., Bernardel, G., & LOS Project Team, in prep. Geological framework of the Great Australian Bight and adjacent ocean basins. Australian Geological Survey Organisation, Record. Smith, M.A. & Donaldson, I.F., 1995. The hydrocarbon potential of the Duntroon Basin. APEA Journal, 35 (1), 203-219. Totterdell, J.M.., Blevin, J.E., Struckmeyer, H.I.M., Bradshaw, B.E., Colwell, J.B., & Kennard, J.M., 2000. A new sequence framework for the Great Australian Bight; starting with a clean slate. APPEA Journal, 40. Stagg, H.M.J., Willcox, J.B., Needham, D.J.L., O'Brien, G.W., Cockshell, C.D., Hill, A.J., Thomas, B. & Hough, L.P., 1990. Basins of the Great Australian Bight region: geology and petroleum potential. Continental Margins Program Folio 5. Bureau of Mineral Resources, Geology and Geophysics and Department of Mines and Energy, South Australia. Acknowledgment This paper is published with the permission of the Chief Executive Officer, AGSO. 27

EPOCH

STAGE

SEA LEVEL CURVE

SEQUENCES

Dugong

Base Hammerhead

Blue Whale

Loading of White Pointer and Tiger

Blue Whale

Bronze Whaler

Loading of Hammerhead

White Pointer

Loading of Hammerhead 3

Tiger

Southern Right Minke

Sea Lion

Figure 1: Sequence stratigraphic and petroleum systems chart for the Eyre and Bight basins. Key influences on the maturation of potential source rocks in the Blue Whale, Tiger and lower Hammerhead sequences are shown in the boxes. The arrows indicate the timing of hydrocarbon explusion from these intervals (onset = base of arrow; end = top of arrow; Mid-Santonian to Maastrichtian). 28

WNW

0-|

Jerboa-1

ESE

10 km

Figure 2. Seismic line across the Eyre Sub-basin showing the Jerboa-1 well and mapped sequences. The numbers refer to untested play families in the basin.

Figure 3: Diagrammatic cross-section across the western Ceduna Sub-basin. The numbers refer to untested play familes identified in the basin.

Figure 4: Diagrammatic cross-section across the central Ceduna Sub-basin. The numbers refer to untested play families identified in the basin.

smkMM: j J ^ r- sequences. 1 29

EVERYTHING OLD IS NEW AGAIN: MAGNETICS IN THE GIPPSLAND BASIN, SE AUSTRALIA David H. Moore, David Wong, Tom Bernecker and Mike Woollands Minerals and Petroleum Victoria PO Box 500, East Melbourne VIC 3002, Australia

INTRODUCTION

The Gippsland Basin is Australia's premier hydrocarbon province (1999 reserves: 4 billion barrels crude oil and condensate, 10TCF gas). Although oil production is declining, gas production in the basin will become increasingly important. Apart from Blackback, all producing oil and gas fields are in the extensively explored, shallow water area in the west. Very little is known about the eastern, deep-water area of the basin. While most agree that further potential exists in Gippsland, the common wisdom has been that no additional large discoveries will be made offshore. This speculation was mainly supported by the drilling of four dry wells near the edge of the continental shelf. Well failure in these instances, however, is partly related to the targeting of inappropriate stratigraphic intervals, but, more significantly, to the difficulties in seismic data processing, associated with velocity anomalies created by channelling in the thick carbonate cover sequence. Seismic coverage in the eastern part of the basin is limited to the recently acquired good quality GDW99 survey (981 km) and the 1987 BMR deep seismic lines which may benefit from more processing. In the early 1960s, potential-field surveys were important in the discovery of petroleum in the Gippsland Basin. Since then, the tools were little used until 1999, when the State government of Victoria initiated, under the VIMP umbrella (Victorian Initiative for Minerals and Petroleum), a 400/800 m, federally supported, aeromagnetic survey and a 1.5 km spaced onshore gravity program. Together, these have provided new insights into deep-seated geological features. They are the highest resolution regional surveys available and help link basement and basin structures. Airborne magnetic surveys are well known as effective ways of mapping the "basement" (for example Willocks and Simons, 1998). Particularly in areas where seismic coverage is limited, potential field surveys are also an extremely cost-effective way of complementing seismic information, since almost all faults in the basin must result from some movement in the basement. Moreover, magnetic images help to extend the known structuralsedimentary framework beyond the seismic lines into virgin areas. Modern interpretation techniques, which place equal emphasis on geological and geophysical validity, are especially suited to this task.

BASEMENT

Non-magnetic Early Palaeozoic metaturbidites and north to northeast-oriented magnetic granites (Figure 1) underlie the western and central parts of the Gippsland Basin rift. New onshore mapping has shown that the Gippsland Basin formed at the apex of south-directed, arcuate thrust slices in this basement. The basin margins are typically 0.5 to 2 km thick, while the Central Deep has magnetic basement at about 15 km, deeper than the current seismic data. East of the presently known petroleum accumulations, the basement changes magnetic character, with much more equant responses. Similar responses are present along the edges of the Sydney and Bowen basins, and equivalent sedimentary rocks are also known from the Lord Howe Rise and southeast Tasmania. It seems reasonable that similar Late Palaeozoic and Mesozoic rocks underlie the eastern Gippsland Basin. Much of the Palaeozoic basement structural fabric controlled the internal partitioning of the basin. Some of the structures control the present seafloor topography, showing a long movement history. Figure 1 clearly shows that northeast trends influenced not only the present basin fill configuration, but also the shapes of some of the petroleum traps. It is also possible that the accumulations that cluster around a prominent east-west magnetic low are controlled by structures that originated above Palaeozoic thrust sheet edges. If so, both propositions are important predictors of other trap sites.

RIFT

From the Late Jurassic to mid-Cretaceous, the Gippsland Basin was part of a major continental rift system. NNE-trending grabens and half-grabens, including the precursors to the offshore Central Deep and onshore Strzelecki Ranges, were filled with up to 10km of dominantly fluvial sediments of the Strzelecki Group. The

structural grain is strongly oblique to the current east-west Gippsland Basin axis and was partly controlled by the Palaeozoic basement grain. The new aeromagnetic data confirms the persistence and location of these trends across the basin. In areas of shallow basement, magnetic dykes show extension directions. In deeper areas, breaks in magnetic responses show fault locations. Both provide important information for better constrained basin and structural modelling. Further rifting, associated with the opening of the Southern Ocean to the west, initiated the deposition of the Emperor Subgroup in half-grabens on trends largely coincident with those of the Strzelecki Group. The basin margins were uplifted and eroded, episodically delivering coarse-grained sediments onto narrow floodplains and into deep rift-valley lakes. Up to 500 m of lacustrine shales accumulated in these.

Figure 1: First vertical derivative of the magnetics of the Gippsland Basin. Black shows low, white shows high gradients; deeper features look more blurred while shallower features are sharper. Petroleum accumulations are outlined in black; bathymetry, coastline and Victoria's State border in white. Note how most of the significant hydrocarbons accumulations tend to cluster around a magnetic low; one field (Flounder) is closer to its centre. Offshore data from AGSO, onshore data from MPV and AGSO. The late synrift Golden Beach Subgroup marks the first appearance of marine sedimentation in the basin; it correlates with the opening of the Tasman Sea. Northwest trending faults, normal to the Tasman extension direction, largely controlled deposition, particularly in the south and east. These contrast with previous rift phase structural trends. In the east of the magnetic image, similarly trending dyke swarms may be associated with the start of this phase. These faults are the first major set to significantly cut across the basement fabric and develop sub-parallel with the final sag axis of the basin. Near the eastern edge of Figure 1, the Tullaberga Trough can be seen as a north-south dulling of the magnetic responses. It probably includes Golden Beach Subgroup-age sediments.

, Until recently, the hydrocarbon potential of the Golden Beach Subgroup was poorly understood. Only the minor discoveries at Archer-1 and Anemone-1A have demonstrated that the subgroup is a valid target. Our new prospectivity assessment of this stratigraphic interval, integrating aeromagnetic, seismic and sedimentological evaluations, suggest a petroleum system has probably operated in the Golden Beach Subgroup. Before the current interpretation, there was little confidence in the presence or impact of the northwest-trending fault sets, as well as the location of basement highs that would have influenced depositional patterns and facies distribution. The new data is being applied to develop more robust geological models of the subgroup and will highlight new play fairways. POST-RIFT A pronounced phase of tectonism and associated volcanism during the early Campanian contributed to the major throws now seen on intra-Golden Beach Subgroup faults and caused prominent basin subsidence. The Latrobe Siliciclastics unconformably overlie the Golden Beach Subgroup. Thermal subsidence provided the accommodation space for non-marine, estuarine to back-barrier/lagoonal sediments in the west, and coastal plain/delta front to fully marine sediments in the east. Numerous marine incursions inundated the basin from the southeast. Decreasing subsidence rates prevailed during this period, coupled with continued movement on many earlier faults. Deep basement features and the major basin-bounding faults continued to subtly influence depositional patterns. Compressional tectonism overprinted the basin from the Early Eocene to Early Miocene. During this period, the major anticlines that trap many of the giant hydrocarbon accumulations were generated. Simultaneously, the northeastern part of the basin was uplifted and the deep, northeasterly trending Strzelecki grabens and halfgrabens were inverted. Normal faulting produced fault trends, which strike WNW-ESE except where they are influenced by deeper structural elements. Sea-level fluctuations, in association with the uplift and inversion, led to major submarine channelling of the Latrobe Group. Finally, marine carbonates of the Seaspray Group were deposited in a mature drift phase setting in a temperate climate. CONCLUSION The eastern region of the Gippsland Basin represents an exciting, unexplored frontier. Only a few wells, backedup by limited seismic coverage, provide some geological insights. Nevertheless, the application of aeromagnetics over much of the basin can be used to delineate many of the structural features that control hydrocarbon distribution. Its integration with seismic and sedimentological interpretations produces results that should stimulate exploration of the considerable oil and gas potential in the deep-water area. REFERENCE Willocks A.J., & Simons, B.A., 1998. Geologists and geophysicists: getting them on the same planet. Exploration Geophysics Vol. 29. pp. 658-664.

STRATIGRAPHIC FORWARD MODELLING IN FRONTIER BASINS Cedric M. Griffiths CSIRO Petroleum, Box 3000, Glen Waverley, VIC, Australia 3150

Of the approximately 600 sedimentary basins known around the world less than a third have yielded hydrocarbons to date, less than 50 are significant producers, and up to 75 percent of total known oil is found in around ten of the fifty. Although exploration has occurred in another two hundred or so basins, discoveries of commercial significance have not yet been made. This leaves at least two hundred basins of various sizes that could be called 'underexplored' or 'frontier'. These basins have not attracted significant exploration attention for a variety of reasons. Access may be physically or politically difficult, no-one has identified large structures, the existence of potential source may be in doubt, maturity may be a problem etc.. In other words, after over a century of energetic world-wide hydrocarbon exploration and production, if a basin is still considered underexplored it is probably for a good reason. Any progress in discovery in a frontier basin will depend on the development and application of an economic technology. Wells will be expensive and difficult to justify, seismic access may be expensive, non-invasive remote sensing information may be available only from aircraft or satellites. Ground access may be dependent on the slow and expensive development of infra-structure, and there may be little or no surface exposure. The exploration of such basins presents a challenge that conventional geological techniques struggle to address. Let us look at the process involved in stratigraphic forward modelling and see how this technology can help in such cases. Stratigraphic forward modelling (SFM) is a technology that has come of age over the past decade. It has been successfully applied to several basins on the NW Shelf of Australia. The numerical technique has been developed around our understanding of the basic processes involved in basin fill. If a basin is to exist a crustal depression is formed for some reason (compression, extension, thermal processes etc.), the depression creates an opportunity for water-, or wind-, borne sediment to accumulate together with the in situ formation of carbonates and organic matter. The stratal architecture within the basin is dependent on the fine balance between the rate of creation or destruction of accommodation and the rate of sediment supply. Modern SFM tools allow these processes to be modelled in three spatial dimensions, at basin to reservoir scale, over geological time periods. The half-dozen or so 3D models available all use different assumptions and numerical schemes, but the method of operation is the same. All available knowledge of the basin is examined. For a frontier basin this may not be very much, but the geographical limits, location of major sediment supply external to the basin, the stratigraphic timing of the major events, any information about the basin fill, any biostratigraphic data, any seismic lines that may exist, can all be incorporated in the model. The modelling team works closely with geophysicists, sedimentologists, biostratigraphers, and petrophysicists to build a composite model of how the basin filled over the time interval of interest. There will be a huge number of unknowns, but these are unknown to everyone, which is why it is a frontier basin. The difference is that by using SFM the consequences of a variety of possible scenarios can be quantitatively tested. Tectonic influence on sediment distribution can be modelled using many different rates. The effects of sediment supply character and volume can be investigated as well as timing in relation to tectonic movement. Usually a major reason for the basin still being relatively underexplored is the lack of major structural closures visible on early seismic. Thus exploration in frontier basins is often also associated with the 'deliberate search for the subtle trap', and it is the, often seismically transparent, stratigraphic relationship between reservoir and seal lithologies that have potential in such basins. SFM has been used to predict the possibility of such stratigraphic traps on the NW Shelf. How do we know if SFM gives believable results ? First and foremost we use the relationship proposed by the Exxon team in the 1970's, that seismic reflections are time boundaries. This has been supported by most studies that have critically examined the hypothesis. The fundamental Exxon hypothesis was that a seismic reflection generally separates younger strata above from older strata below. SFM starts at a depth-converted lower reflector, treated as a depositional surface, and MUST duplicate not only the three-dimensional internal geometry of reflectors to the upper-most reflector of the simulation, but also the thickness relationships of the entire package. In complex areas, deriving the initial depositional surface can be difficult, but again this is no different to the requirements of any thorough exploration effort, or seismic interpretation, apart from the fact that SFM demands defendable numbers. The grain-size and biostratigraphic information from wells in the modelled area of the basin must also be reconciled with the simulation results. A useful approach is to deliberately withhold information from one or more wells while building the model input files. If the SFM manages to duplicate the hidden data then the predictions away from well data may be more credible. At the end of the day the only proof of a prediction is to drill, but in a frontier basin probably more than any other, a relatively inexpensive approach such as Stratigraphic Forward Modelling is a useful and proven frontier idea to apply to test an exploration 33

concept pre-drill, make quantitative predictions concerning the probable location and quality of reservoir and seal, identify sites that would repay further geophysical investigation, and rank potential drill sites. The process starts with at least a 2D seismic grid over the area of interest. After (ideally) depth conversion, and digitising each reflector on each line within the area of interest, a three-dimensional relative chronostratigraphy is then produced using software such as 3D-Chronostrat™ (Nordlund and Griffiths (1993), Griffiths and HadlerJacobsen (1993), and Emery and Myers (1996)), which will automatically produce the compacted sediment volumes and relative hiatuses for and between each 3D chronosome without the need for well control. The output from 3D-Chronostrat™ is used as input for a three-dimensional Stratigraphic Forward Model such as Sedsim. This way we are making full use of the three-dimensional shape of the reflection geometries that define the relative timing of each of the packages. Without well control we can only make a rough estimate of the absolute timing of the chronosomes and the duration of the hiatuses (Griffiths and Hadler-Jacobsen, 1993) but this will often provide enough information in three-dimensions to enable the uncertainties in the depositional environment to be quantitatively investigated. With the addition of a single well with biostratigraphy, cuttings or core and wireline logs it becomes possible to constrain the 3D-Chronostrat™ data and provide more precise estimates of water depth, sedimentation rates, energy of deposition etc.. In a frontier basin there will often not be a lot of information apart from seismic data of dubious age and quality. Making the most of these data is therefore essential, and quantitative three-dimensional chronostratigraphy, followed by Stratigraphic Forward Modelling allows several conceptual models to be quantitatively tested and discussed before drilling. With several wells then we can constrain the model to a much greater extent and reduce the uncertainty in prediction. An example of the use of Stratigraphic Forward Modelling in the inner Browse Basin is given in Griffiths and Paraschivoiu (1998). In this case the model predicted the development of a linear shelf sand system that had not been intersected by any of the existing wells at the time of the simulation, and may well prove to be a commercial target. Fitzroy

Figure 1 - In this case a regional 2D seismic data set has been used without well control to provide a three-dimensional chronosome map of the Roebuck Basin, NW Shelf (Smith, 1999).

Frontier Case A - Regional seismic and no wells Input: location in basin - seismic geometry - onlap history - channel locations - subsidence history depositional surface - 3D chronosome pattern (Figure l)-sediment supply rates - palaeoclimate Output: Range of 3D depositional models at appropriate resolution (5 km) indicating sand body location for the interval of interest. The range captures the input uncertainties in sediment supply rates, subsidence rates, input sediment locations and water depths. Synthetic seismic sections (Figure 2) are generated from the model to compare with observed seismic. Common Risk Segment, isopach, and net:gross maps are prepared for the depositional phase of trap development. (a)

Figure 2 - Here the simulation results (a) have been converted to synthetic seismic traces (b) and rescaled (c) to compare with observed depth-converted seismic sections. Frontier Case B - Regional 2D seismic at 2km spacing - one well Input: location in basin - seismic geometry - onlap history - channel locations - subsidence history depositional surface - 3D chronosome pattern (Figure 1) -sediment supply rates - palaeoclimate grain sizes - water depth - energy of environment of deposition - biozones Output: Range of 3D depositional models at appropriate resolution (5 km) indicating sand body location and quality for the interval of interest. The range captures the input uncertainties in sediment supply rates, subsidence rates, input sediment locations and water depths. The well information is used to constrain the uncertainty and the model must match the well grain size distributions, water depths, and preserved biozones at the well location. Synthetic seismic sections (Figure 2) are generated from the model to compare with observed seismic. Pseudo-gamma logs (Figure 3) are generated at the well location to compare with the observed gamma. Common Risk Segment, isopach, and net:gross maps are prepared for the depositional phase of trap development.

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Figure 3 - Pseudo-gamma logs generated from forward stratigraphic modelling can be compared with calibration wells. Frontier Case C - 3D seismic and one well Input: location in basin - seismic geometry - onlap history - channel locations - subsidence history depositional surface - 3D chronosome pattern (Figure 1) -sediment supply rates - palaeoclimate grain sizes - water depth - energy of environment of deposition - biozones - high resolution depositional surface - location of channels and channel dimensions Output: Range of 3D depositional models at appropriate resolution (hundreds of metres) indicating sand body location and quality for the interval of interest. The range captures the input uncertainties in sediment supply rates, subsidence rates, input sediment locations and water depths. The well information is used to constrain the uncertainty and the model must match the well grain size distributions, water depths, and preserved biozones at the well location. Synthetic seismic sections (Figure 2) are generated from the model to compare with observed seismic. Pseudo-gamma logs (Figure 3) are generated at the well location to compare with the observed gamma. Common Risk Segment, isopach, and net:gross maps are prepared for the depositional phase of trap development. CONCLUSIONS All exploration depends on a model. Often the model used exists only in the mind of the geoscientist, who finds it difficult or inappropriate to place numbers on the concepts involved, especially in a frontier basin. Nevertheless, with experience, many of the uncertain values can be represented by ranges, limits, or semiquantitative 'scenarios'. Stratigraphic Forward Modelling takes these half-formed or incompletely expressed ideas and uses them as numerical input for a quantitative model that will objectively test the exploration concept. In many cases this will result in a revision of the model and a new perspective on the exploration and development issues. Because the model can be run forward through time, incorporating subsidence, tectonics, sediment supply, water level etc., all the specialists involved, geologists, geophysicists and engineers can use the model output as a common reference platform for discussion and dissension throughout the life of the project. Stratigraphic Forward Modelling is proving to be a frontier technology ideally suited to frontier basins. REFERENCES Emery, D., Myers, K., (eds), 1996.Sequence Stratigraphy, Blackwell, London Griffiths, C.M., & Hadler-Jacobsen, F., 1993. Practical Dynamic Modelling of Sequence Stratigraphy. In: Steel, R. et al (eds) Sequence Stratigraphy: Advances and Applications for Exploration and Production in North West Europe, Norwegian Petroleum Society. Griffiths, C.M., & Paraschivoiu, E.,1998.Three-dimensional forward stratigraphic modelling of Early Cretaceous sedimentation on the Leveque and Yampi Shelves, Browse Basin. The APPEA Journal, 38, 1, 147-158. Nordlund, U., & Griffiths, C.M., 1993. Automatic construction of two- and three-dimensional chronostratigraphic sections from digitized seismic data. Computers and Geosciences, 19, 8,1185-1206 Smith, S.A., 1999.The Phanerozoic basin-fill history of the Roebuck Basin. Unpublished PhD Thesis, University of Adelaide

CONTINENTAL SEQUENCE STRATIGRAPHIC CONCEPTS - A REVIEW Paul V. Grech & Nicholas Lemon National Centre for Petroleum Geology and Geophysics, Thebarton Campus, University of Adelaide, SA 5005 In marine influenced depositional environments, the lateral facies changes in response to variations in relative sea level are reasonably well understood. The sedimentary history of basins in a sequence stratigraphic context has been well documented in numerous publications. The driving force behind the different facies and thenrelationship, both laterally and vertically, is the fluctuation in the base level, which in a marine situation, is the relative sea level. When discussing terrestrial environments however, the effects of relative sea level changes decrease upstream, whereas base level changes are more prominently driven by tectonic effects and sediment supply. The facies variations become less pronounced and have been described as 'internally complex rock piles, where consistent correlation is difficult because of abrupt and often random facies changes' (Legarreta et al, 1993). Recently however, fluvial channel stacking patterns have been recognised to follow a pattern dictated by the resultant base level variations, and hence providing a new tool with which to predict lateral and vertical facies variations in a continental setting. The basis for this sequence stratigraphic interpretation of continental environments are the fluvial channel stacking patterns. Within the lowstand systems tract (LST) and the late highstand systems tract (HST), channel sands are amalgamated laterally and vertically, while similar sands in the transgressive systems tract (TST) and in the early HST are isolated. Sequence formation is controlled by third-order base level cycles, while fourth and fifth-order fluctuations control deposition within the systems tracts. Accommodation during LST deposition is minimal, before base level eventually starts rising at a slow rate. The TS is the surface at which point the rate of rise of base level starts to increase rapidly. This acceleration continues until a point is reached where the rate of rise starts to decrease, the surface of maximum rate of base level rise or the surface of maximum transgression (SMT). During HST deposition, the rate of accommodation creation decreases until it is again stationary and eventually becomes negative. When this point is reached, erosion starts to take place, forming the sequence boundary (SB) of the following sequence. The proposed model is mainly based on a review of work carried out by Legarreta et al (1993), Shanley and Mc Cabe (1994), Aitken and Flint (1995), Olsen et al (1995), and Allen et al (1996). REFERENCES AITKEN, J.F. AND FLINT, S.S., 1995. The application of high resolution sequence stratigraphy to fluvial systems: a case study from the Upper Carboniferous Breathitt Group, eastern Kentucky, USA. Sedimentology, Vol. 42, pp3 - 30. ALLEN, G.P., LANG, S., MUSAKTI, O., AND CHIRINOS, A., 1996. Application of sequence stratigraphy to continental successions: Implications for Mesozoic cratonic interior basins of eastern Australia. In: Mesozoic geology of the eastern Australia plate Conference. Geological Society of Australia Inc., Extended abstracts, September 23 - 26, 1996, pp 22 - 26. LEGARRETA, L., ULIANA, M.A., LAROTONDA, C.A., AND MECONI, G.R., 1993. Approaches to nonmarine sequence stratigraphy - Theoretical models and examples from Argentine basins. In: Eschard, R. and Doligez, B. (Eds.): Subsurface reservoir characterization from outcrop observations. Proceedings of the 7th IFP Exploration and Production Research Conference, Scarborough, April 12 to 17, 1992, ppl25 - 143. OLSEN, T., STEEL, R., HOGSETH, K., SKAR, T., AND ROE, S., 1995. Sequential architecture in a fluvial succession: Sequence stratigraphy in the Upper Cretaceous Mesaverde Group, Price Canyon, Utah. Journal of Sedimentary Research, Vol. B62, No. 2, pp 265 - 280. SHANLEY, K.W. AND McCABE, P.J., 1993. Alluvial architecture in a sequence stratigraphic framework: a case history from the Upper Cretaceous of Southern Utah, USA. In: Flint, S., and Bryant, I.D. (Eds.), Quantitative description and modelling of clastic hydrocarbon reservoirs and outcrop analogues. International Association of Sedimentologists Special Publication, No. 15, pp 21 - 56.

RECOGNISING THE BASE OF THE COOPER BASIN -ATTRIBUTES AND HYDROCARBON POTENTIAL D.I. Gravestock & E. Alexander Petroleum Group, Primary Industries and Resources South Australia GPO Box 1671 Adelaide SA 5001

This abstract is based on the last presentation by Dr Dave Gravestock at a luncheon seminar at the University of Adelaide on 20 October 1999, before his untimely death on 15 December 1999. Dave had commenced an abstract entitled "The Reservoir Potential of Early Cambrian shelf limestones, Arrowie Basin, SA", however it was not complete at the time of his death. His colleagues in Petroleum Group have completed the abstract to bring the paper to a wider audience. Dr Alistair Chaney (Amerada Hess, UK) and Dr Rodney Boucher (Linex Pty Ltd) kindly reviewed the abstract. The late Carboniferous-Triassic non-marine Cooper Basin is Australia's most productive onshore oil and gas province, with hydrocarbon production from Permo-Triassic fluvial and deltaic reservoirs sourced by organicrich mudrocks and coal measures. Cooper Basin sediments were deposited unconformably on Early Palaeozoic carbonates, clastics and volcanics of the Warburton Basin and mid-Carboniferous Big Lake Suite granitoids. Rapid initial tectonic subsidence has preserved up to 600 m of Late Carboniferous to Early Permian glacigenic deposits of the Merrimelia Formation at the base of the succession, of which 360 m have been intersected while drilling. These glacigene deposits intertongue with and overlie the glacial outwash plain deposits of the Tirrawarra Sandstone. The Merrimelia Formation and Tirrawarra Sandstone form an evolutionary continuum produced by deglaciation - flow tills, outwash sands and conglomerates pass into aeolian, braided channel and braid delta sands (Williams & Wild 1984). These in turn pass upward into fluvial, peat swamp and floodbasin deposits of the Patchawarra Formation. Since the first discovery of natural gas in the Late Permian in 1963 it has taken almost three decades for the basal glacial deposits to rise in status from economic basement to exploration targets in their own right following the discovery of gas in these rocks in 1989. Detailed study of the complex glacial deposits has thus been carried out only relatively recently. The first phase of this study involved identification of the base of the Cooper Basin. Despite differences in age and degree of tectonism, differentiation between lower Cooper Basin and Warburton Basin formations is difficult. An altered zone developed at the top of the Warburton Basin in a range of lithologies (although rarely in carbonates) is marked by a distinctive resistivity log anomaly, and was first recognised by Boucher (1996). Where the altered zone has developed in Ordovician shales and Carboniferous granitoids, it has often been mistakenly picked as Merrimelia Formation. New evidence indicates that this altered zone is also developed within the Merrimelia Formation. For the altered zone to be preserved, it must have formed after the regional uplift and continental drift to high latitudes that triggered the Gondwanan glacial episode. The altered zone is interpreted as a sapropel which formed during the depositional phase which followed the earliest deglaciation cycle, when a mantle of fresh water saturated sediments accumulated on the glacially sculpted Warburton Basin strata on the floor of the basin. The altered zone is a Cooper Basin phenomenon which has transcended the boundary between basement and cover and obscured the differences between two dissimilar deposystems. Following identification of the altered zone, re-evaluation of the Warburton Basin as well as the Merrimelia Formation was achieved in around 600 wells using palynology, cores and cuttings, wireline logs and over 1000 thin sections. Five facies associations within the Merrimelia Formation were interpreted by tying wireline log motifs (particularly the gamma) and dipmeter directional data to cuttings and core-based information The facies associations are: stacked cycles, high gamma glaciolacustrine deposits, aeolian deposits, thick diamictite deposits and hybrids - diamictite followed by lacustrine or stacked cyclic deposits. These facies associations occur as cycles and two to four complete preserved cycles can be seen on wireline logs in a dozen SA wells. Cooper Basin subsidence during deposition of the Merrimelia Formation was greater than at any subsequent epoch, except perhaps the Cretaceous, enabling preservation of these cyclic deposits. Due to its economic importance as an oil reservoir the Tirrawarra Sandstone in the Tirrawarra and nearby oil fields has been cored and studied in detail. In contrast the Merrimelia Formation has produced commercial hydrocarbons in the last decade, it is represented by cores from less than 70 wells drilled throughout the basin. Hydrocarbons come from two unusual reservoir types. One is proglacial aeolianite which was recognised and

mapped in the Merrimelia oil and gas field by Williams et al (1985) and has produced gas in Pondrinie field since 1989. The other is a thin sandstone encased in conglomerate close to the southwestern depositional margin of the Cooper Basin which in 1990 flowed oil at a rate of 640 barrels per day from deviated well Malgoona 1 A. The 7 m thick sandstone was interpreted originally as an outwash fan, storm surge sand (Oldham & Gibbins, 1995) and has been reinterpreted by Chaney (1998) as the distal part of a glacier burst deposit of a type common in Iceland and given the Icelandic name jokulhlaup. The normal process of outwash fan deposition takes place according to the seasonal melt cycle by streams issuing from active glaciers. On the larger fans such as Skeidara in Iceland (which is about 30 km long), downfan grain size variation is predictable and longitudinal to linguoid bars and channels form the principal fan geometry (Boothroyd & Nummedal 1978). In the Cooper Basin context this is the setting for "Tirrawarra type" sandstones (Williams & Wild 1984, Chaney et al 1997). Catastrophic floods (jokulhlaups) issuing from the tunnel mouth of glaciers, with very high sediment discharge rates episodically disrupt these conditions and create debris and fluid flows. Fluid flows are associated with erosion into the outwash plains to form incisions filled by gravel, sand, with minor silt and clay, and bearing massive to laminated, planar to trough cross-stratified beds and dewatering structures (e.g. Maizels 1989). In Iceland, jokulhlaups are generally caused by sub glacial volcanic activity. Another cause of jokulhlaups is glacier surging in response to wetter climatic phases or as a consequence of tectonic activity, producing englacial dam bursts. Incision depth is not well documented but Maizels (1989 and 1993) illustrated downcuts up to 10 to 12 m deep. The latter would set an upper limit for incision depth and thus one may anticipate a range of 3-10 m or so for Cooper Basin analogues. Cross-bedding directions on the sandur (glacial outwash plain) under normal conditions are variable in the longitudinal-linguoid bar-dominated conditions (Bluck 1974). Where sediment has been reworked and deposited as a result of jokulhlaups, however, current directions are presumed in contrast to have low dispersion. Some properties of jokulhlaups which may be anticipated in the Merrimelia Formation are sandier deposits, ranging in thickness from 3-10m and low directional dispersion of cross-beds within the sand packages in contrast to normal sandur (glacial outwash plain) deposits. Jokulhlaup deposits are common in the lower Merrimelia Formation in successive deglaciation cycles. They can be recognised on gamma ray logs and should be mapped with FMS or high resolution dipmeter data. Some jokulhlaups at least will contain hydrocarbons which have migrated from downdip Patchawarra Formation source rocks. REFERENCES Bluck, B .J., 1974. Structure and directional properties of some valley sandur deposits in southern Iceland. Sedimentology, 21. 533-554. Boucher, R.K., 1996. Big Lake Suite not Tirrawarra Sandstone in the Moomba Field, Cooper Basin, SA. PIRSA Report Book 96/31 (unpublished). Chaney, A.J. (1998): Sedimentology, facies architecture and hydrocarbon potential of the Merrimelia Formation (glacial Permo-Carboniferous), southern Cooper Basin, South Australia. Ph.D. Thesis, University of Aberdeen (unpublished). Chaney, A., Cubitt, C.J. & Williams, B.P.J., 1997. Reservoir potential of glacio-fluvial sandstones: Merrimelia Formation, Cooper Basin, South Australia. The Australian Petroleum Production and Exploration Association Journal, 37, 154-176. Gravestock, D.I., 2000. Glacier burst deposits in the Merrimelia Formation, Cooper Basin, South Australia. Weiss, H.R. (ed), Contributions to the Geology and Paleontology of Gondwana. Studies in honor of Helmut Wopfner. Institute of Geology, University of Cologne. Koln. Oldham, A.C. & Gibbins, N.M. (1995). Lake Hope 3D - A case study. Exploration Geophysics, 26: 383-394. Maizels, J.K., 1989. Sedimentology, paleofiow dynamics and flood history of Jokulhlaup deposits: paleohydrology of Holocene sediment sequences in southern Iceland sandur deposits. Journal of Sedimentary Petrology, 59(2), 204-223. 39

Maizels, J.K., 1993. Quantitative regime modelling of fluvial depositional sequences: application to Holocene stratigraphy of humid-glacial braid-plains (Icelandic sandurs). In: North, C.P. & Prosser, D.J. (eds), Characterization of fluvial and aeolian reservoirs. Geological Society Special Publication, 73: 53-78. Williams, B.P.J. and Wild, E.K. (1984). The Tirrawarra Sandstone and Merrimelia Formation of the southern Cooper Basin, South Australia - the sedimentation and evolution of a glaciofluvial system. The Australian Petroleum Exploration Association Journal 24: 377-392. Williams, B.P.J., Wild, E.K. and Suttill, R.J. (1985). Paraglacial aeolianites: potential new hydrocarbon reservoirs, Gidgealpa Group, southern Cooper Basin. The Australian Petroleum Exploration Association Journal, 25: 291-310.

SOURCE ROCK POTENTIAL AND ALGAL MATTER ABUNDANCE, COOPER BASIN, S.A. John F. Lindsay . David Gravestock Research School of Earth Sciences, Australian National University, Canberra, ACT 0200 2 Petroleum Group, Department of Primary Industries and Resources, SA, 101 Grenfell Street, Adelaide, SA 5000 1

The Cooper Basin, one of Australia's Gondwanan onshore basins, extends from northeastern South Australia into southwestern Queensland covering approximately 130,000 square km. The basin appears to have evolved in a mildly compressional environment with its general architecture being determined by older basement features (Apak et al., 1997). Like most intracratonic settings the Cooper Basin is polyphase and contains a thick Permian to Triassic succession of fluvial, lacustrine and, at the base, glacial rocks. The succession overlies, in part, the Early Palaeozoic rocks of the Warburton Basin and is in turn overlain by the Jurassic to Cretaceous rocks of the Eromanga Basin. The basin is the source of a significant proportion of Australia's onshore oil and gas and in particular supplies a large area of southeastern Australia with natural gas. The hydrocarbons are mostly reservoired in fluvial channel sandstone and point-bar deposits within the Permian Patchawarra and Toolachee Formations in association with basin highs. Lesser, but significant, reservoirs occur in shoreline sandstones associated with the Patchawarra, Epsilon and Daralingie Formations. The deposition of these formations was controlled in large part by basin subsidence rates and the rate of sediment supply, such that depositional environments alternate between fluvial, lacustrine and cool temperate coal swamps. The abundant supply of clastic sediments was provided by the earlier glaciation (Hobday, 1987). It has generally been accepted that the hydrocarbons reservoired in the Cooper Basin are largely relatively locally derived from interbedded organic matter. However, most of the associated organic matter occurs as coals interbedded within the succession and all appear to be inertinite rich and thus, at first sight, poor source rocks. Boreham and Summons (1999) have shown that two independent petroleum systems operate within the basin. The Patchawarra and Toolachee Formations contain hydrocarbons that are isotopically distinct with the Patchawarra Formations oils being isotopically lighter. Recent studies (Taylor et al., 1988) based on a single well penetrating the Patchawarra Formation suggest that alginite is associated with the inertinite component of the coals and could provide a more than adequate source for all of the hydrocarbons generated within the basin. The present study aims to refine and extend the earlier work of Taylor et al. (1988) on potential alginite sources by analyzing data reported from all wells within the South Australian part of the basin. The Cooper Basin is today a mature petroleum province such that more than 1200 wells penetrate the succession in the South Australian part of the basin. Much of the data available to us through well completion reports and related documents is qualitative. To overcome these problems we have ranked variables, such as the abundance of alginite, coal content and inertinite, on a scale from 0 to 5 with the upper limit indicating the component as abundant. Evidence of algal matter is relatively common. Of wells examined to date 31% contain evidence of algal matter in the Patchawarra Formation and 9% contain evidence of algal matter in the Toolachee Formation. Limited amounts of algal matter are also present in the associated Murteree Shale (2%), Epsilon Formation (9%), Roseneath Shale (9%) and Daralingie Formation (5%). In general, the abundance of algal matter increases with the total coal content of the two main reservoir intervals implying that much of the hydrocarbons are sourced relatively locally. This appears to be consistent with the analysis put forward by Boreham and Summons (1999) and by the distinct isotopic signatures of the two intervals. Areally, the data available to date suggest that algal matter is found more frequently closer to the basin margins and in areas of lower maturity. This implies that, in the more mature depocentres, much of the algal matter has been destroyed, particularly where coal rank is high and Ro max exceeds ~ 1.0.

REFERENCES

Apak, S.N., Stuart, W.J., Lemon, N.M. & Wood, G., 1997. Structural evolution of the Permian-Triassic Cooper Basin, Australia: relation to hydrocarbon trap styles. AAPG Bulletin 81, 533-555. Boreham, C.J. & Summons, R.E., 1999. New insights into the active petroleum systems in the Cooper and Eromanga Basins, Australia. APPEA Journal, 263-296. Hobday, D.K., 1987. Gondwana coal basins of South Australia and South Africa: tectonic setting, depositional systems and resources. In Scott, A.C. Coal and coal-bearing strata: recent advances. Geological Society of London. Special Publication 32, 219-233. Taylor, G.H., Liu, S.Y. & Smyth, M., 1988. New light on the origin of Cooper Basin oil. APEA Journal, 303309.

ASSESSMENT OF THE CAMBRIAN STANSBURY BASIN AND PETROLEUM POTENTIAL Wen-long Zang & Les Tucker 1 Geological Survey Branch, Mineral Resources Group, Department of Primary Industry and Resources SA, Box 1671, S A 5000 2 Petroleum Group, Department of Primary Industry and Resources SA, Box 1671, SA 5000 1

The late Reg Sprigg pioneered exploration of the Cambrian sequences in the Stansbury Basin, South Australia during 1950s - 1960s. He was responsible for the mapping of the KINGSCOTE 1:250 000 sheet (first edition) when employed by the Geological Survey of South Australia (Sprigg et al., 1953, 1954) and conducted a comprehensive study of the petroleum potential in the basin after waxy paraffinic crude was found in Wilkatana 1 in the neighbouring Arrowie Basin (Sprigg, 1961). He was one of the founders of Beach Petroleum Ltd. and the leader of the Stansbury Basin exploration team (Sprigg, 1963; Sprigg and Stackler, 1965). His interests in the basin lasted for some four decades (Sprigg, 1990) and his research laid a foundation for future exploration. Some twenty exploration wells have been drilled in the basin since the 1950s, but most of them were not ideally sited because of poor understanding of the tectonic development and sedimentation in the basin. Detailed study suggests a complex oil generation and migration history in Cambrian sediments and the existence of potential source rocks (McKirdy, 1994), whereas karstic, vuggy dolomite of the Kulpara Formation and abundant archaeocyathan/algal reefs in the basin could be potential reservoir rocks. A recent PIRSA aeromagnetic survey and stratigraphic database integration will provide valuable information to analyse the regional structures and thermal history of the basin. Petroleum potential in the Stansbury Basin was investigated by Harvey and Hibburt (1999). Generally, the lack of sufficient source rocks makes exploration in this frontier basin a high-risk venture. In 1998, two offshore wells were spudded. Enchilada 1 bottomed in the red-brown sandstone probably of Winulta Formation and Frijole 1 in red-brown siltstone of the Yuruga Formation (Figure 1). Neither of the two wells intersected Cambrian carbonate.

STRUCTURE AND SEQUENCE STRATIGRAPHY

Deposition of the Early Cambrian succession in the Stansbury Basin started with normal faulting which can be recognised by field and seismic interpretation. Exploration drilling reveals that the lower Cambrian sediments (eg. Winulta Formation) unconformably overlie Gawler Craton basement rocks on southern Yorke Peninsula, but to the north at Kulpara, east in Gulf St Vincent, and on Fleurieu Peninsula, the sediments unconformably overlie Neoproterozoic sediments. On Fleurieu Peninsula this truncation surface may correlate with the low-angle unconformity between the Lower Cambrian Mt Terrible Formation and underlying Neoproterozoic ABC Range Quartzite. The extensional faults on Yorke Peninsula indicate further break-up of the eastern margin of the Gawler Craton or subsidence of the crystalline basement during the Early Cambrian, resulting in the Lower Cambrian sediment onlap on the Palaeoproterozoic basement. These faults have been reversed during the Delamerian Orogeny and activity along them continues. The Cambrian sediments, up to 4000m thick in the depo-centres, are divided into three sequence sets on Yorke Peninsula and in Gulf St Vincent (Gravestock, 1995). The sets are also recognisable in seismic interpretation and can be divided into the lower carbonate (strong layer-parallel reflectors) and upper siliciclastic (massive to layered reflectors) packages. Detailed sequence stratigraphic study and biostratigraphy provides a reliable approach for analysing the distribution of potential source and reservoir rocks.

PETROLEUM POTENTIAL

A petroleum source rock study suggests that fair to good oil and gas prone sources are present in the basin, with up to 2.43% in the Heatherdale Shale (McKirdy, 1994; Table 1). Thermal index analysis of acritarchs suggests that the organic matter in e 1.2 and e 1.3 (cf. Gravestock, 1995) sediments is commonly yellow to brown, indicating a local palaeo-temperature of not more than 130°C, whereas in e 1.1 A dolomites the organic matter was probably altered by dolomitisation. In the SYC 101 well, the organic matter from e 1.2 nodular limestone is brown to dark-brown, whereas in thin siltstone interlayers yellow to yellow-brown, suggesting the overmaturity of the organic matter in the nodular limestone is probably related to depositional environments, rather than thermal alteration. The siltstone is considered to have been deposited in aerobic environments and the nodular limestone in local anaerobic stagnant brines (within a graben / half-graben according to lithofacies analysis), where sulfur bacteria might have re-worked organic matter before burial. Petroleum traps may be present in el.2 sequence in Gulf St Vincent, where a broad carbonate platform and gentle slope/ramp can be interpreted from seismic profiles. Analysis based on drillhole logging and seismic

sequence stratigraphic study suggests that the Parara Limestone and Koolywurtie archaeocyathan reefs prograded from a ramp/platform environment towards an eastern slope or a pelagic region where organic-rich transgressive Heatherdale Shale was deposited (Figure 2C). The shale may have been intertonguing with the limestone and reef complexes when sea level fluctuated during forced regression. The possible reef complexes are considered to be a potential reservoir with streaky mouldic / vuggy porosity (Gravestock, 1995). The reef complexes are overlain by siltstone of the Minlaton Formation which contains a very effective anhydrite seal; this siltstone might be organic-rich in offshore settings. Equivalent Oraparinna Shale in the Arrowie Basin contains up to 1.15% TOC (McKirdy, 1994). This is possibly another source rock which could contribute to the potential of reef complex reservoirs.

Y82-A2

Base of Tertiary

Base of the Yuruga Formation

Base of Permian

Base of the Minlaton Formation

—

Stansbury West 1

Stansbury Town 1

Base of the Cambrian r

SYC101

Minlaton 1

Pofnt Soiittar,

itansbury Town \ Carbonate Shelf

Peninsula Oil 1

Proterozoic'basement/sediments

KILOMETRES

upper Kulpara Formation (Limestone) lower Kulpara Formation (Dolomite) lower Minlaton Formation (Siltstone)

Winulta Formation (Sandstone) Parara Limestone (Nodular limestone) __ Koolywurtie Member Archaeocyathan-algal reefs

?Source

Koolywiirtie Membeix?

Reef Complex ? reservoirs Possible petroleum migration;

i - Parara . .Limestone

? Heatherdale Shale TOC up to 2.43% Older Rocks

Fig. 2. A. Seismic line Y82-A3. B. Block diagram showing sequences and sedimentary settings. C. Hypothetical petroleum model.

Carbonate reservoirs are common in the basins, particularly e 1.1 A highstand dolomites that were probably uplifted to subaerial exposure, forming vuggy, karstic and fracture porosity along the unconformity surface. Karstic and fractured carbonate reservoirs have been proven to be very productive in Siberian oil fields (Russia) and the Renqiou Oilfield, Tarim Basin and Weiyuan Gasfield (China). Table 1. Petroleum data and summary.TOC: total organic carbon content; Type II: oil prone; Type III: gas prone. Reservoir Rocks Dolomitised limestone Up to 500m thick, vuggy, dissolution and fractures, Carbonate (Kulpara Formation) core porosity up to 13%, permeability up to 340mD Reservoirs Koolywurtie reef complex Up to 73m thick, vuggy and dissolution porosity Winulta Formation 100m thick, arkosic, fluvial to shoreface sandstone, Sandstone (lower sandstone) lowstand deposits Reservoirs Stokes Bay Sandstone ~350m thick, shoreface sandstone, dissolution porosity Yuruga Formation >500m thick, lower part of sandstone: fluvial, arkosic with basal conglomerate, very porous Seal Micritic Parara Limestone Potential seal to the dolomitised limestone of the Kulpara Formation and sandstone of the Winulta Formation Minlaton Formation (siltstone+gypsum layers) Potential seal to underlying carbonate and reef reservoirs Yuruga Formation (upper siltstone) Potential seal to all underlying reservoirs Source Rocks Heatherdale Shale or equivalents TOC (max. = 2.43%, mean = 0.64%), Kerogen type II Parara Limestone TOC (max. = 0.91%, mean =0.30%), Kerogen type II-ID Corrodgery Formation Marine dark-grey shale (TOC = ? >0.5%), palaeotemperature <110°C (estimated from acritarch's colour index). Acknowledgment The authors thank Dave Gravestock (PIRSA) for his support and supervision of this study over a long period. The authors publish with the permission of Directors of Mineral Resources and Petroleum Groups, PIRSA. REFERENCES Gravestock, D. I., 1995. Early and Midlle Palaeozoic. In Drexel, J. F. and W. V. Preiss (editors). The geology of South Australia. Vol. 2, the Phanerozoic. South Australia. Geological Survey. Bulletin 54, 3-61. Harvey, S. C. & Hibburt, J. E. (compilers), 1999. Petroleum exploration and development in South Australia. South Australia, Department of Primary Industry and Resources, Report Book 99/3. McKirdy, D. M. 1994. Biomarker geochemistry of the Early Cambrian oil show in Wilkatana 1 implications for oil generation in the Arrowie and Stansbury Basins. PESA Journal 22, 3-17. Sprigg, R.C., 1961. Oil and gas possibilities of the St Vincent Gulf Graben. APEA Journal 1, 71-88. Sprigg, R.C., 1963. Completion report, Beach Petroleum N.L. Troubridge Island No. 1 stratigraphic well, OEL 24. South Australia. Department of Mines and Energy, Envelope 324. Sprigg, R.C., 1990. Implications of the discovery of Archaeocyatha in the Macclesfield Marble, Mount Lofty Ranges. In: Jago, J.B. and Moore, P.S. (Eds), The evolution of a late Precambrian-early Palaeozoic rift complex: the Adelaide Geosyncline. Geological Society ofAustralia. Special Publication 16, 324-333. Sprigg, R.C. & Campana, B., 1953. The age and facies of the Kanmantoo Group, eastern Mount Lofty Ranges and Kangaroo Island. Australian Journal of Science 16, 12-14. Sprigg, R.C., Campana, B. & King, D., 1954. KINGSCOTE map sheet. South Australia. Geological Survey. Geological Atlas 1:253 440 (4 mile) Series, sheet SI53-16. Sprigg, R.C. & Stackler, W.F., 1965. Submarine gravity surveys in St Vincent Gulf and Investigator Strait, South Australia, in relation to oil search. APEA Journal 5, 168-178.

TECTONICS AND HYDROCARBON POTENTIAL OF LORD HOWE RISE H.M.J. Stagg , P.A. Svmonds . M. Alcock ,1. Borissova , A.M.G. Moore , S. Van de Beuque Australian Geological Survey Organisation, Canberra, ACT IFREMER, c/- Australian Geological Survey Organisation, Canberra, ACT 1

BACKGROUND The foundered continental fragment of Lord Howe Rise extends for almost 2000 km from northwest of New Zealand, to west of New Caledonia. It ranges from 400-700 km in width, and lies at water depths generally deeper than 1000 m. Lord Howe Rise was detached from eastern Australia during the breakup of eastern Gondwana that preceded the formation of the oceanic Tasman Basin from 85-52 Ma. Under the United Nations Convention on the Law of the Sea (UNCLOS), Australia may claim an 200 nautical mile Exclusive Economic Zone (EEZ) around Lord Howe and Norfolk Islands and an extended 'Continental Shelf beyond the EEZ that takes in an area of about 1.4 million km , comparable to the area of Queensland. A substantial part of the Australian jurisdiction includes the central segment of Lord Howe Rise and its sedimentary basins. 2

The available geoscientific data sets are limited, and include: deep-seismic data acquired by the Australian Geological Survey Organisation (AGSO); regional seismic lines recorded mainly in the early 1970s; Deep Sea Drilling Project sites; samples dredged from the flanks of the rise; and satellite gravity and predicted bathymetry. Recent interpretation of these disparate and sparse data sets within AGSO's :Law of the Sea project provides some important new insights into the tectonic framework and resource potential of this enormous feature. TECTONIC PROVINCES From east to west, the Lord Howe Rise comprises four sub-parallel provinces (Figs 1, 2), viz: Shallow, planated, probable Palaeozoic basement of the Lord Howe Platform, which is overlain by a few hundred metres of Cainozoic ooze. Basement to the east is down-faulted by up to 4 km into the New Caledonia Basin, which is of uncertain crustal affinity, while the western boundary is defined by a Cretaceous hinge. A central rift which is characterised by a series of poorly defined basement blocks that are normally downfaulted to the west. This rift contains 2-4 km of Cretaceous and Cainozoic syn- and post-rift section and includes the Moore Basin in the south and the Faust Basin in the north. A western rift, which is also characterised by normal-faulted basement blocks and a sediment fill that is somewhat thicker than in the central rift. This rift lies at greater depths than the central rift, and the two rifts are separated by a broad fault zone that may be a sub-branch of a regional detachment surface. The western rift includes the Monawai Basin in the south and the Capel Basin in the north. In the vicinity of Lord Howe Island, the two rifts cannot be distinguished, and the combined structure is referred to as the Gower Basin. A western ridge complex that, where sampled, is of continental origin. In the south, the Monawai Ridge forms the western flank of the Monawai Basin, while in the north, where continental extension may have proceeded further, the segmented Dampier Ridge is separated from the sedimentary Gower and Capel Basins by the physiographic Lord Howe and Middleton Basins. Volcanism has been important in the tectonic development of the region, with four volcanic phases recognised: • Early to mid Cretaceous (120-95 Ma) - slightly alkaline volcanogenic sediments possibly derived from an Aptian-Albian volcanic arc, but more likely from transitional extensional/transtensional magmatism along the line of incipient Tasman Sea breakup; • Late Cretaceous (ca 85-80 Ma) - basic volcanics associated with Tasman Sea breakup, interpreted in seismic data; • Eocene-Oligocene (37-36 Ma) - basaltic volcanics interpreted to be related to the formation of a major western New Zealand rift system, and mainly restricted to the southern end of Lord Howe Rise; and • Miocene (24-6 Ma) - basaltic volcanism reflected by the linear, N-S trending hotspot trails of the parallel Tasmantid and Lord Howe seamount chains. Interpretation of seismic and satellite gravity data shows the importance of regional-scale crustal lineaments in compartmentalising the Lord Howe Rise. These lineaments are oriented NE-SW in the west, where they were probably active in the Cretaceous and early Cainozoic, and NW-SE in the east, where they are of mid to late Cainozoic age (Fig. 1). The NE-SW lineaments are the more important on Lord Howe Rise and the most important of these is referred to as the Barcoo-Elizabeth-Fairway Lineament (BEFL). This lineament extends

for about 1800 km northeast from the vicinity of Jervis Bay on the Australian margin to the northern end of the Norfolk Ridge complex, and has structural expression as: • the boundary between the relatively 'normal' seafloor spreading in the southern Tasman Sea, and the highly segmented and oblique spreading in the northern Tasman Sea; • offsets in the Dampier Ridge and between the Lord Howe and Middleton Basin; • a 130 km northwards narrowing of the Lord Howe Platform due to an eastwards step in its western margin; • southwards termination of the Fairway Basin and Fairway Ridge; and • a major northwards constriction of the New Caledonia Basin. CONVENTIONAL AND NON-CONVENTIONAL HYDROCARBON POTENTIAL Lord Howe Rise has been recognised as a potential conventional hydrocarbon province since the mid-1970s, although it has never been actively explored. Assessment of the hydrocarbon prospectivity has been largely dependent on an understanding of the regional palaeogeography and on comparisons with the conjugate Australian continental margin, which includes the New England and Lachlan Fold Belts, Permo-Triassic Sydney Basin, Triassic to Cretaceous Maryborough Basin and the highly petroliferous Gippsland Basin. On the basis of adequate sediment thickness, two areas are recognised as having potential - viz the central and western rifts, and the narrow rift that separates the Lord Howe Platform from the New Caledonia Basin. The deeper half grabens in the central and western rifts contain up to 4000 m of sediment (Fig. 3) which may include suitable fluvio-lacustrine sources of comparable age to, or older than the Gippsland Basin source sequences. Potential reservoir sequences may be present in the form of interbedded sandstones in fluvial and shallow marine sequences, while pelagic oozes could provide the regional seal. The eastern flank of Lord Howe Rise has been interpreted to be an ancient seaboard of the Australia-Antarctica supercontinent (Willcox et al., 1980). Thick ?Upper Cretaceous clastic sediment, derived from the Lord Howe Platform, was deposited across this margin above a narrow rift. Depositional environments within this rift, and also in the adjacent thick section (ca 4 km) in the New Caledonia Basin may have been favourable for the deposition and preservation of suitable source rocks. Extensional and compressional structuring within this province is extremely complex, and there is scope for both structural and stratigraphic traps. The degree to which multi-phase volcanism may have affected the hydrocarbon potential of Lord Howe Rise is unclear. Possible negative impacts include damage to reservoirs and to pre-existing hydrocarbon accumulations. However, positive impacts include the sealing capacity of extrusions and shallow intrusions (as in some Gippsland Basin fields), potential good-quality volcaniclastic reservoirs, and a Miocene and later heat-flow pulse which might have enhanced maturity in a sedimentary section that is otherwise of marginal thickness. Exon et al. (1998) have reported a 'bottom-simulating reflector' (BSR) that extends over an area of at least 25,000 km of the eastern flank of the northern Lord Howe Rise and adjacent New Caledonia Basin in water depths of 1500-3600 m. BSRs may indicate an interface between overlying sediment containing methane hydrate (a frozen crystalline mixture of methane and water) and underlying sediment containing bubbles of free methane gas. The depth of the BSR of 520-600 m below sea bed, as inferred from seismic reflection profiles, is consistent with this interpretation, given the expected thermal gradient for the region. Subsequently, BSRs have also been identified on the western flank of the northern Lord Howe Rise, where it descends into the Middleton Basin, on the crest of the rise above half-graben, and in the northern part of the Monawai Basin (Fig. 4). Satellite synthetic aperture radar (SAR) imagery also contains some evidence of low level oil slicks and films that are approximately coincident with observed BSRs in the Fairway Basin and on the flank of the Middleton Basin. These observations, discussed further in Stagg et al. (2000), are the first compelling evidence for methane hydrate deposits in waters off Australia. If confirmed, these could represent an immense accumulation of natural gas in an unexpected open-ocean location within both French and Australian seabed jurisdiction. 2

REFERENCES Exon, N,F., Dickens, G.R., Auzende, J-M., Lafoy Y., Symonds, P.A. & Van de Beuque, S., 1998. Gas hydrates and free gas on the Lord Howe Rise. PESA Journal, 26, 148-58. Stagg, H.M.J., Symonds, P.A., Exon, N.F., Auzende, J-M., Dickens, G.R. & Van de Beuque, S., 2000. Gas hydrates in Australia's marine jurisdiction: a potential long-term resource. PESA, this volume. Willcox, J.B., Symonds, P.A., Hinz, K., & Bennett, D., 1980. Lord Howe Rise, Tasman Sea - preliminary geophysical results and petroleum prospects. BMR Journal ofAustralian Geology & Geophysics, 5, 225-236.

Volcanics

Kermacec Trench

Bellona Trough

LHB

Lord Howe Basin

NHT New Hebrides Trench

Capel Basin

LHP

Lord Howe Platform

Faust Basin

Maryborough Basin

Sydney Basin

Fairway Ridge

MiB

Middleton Basin

Taranaki Basin

GoB Gower Basin

MoB Moore Basin New Caledonia Reinga Basin

FwB Fairway Basin

MnB Monawai Basin

TKR Three Kings Ridge

GiB Gippsland Basin

MnR Monawai Ridge

WNR West Norfolk Ridge

Figure 1: Tectonic provinces of the Lord Howe Rise region.

Tasman Basin

WESTERN RIFT Monawai Ridge Monawai Basin

CENTRAL RIFT Moore Basin

Lord Howe Platform

New Caledonia Basin

Figure 2: Seismic profile from the Tasman Sea, across Lord Howe Rise to the New Caledonia Basin (lines LHRNR-G and 114-4).

Figure 3: Half-graben development in the Gower Basin (line S036A-11).

Figure 4: Bottom-simulating reflector (arrow) in the Monawai Basin (line 114-9).

PETROLEUM GEOLOGY OF THE ONSHORE MARYBOROUGH BASIN Paul Lipski Magellan Petroleum Australia Limited, Level 10,145 Eagle Street, Brisbane, QLD, 4051

STRUCTURE AND STRATIGRAPHY The Maryborough Basin is a mainly Mesozoic basin in southeastern Queensland. It covers an area of approximately 24,600 square kilometres, of which approximately 9,100 square kilometres are located onshore. The basin is oriented northwest-southeast, approximately parallel to the coast. It is bounded on the western margin by a major down-to-basin fault system, known as the Electra Fault system. The eastern offshore margin is controlled by the fault-bounded basement rise of the Bunker Ridge, located north of Fraser Island. Deposition within the Maryborough Basin was contemporaneous with the Surat and Eromanga basins for most of its geologic history (Figure 1). The Maryborough Basin was initiated in the Late Triassic as a result of extensional rejuvenation of the major northwest trending Electra Fault system. This resulted in considerable subsidence to the east. Upper Cretaceous compressional deformation produced a number of northwest-trending asymmetrical anticlines and synclines, with both high angle and low angle reverse faults. This major tectonic event can be correlated across the Surat and Eromanga Basins, where it is known as the Winton Movement. The magnitude of this event was greater to the east in the Maryborough Basin. The tectonic episode is well documented and has been dated as 85 to 80 million years before present. This period of compressional tectonism overprinted the previous mainly tensional regimes and created the structural traps that form the basin's primary exploration targets. The Maryborough Basin sequence ranges in age from latest Triassic to lower Tertiary. Continued sedimentary loading in the central part of the Maryborough Basin resulted in the deposition of in excess of 6,000 m of sediments and minor volcanics of mainly Jurassic and Cretaceous age. The sequence rests unconformably on an economic basement composed of Permian and lower Triassic metasediments and granites of the Gympie Basin sequence. At the base of the Maryborough Basin sequence, continental sedimentation occurred throughout the Late Triassic to Early Jurassic, resulting in the deposition of the Myrtle Creek Sandstone and the Tiaro Coal Measures. The Myrtle Creek Sandstone is considered to be the lateral equivalent of the Precipice Sandstone and the Tiaro Coal Measures is considered to be the lateral equivalent of the Evergreen/Hutton/Walloon Coal Measures sequence of the Surat Basin. This was followed by a period of continental volcanism, which resulted in the deposition of the Graham's Creek Formation. This volcanism was followed by uplift in the Late Jurassic to Early Cretaceous. The following thick lower Cretaceous depositional sequences consisted mainly of marine and coastal/estuarine sediments of the Maryborough Formation and the fluviodeltaic/lacustrine Burrum Coal Measures. Following a period of compressional uplift in the Late Cretaceous, a veneer of lower Tertiary fluvial sediments was deposited. Periods of basaltic volcanism also occurred locally during the Tertiary. HYDROCARBON CHARGE The Myrtle Creek Sandstone and the Tiaro Coal Measures are thick lower to middle Jurassic mainly continental sequences containing sandstones, carbonaceous shales, siltstones and coal seams deposited in fluviatile to lacustrine environments. The sequences have not been penetrated by any deep exploration wells in the area. The units are known from shallow stratigraphic drilling and outcrop data on the margins of the basin. Maturity modelling suggests that the Myrtle Creek Sandstone may have experienced early charge from intraformational black shales in the lower part of the unit, and possibly from the shales and coals of the overlying Tiaro Coal Measures. In the Cretaceous sequence, there is a thick sequence that has source potential in both the shales of the Maryborough Formation and also in the shales and coals of the Burrum Coal Measures. The organic material analysed to date from the Cretaceous section is mainly continental in origin and comprised of Type II and Type III kerogens. The kerogen type is thus both oil and gas prone. Maturities, estimated from vitrinite reflectance studies, are high. Vitrinite reflectance studies have been conducted on samples from the Maryborough Formation in the four wells drilled in the central part of the basin. Most samples from 500 to 3,000 metres depth displayed current vitrinite reflectance ranges from 1.0 and 2.5. This places the formation mainly within the present mature gas window. Maturation modelling suggests that significant gas charging occurred at the time the structures formed during the upper Cretaceous Winton Movement. This was likely to have been followed by a second episode of gas charging from the Miocene onwards. This later phase would be associated with periods of high heat flow related to lower Tertiary basaltic volcanism and intrusive activity. The Maryborough Formation is comprised primarily of interbedded shales, siltstones and sandstones. The unit is a thick sequence that was deposited in marginal marine to estuarine environments. Where fully preserved, the Maryborough Formation appears to have a fairly uniform thickness of approximately 2,500 m across ATP 613P. Although the shales of the entire sequence have source potential, the richest source appears to be the thick black shale unit in the basal half of the Lower Pelitic Member, informally termed the Cherwell Mudstone. The source rocks are expected to

have been primarily within the gas window at the time of trap formation. This is supported by the recovery of gas from the Maryborough Formation in Gregory River-1. Potential source rocks also exist within the lower Cretaceous Burrum Coal Measures. Consisting primarily of siltstone, shale and coal seams, these sediments represent a predominantly fluviodeltaic and lucustrine sequence. The Burrum Coal Measures are generally preserved in synclines and in the central parts of the basin. RESERVOIRS The primary reservoir objective in the basin is the Gregory Sandstone of the Maryborough Formation. The unit consists of sandstone, siltstone and shale with minor conglomerate deposited in marginal marine to estuarine environments. The sandstones have reservoir potential with a gas flow rate of 200 MCFPD reported from Gregory River-1 at a depth of 2,780 to 2,807 m. Wireline log evaluation from Gregory River-1 indicates that matrix porosities average 6% and increase to 10 - 12% in several thin untested zones. There is also considerable potential for multiple reservoir horizons due to the interbedded nature of the unit. Matrix permeability is generally low, although this is based on a very limited core data set samples taken from a 500 metre gross interval. Natural fractures, both open and closed, were observed in several cores. Some fractures were observed to be bubbling gas. The only quantitative analyses of this reservoir in the subsurface have occurred at depths below 2,600 m. Reservoir quality was found to be poor. There is also reservoir potential in the sands of the Upper Sandy Member of the Maryborough Formation. The upper Triassic to lower Jurassic Myrtle Creek Sandstone is the lowermost depositional unit in the Maryborough Basin sequence. It is generally several hundred metres in thickness. The upper part is composed predominantly of massive quartzose sandstones. The lower part is generally more interbedded, consisting mainly of quartzose and felspathic sandstones, siltstones and shales. The depositional environment was dominated by braided stream, meander channels and overbank deposits. The unit is considered to be the lateral equivalent of the Precipice Sandstone of the Surat Basin. The unit is exposed at some locations along the western margin of the basin, where it has observed outcrop porosities of up to 30% and good associated permeability. Some of the favourable reservoir characteristics, however, may have been induced by surface leaching. Although it has been buried very deeply over most of the basin, the unit is still considered to have reservoir potential for gas. Early gas charge may also have preserved some primary porosity. There is also potential for fracture porosity. The Myrtle Creek Sandstone, however, has not been intersected in any of the basin's petroleum exploration wells. TRAPPING STYLE The dominant trapping style in the Maryborough Basin is structural. All structural traps identified to date are related the upper Cretaceous compressional deformation that resulted in a number of northwest trending asymmetrical anticlines and fault-bound rollovers. These are the primary exploration targets in the basin. This compressional tectonic event overprinted a structural style that was extensional throughout most of the Maryborough Basin history. In many cases compressional structures have been formed as reactivations of preexisting normal faults. Effective seals are developed throughout the Maryborough Basin sequence. The thick sequence of carbonaceous shale in the Lower Pelitic Member of the Maryborough Formation should adequately seal the top of the Gregory Sandstone. Intraformational shales within the Gregory Sandstone Member and Upper Sandy Member objectives should seal the numerous prospective thin sandstones that are characteristic of these units. In fault-dependent structures in the Cretaceous section, there should be a relatively high level of confidence in fault seal. Being a primarily argillaceous section, presence and adequacy of seal should not be problematical. PROSPECTIVITY After intermittent exploration, previous explorers became unenthusiastic about this basin because it was deemed to be gas prone. Gas was not considered viable in 1981, when the last well was drilled. Only four exploration wells have been drilled thus far in the central part of the onshore Maryborough Basin. Two early 1950's wells were drilled off structure and without gas detection equipment, a third well drilled in 1966 flowed gas at 200 MCFPD, and the fourth well drilled in 1981 flowed gas at a rate too small to measure. The two valid structural tests were drilled overbalanced, with evidence of tool plugging in the 1966 well. The reservoir objectives were gas charged, but deemed to be tight. Gregory River-1 had high gas saturations in low porosity sands over a gross interval of 500 metres. Maturation modelling suggests that similar undrilled prospects should also have been charged with gas. Structure, gas charge and seal are considered to be relatively low risk in the Mesozoic sequence of the Maryborough Basin. In terms of structure, outcrop geology and limited seismic coverage suggest the presence of abundant compressional rollovers, with both fault-independent and fault-dependent rollovers. In terms of charge, a thick, organic-rich, mainly argillaceous Cretaceous section lies within the current oil to dry gas generative window. Jurassic shales and coals also have gas prone source potential. The predominance of shales

in the sequence ensures seal adequacy. The highest risk is associated with reservoir. In addressing reservoir risk, the following points will be significant in future exploration: 1. The maturing of prospects, in which the reservoir objectives currently occur at relatively shallow depths, and in which the maximum depth of burial, prior to uplift, has not been prohibitive. 2. The identification of areas that exhibit favourable reservoir facies or porosity enhancement. With a well density of less than one well per thousand square kilometres in the central part of the basin, there is ample opportunity for the discovery of quartz-rich channels in the Gregory Sandstone and the Upper Sandy Member of the Maryborough Formation. There is also potential for the presence of structures with primary porosity preserved by early gas charge, local areas that have experienced secondary dissolution adjacent to faults and unconformity surfaces, and the development of fracture porosity on the crests of faulted compressional rollovers. 3. Technological advances are now unlocking large reserves of gas in areas previously thought to be too tight to be of commercial interest. The implementation of underbalanced drilling and modern fraccing techniques should increase the flow potential of any future discovery.

CRETACEOUS

TERT

AGE

JURASSIC

Intermittent basaltic volcanism Winton Movement compressional tectonism

-J

TRIASSIC

TECTONIC EVENTS

Extensional downwarp

Uplift associated with island arc volcanism

ENVIRONMENT & THICKNESS

LITHOLOGY

Fluvial (0-50m)

Sandstone

Lacustrine/ deltaic (0-3,000m)

Marine/ estuarine (0-3,300m) Continental volcanics volcanoclastics (0-1,200m)

MARYBOROUGH BASIN

£i LU

Fluvial/ lucustrine (0-850m)

Elliott Fm

Claystones, siltstones coals and minor sandstones

Burrum Coal Measures

Claystones, siltstones minor sandstones Maryborough Fm Interbedded sandstones Gregory Sst and claystones w v A . Member Volcanics, tuffs and conglomerates

Graham's Creek Fm

Sandstones, siltstones, claystones and minor coals

W \ A / v w >

Tiaro Coal Measures

Griman Creek Fm Surat Siltstone

Winton Fm Mackunda Fm Allaru Mudstone Toolebuc Fm

Wallumbilla Fm

Bungil Fm Cadna-Owie Fm Mooga Sst Orallo Fm Gubberamunda Sst Hoorayj^^ Westbourne Fm Westbourne Fm Springbok Sst Walloon Coal Measures Binchead Fm

ywfl&Wvw

Hutton Sst Evergreen Fm

Fiuviai (0-500m)

-J

NE EROMANGA BASIN

WVWVWVN ^ W V W V W V AA/VWVWV

Extensional block faulting

SURAT BASIN

Sandstones and minor claystones

Myrtle Creek Sandstone

Hutton Sst Poolowanna / Basal Jurassic

A / W W W W

v w w v w v >

Uplift, folding,

intrusion, low 5 grade metamorphism UJ

Gympie Basin Sequence Bowen Basin Sequence Cooper Basin Sequence

Figure 1. Generalised stratigraphy of the Maryborough Basin, with equivalent sections from the Surat and northeastern Eromanga basins.

THE ADELAIDE GEOSYNCLINE AS A FRONTIER CONTINENTAL TERRACE A REVIEW C. R. Dalgarno PO Box 8051 Mount Gambier East, South Australia, 5091 Today the Adelaide Geosyncline is recognised as a record of the break-up of a Rodinian Supercontinent which existed, dismembered and commenced in part to re-weld in the interval one billion to a half billion years ago. Reg Sprigg, having worked since his student days with his mentor, Sir Douglas Mawson, was the first to describe a continental terrace setting for this thick succession of clastic and carbonate sediments and its fold and fault patterns in his classic contribution to the Sir Douglas Mawson Anniversary Volume (Sprigg 1952). Sprigg worked tirelessly on this interest in his early years as a student geologist and soil scientist in the Mount Lofty Ranges and Kangaroo Island and had an unparalleled knowledge in his time of the stratigraphy of these regions. With the growth of systematic stratigraphy he developed with Mawson the first attempt at classification and terminology of the sequence in the Adelaide region, the framework of which has essentially survived. The formal nomenclature of the Torrensian, Sturtian and Marinoan Series, taken from the sequences exposed in the face of the Mount Lofty Ranges from the Torrens and Sturt Gorges to the coast at Marino has survived to the new millennium and is recognised in correlation of the Neoproteroic around the world. Their approach in adopting Time Rock terminology reflects the global significance that they placed on the new names for the late Precambrian strata of southern and central Australia and while open to some misconception, has provided a classification which permits discussion of such features as the major phases of glaciation in both Sturtian and Marinoan times. In the late 1940's the Willouran Range area west of Marree had attracted Sprigg's attention from the wartime RAAF photographic record which involved wide spaced flight lines of vertical and oblique photographs. His paper "Thrust Structures in the Witchelina Area", Sprigg (1950), was again a forerunner which introduced the geological fraternity to a new province which has been studied over the years by industry explorers, academics and the Geological Survey. This is the region which lends its name to Sprigg*s Willouran Series and contends with the Arkaroola area as the most significant exposure of the early rift succession of the Adelaide Geosyncline. Sprigg (1952) noted that the Series subdivisions are mostly based on movements within the neighbouring geanticlines as well as climatic changes, notably glaciation, which influenced sea level and the erosion of sediments at the shelf edges. He recognised that the shelves display prominent intraformational unconformities and remarked that in late Sturtian time, with deglaciation and unloading of continental ice, active subsidence east of the Torrens line of faulting favoured rapid reworking of glacigene materials from the Stuart Shelf. The Willouran Range proves to be one of the very good areas to demonstrate this relationship. Mawson and Sprigg did not include the 'Pound Quartzite' in their classification of the Adelaide System. Time has seen us debate the definition of the base of the Cambrian both here and worldwide and the Ediacara fauna, discovered by Sprigg, and its correlatives around the world, have led to wide interest in the definition of an Ediacaran time rock succession which would include the Pound Subgroup. The broadest likely definition for this interval encompasses all the 'Purple Series' of Mawson above the Marinoan glacial epoch and up to and including the 'Pound Quartzite'. Sprigg played a largely unsung part in the work of description of the Cambrian successions of South Australia but due to his wide travel and intuitive interest in everything from fossils to petroleum exploration he was instrumental in many investigations from Kangaroo Island and the Spencer and Stuart Shelf regions to central South Australia (Arrowie and Warburton Basins) and beyond. His work was pioneering and inspirational and touched on many facets which have required detailed research and mapping to unravel. Subsequent work by the Geological Survey of South Australia and university and other researchers has considerably refined classification of the rock succession of the Adelaide Geosyncline (Thomson et al, 1964, Preiss, 1989, etc.) and has significantly increased understanding of facies and sequence stratigraphy together with the tectonic setting as a rift complex associated with continental break-up. One facet of the geosyncline's development which was largely left by Sprigg to later Geological Survey mappers was the pattern of diapir growth and their history of erosion, first described for the Blinman Dome by Bruce Webb, (Webb 1961). In past decades a whole literature and terminology has developed around salt tectonics and

its interaction with basin architecture and sedimentation in areas such as the Gulf of Mexico, the North Sea and South Atlantic margins. Features which were first identified by Bruce Webb and others in the structurally deformed and well exposed diapirs of the northern and central Flinders Ranges have more recently been identified by refined seismic methods in continental terrace settings and by simulation modelling, eg., Guglielmo et al. (1997). Thus terms such as "salt walls" are named for contiguous diapir trends, eg., the Oratunga-Blinman-Enorama-Oraparinna trend of the central Flinders Ranges (Dalgarno and Johnson 1967, Fig.5), while examples of symmetric graben and half graben "salt ridges and rollers" can readily be identified by reference to Figure 10 (ibid). A host of other features identified elsewhere with modern 3D seismic and experimental modelling methods have been mapped here in surface exposure. This presentation summarises contributions by many authors who followed Sprigg's pioneering description of his Adelaide Continental Terrace and it emphasises the value of the Flinders-Mount Lofty Ranges in providing very good exposure of a variety of features interpreted in sub-surface petroleum exploration activities in basins around the world. We have in this region surface expression of plays and fairways interpreted only from seismic and drilling in other regions or from bottom bathymetry and sonar studies of the modern ocean floor. Reg Sprigg had the vision to identify many of these features and to see the advantage of systematic geological mapping and use of consistent nomenclature in the South Australian model. We should make full use of this example of a rift complex associated with continental separation as a laboratory for training our professionals, to hone their skills in traditional geology and hence enhance their interpretive skills in new techniques. By developing skills in the field we will improve their abilities to identify potential pitfalls in the search for economic targets. ACKNOWLEDGMENT Thanks to Wolfgang Preiss of PIRS A who made helpful comment on the draft of this abstract. REFERENCES Dalgarno, C.R. & Johnson, J.E., 1967. Diapiric structures and late Precambrian-early Cambrian sedimentation in the Flinders Ranges, South Australia. AAPG Memoir No.8, 301-314. Guglielmo, G., Jackson, M.P.A. & Vendeville, B.C.,1997. Three-dimensional visualization of Salt Walls and associated fault systems. AAPG Bulletin, V.8I.N0.1, 46-61. Mawson, D. & Sprigg, R.C., 1950. The subdivision of the Adelaide System. Aust. Journ. Science, 13(3). Preiss, W.V., 1989. A stratigraphic and tectonic overview of the Adelaide Geosyncline, South Australia. In Jago, J.B. and Moore, P.S. eds., The Evolution of a Late Precambrian-early Palaeozoic rift complex: the Adelaide Geosyncline. Geological Society of Australia special publication 16. Sprigg, R.C., 1950. Thrust structures of the Witchelina area, South Australia. Transactions of the Royal Society of South Australia 73, 40-47. Sprigg, R.C., 1952. Sedimentation in the Adelaide Geosyncline and the formation of the continental terrace. In Glaessner M.F. & Sprigg R.C. eds. Sir Douglas Mawson Anniversary Volume. University of Adelaide. Thomson, B.P., Coats, R.P., Mirams, R.C., Forbes, B.G., Dalgarno, C.R. and Johnson, J.E., 1964. Precambrian rock groups in the Adelaide Geosyncline: a new subdivision. Quarterly Geological Notes, Geological Survey of South Australia 9, 1-19. * Webb, B.P., 1961. Diapiric structures in the Flinders Ranges, South Australia. Trans. R. Soc. S. Aust., 85, 1-6.

CHALLENGES TODAY IN EXPLORING FRONTIER BASINS Hector Gordon Beach Petroleum NL, 25 Conyngham Street,Glenside SA 5065

"Wildcatters are gamblers". So said Reg Sprigg and, while the term "gambling" is anathema to many of today's explorers, for most companies exploration in frontier basins remains, essentially, a gamble. Today's explorers in today's frontiers face a multitude of challenges. These include, not only the geotechnical challenges associated with exploration in a new geologic frontier, but also challenges less familiar to explorers, such as those presented in environmentally sensitive areas or the recognition the rights of the traditional landowners in many of Australia's onshore frontier basins. Our industry has made great strides forward in developing tools to analyse, quantify and manage the risks inherent in the exploration process. This has been a key factor in the survival of the exploration industry in today's environment, where, in order to obtain funding for our activities, it is necessary to present exploration as an investment opportunity, with a relatively predictable result and return. Because of the greater economic scrutiny to which exploration programs are now subjected, lower risk projects are generally favoured and the industry has become more risk averse. A key challenge for today's frontier explorers, as it was for explorers in the Cooper Basin in thel950's, is the task of obtaining funds to pursue sound exploration concepts in a very high risk environment. This will require a different mindset, by both explorers and the 'decision makers', to that commonly prevailing in the industry today. Skillful risk analysis and risk management cannot replace the geological creativity and willingness to take a chance that is critical to achieving success in frontier basins.

PETROLEUM GEOLOGY AND GEOLOGICAL EDUCATION. Brian McGowran Department of Geology & Geophysics, The University of Adelaide, SA 5005. Does petroleum geology exist? Undoubtedly it is a useful term, like "economic geology" and "marine geology", but the downside is that it can imply a kind of wall as insidious as the walls between academic departments. Thus, academia has to simultaneously attend to the needs of professional employment and the realities of increasingly rapid and unpredictable change in the intellectual disciplines comprising the earth sciences. This is a useful dualism, much the same as the hallowed dualism of the "English-based" philosophy of attending to the students vis-a-vis the "German-Scottish based" attending to the disciplines. Teaching by scientific revolution? Geology's heart is to be found in rock relationships and earth history and, most of all, in the realisation of the immensity of geological time, which is fully comparable to the previously realised immensity of astronomical space. I believe that we should establish in our teaching the identity of geology by a kind of intellectual logo-by focussing from the outset on rock relationships, especially the triad of stratigraphic unconformities, structural deformities, and intrusive contacts. All of these quintessentially geological configurations and their significance are explainable in the field to beginning students. From this flows the notion of seven "revolutions"(McGowran, 1999): 1. The rock cycle, which took hold at the turn of the 18^/19* C? 2. The geological time scale and earth history. 3. The theory of organic evolution. 4. The theory of isostasy. 5. Radiometric dating and calibration of the geological time scale. 6. Continental drift and plate tectonics. 7. Planetary environmental history. Planetary environmental history. For more than thirty years the drilling vessels Glomar Challenger and Joides Resolution have been drilling the floor of the global ocean. Every single discipline comprising the earth sciences and others such as microbiology have been involved. A new and unifying member has arisen: palaeoceanography, based in geochronology, micropalaeontology and stable-isotope geochemistry among others, based equally in big questions about global environmental change and stability. Palaeoceanography has produced more and more rigorous scenarios of the great global transformation from the greenhouse world of the dinosaurs to the icehouse world of today. Palaeoceanaography is impacting all imaginable specialties of the environmental sciences-mammalian evolution including human evolution; deserts, rangelands and forests, and soils history; feedbacks between atmosphere, surface waters and deep oceans, modelling global climatic change. We chase geobiological, geochemical and geophysical signals from the ocean (pelagic realm) into shallow seas (neritic realm) and into soils, landscapes and their communities (terrestrial realm) and back again. We could make comparable statements about other unifying disciplines, such as sequence stratigraphy. Education must reflect the cross-fertilisation, integration and iteration of disciplines that characterises modern earth science and its practical application. Figure 1 is one illustration of a shift in thinking-beware of outsourcing your specialisms! (From Payne et al., 1999). Hsu (1997) expresses this with his customary forcefulness: "A reform in earth science is urgent. There should be an insight into the philosophy of science, and a realisation of the impracticality of instituting rigid "requirements" to "prepare" for a student's career. Methodological courses should be minimised and the duration of study should be greatly shortened, to be complemented by continuing education. Theoretical geology should be taught, and the theoretical knowledge be applied to resource-and environmental engineering." For an example of what is involved in understanding the simple and hallowed word "stratigraphy", inspect the stratigraphic tool kit in Figure 3 (from Doyle & Bennett, 1997). Stratigraphy has been resurrected by the advent of sequence stratigraphy, and it is apparent to everyone in the field that to grasp it, one needs to recall far more of the earth sciences than was apparent even a couple of decades ago. We are dealing with systems in the natural world, from within and below the earth's crust to the biosphere (Figure 2) and there are feedbacks through that chain that are more startling now than was apparent only recently. It is intuitive that the physical environment affects the biosphere; it is perhaps counterintuitive that the reverse happens too. Grasping these basic theories, key evidence, and ways of thinking enables a deep understanding of the science. This is the best possible basis for both research and professional practice in the geosciences. 56

Old Model

Seismic Biostratigraphy

Reservoir^ Engineering,

Geology

Past perception of the geoscience community to reservoir biostratigraphy: old model showing a lack of integration with broader geoscience.

New Model Seismic

Applied Biostratigraphy

Reservoir Engineering

Geology

Reservoir biostratigraphy as part of a fully integrated project: new model showing full interaction with other subsurfaces disciplines.

Figure 1

intuitive

polarity

exogenic fbiospheric f subI crustai , . CyC ?urficial " g S S , ecological » H endogenic environment e v o l u t l o n succession IIP counterintuitive

polarity Figure 2

The stratigraphical

tool

kit

Rock record Remote • sensing -

t o

Lithostra Igraphy A

Wire-line logging

o<n 1 Relative

zSO

chronology

H o LLi

Biostratigraphy Event stratigraphy —Cyclostratigraphy Chemostratigraphy Magnetostratigraphy Numerical dating Seismic stratigraphy •

Sequence stratigraphy Sedimentary

C/3 LU_j

So j=j

fades

Palaeoecology Palaeoclimate Tectonic history Figure 3

Earth history

Chronostratigraphy

REFERENCES Doyle, P. & Bennett, M.R. (Editors), 1997. Unlocking the stratigraphical record: advances in modern stratigraphy. John Wiley & Sons, New York. Hsu, K.J., 1997. A reform in earth science education after a revolution in earth science. Episodes 20(3): 151-157. McGowran, B., 1999. Geological time is deep time! SASTA JOURNAL 99/2:29-31. Payne, S.N.J., Ewen, D.F. & Bowman, M.J., 1999. The role and value of "high-impact biostratigraphy" in reservoir appraisal and development. In: Jones, R.W. & Simmons, M.D. (Editors), Biostratigraphy in production and development geology. Special Publ. No. 152, The Geological Society, London, pp 5-22.

THE RESOURCE AND RISK ASSESSMENT OF HYDROCARBON PLAYS IN AUSTRALIAN OIL AND GAS PRODUCING BASINS Rhodri Johns Santos Ltd, 91 King William Street, ADELAIDE SA 5000

Oil and Gas producing basins consist of more than one hydrocarbon play. A new play or play concept, even in an established hydrocarbon basin, may be regarded as a 'frontier' until significant commercial hydrocarbons are discovered. Typically, hydrocarbon-producing basins will exhibit several phases of growth as new plays are discovered, exploited and reach maturity. Prospects and fields in a hydrocarbon play will have similar geological characteristics in terms of their traps, their associated reservoir seal pairs and the hydrocarbon charge scenario. The largest fields are often discovered early and subsequent exploration efforts test prospects with geological characteristics perceived to be similar to the discovered fields. The decline in mean field size as the play matures can be useful in estimating undiscovered reserves and the potential of the remaining undrilled prospects. In contrast to established plays in a basin, new plays will have different and distinct trapping, reservoir, seal and hydrocarbon charge characteristics. These geological characteristics may make these new plays elusive as working hypotheses, technologies and skills utilised in exploring existing plays will not always be successful in the search for new plays. Factors which contribute to the success in exploring new plays include technical innovation in developing and testing the play concepts, the appropriate technology to address and reduce critical risks, a realistic assessment of the plays' potential, the persistence and entrepreneurism required for the timely capture of the opportunities and the resources to manage financial risk (exposure). Australian Basins display evidence of maturity in many of their established plays. The application of new technology may help to maintain success rates and lower the economic threshold so that the numerous smaller fields that probably exist in these mature plays can be exploited. However it is unlikely that large reserves will be added from these mature plays. New plays may provide significant upside but exploring them successfully will require intensive and innovative technical effort, the skilled application of technology and sound investment decisions which take into account the high technical and commercial risks.

STRUCTURAL CONFIGURATION AND PETROLEUM PLAY POTENTIAL OF THE NGALIA BASIN Paul Lipski Magellan Petroleum Australia Limited, Level 10,145 Eagle Street, Brisbane, QLD, 4051

The Ngalia Basin is located in the southern part of the Northern Territory, in central Australia. The basin is approximately 400 km in length in an east-west direction, by approximately 100 km at its widest point, in a north-south direction. The southern margin of the Ngalia Basin is located just over 100 km north of the northern margin of the much larger Amadeus Basin. For much of the basin's history, the Ngalia Basin was connected to with the Amadeus Basin. Deposition of sediments was continuous over both areas and many of the stratigraphic units can be correlated. Clastics, carbonates, and evaporites of Upper Proterozoic to Carboniferous age constitute the prospective sedimentary sequence in the Ngalia Basin. Petroleum exploration in the Ngalia Basin is in a juvenile stage. A relatively small amount of seismic data has been acquired and only two deep petroleum exploration wells have been drilled to date. Several shallow stratigraphic wells and mineral exploration holes have also been drilled. Considerable outcrop exposure has also been amenable to surface studies, particularly along the northern and western margins of the basin. The limited data indicate that the Ngalia Basin has the potential to host significant hydrocarbons, and that the basin is prospective for both gas and oil. In the deep central troughs, thick sequences of Upper Proterozoic and Lower Palaeozoic shales and evaporites are expected to be present. On the basis of limited geochemistry, shales in the central depocentres may be organically rich and may constitute mature hydrocarbon source. Burial history reconstructions and maturation modelling (Questa, 1989) suggest that the primary hydrocarbon migration phase took place during the Carboniferous Alice Springs Orogeny. This was the compressive phase that effectively gave the basin its present structural configuration. Most traps would have been present sufficiently early to capture generated hydrocarbons. Hydrocarbons generated earlier would migrate to older basement-controlled structures. At this stage, existing data suggest that the basin may be more gas prone than oil prone. The Davis-1 well, drilled in 1981 near the northern margin of the basin, flared a small amount of gas from a fractured shale. Subsequently acquired seismic data showed that the well did not test a valid structure at the depth of the gas show. Although the well did not penetrate any significant reservoir rocks, the hydrocarbon source potential was considered encouraging. The Newhaven-1 well, drilled in 1998, tested a large structure in the central southern part of the basin. The well did not penetrate any significant source or reservoir intervals, thus downgrading this part of the basin. Reservoir rocks, where observed in outcrop, have generally been poorly permeable. Results from limited subsurface drilling, however, have also suggested that reservoir quality is a concern in this basin. It should also be taken into account that the entire basin sequence is yet to be penetrated by exploration wells. The basin was technically active throughout much of its depositional history and anticlinal structures, both fault-independent and fault-dependent, appear to be common. Several prospects and leads have been identified on seismic data. All realistically require additional seismic to mature them to drillable status. Further exploration should also define additional targets of significant proportions. TECTONIC SETTING The Ngalia Basin is a remnant of a larger depositional province that once covered much of Central Australia in the Late Proterozoic and Early Palaeozoic. Throughout much of its depositional history, the Ngalia Basin formed part of an extensive sedimentary province that extended at least as far south as the Officer Basin, as far north as the McArthur Basin, to the Georgina Basin in the east and likely to the Canning Basin in the west. Failed arms of triple junctions penetrated deep into the interior and allowed ocean waters to readily encroach upon the existing craton. The Ngalia and associated basins were thus covered by shallow seas throughout much of their early stages. The Ngalia Basin is essentially deformed, asymmetrical, intracratonic depression which was formed in Precambrian time and infilled with Upper Proterozoic and Lower Palaeozoic clastics and carbonates. Regional aeromagnetic, gravity and seismic surveys demonstrate the presence of western and eastern depressions that contain thick sedimentary sections that are separated by a northerly trending basement arch. Later seismic control, although sparse, has further defined this "two lobe" configuration. 61

Deposition in the basin was interrupted intermittently by regional tectonic events throughout the Late Proterozoic and Early Palaeozoic. Most of these can be correlated with the well-documented tectonic events of the nearby Amadeus Basin. Multiple periods of compression and extension have resulted in complex structuring. The last and most intense event was the mainly Carboniferous Alice Springs Orogeny. This was a compressional event that deformed the basin into its present structural configuration and brought to an end significant sedimentation in the Ngalia Basin. Like the Amadeus Basin, the Ngalia Basin was considerably reduced in size through thrusting. The Alice Springs Orogeny was focused on the northern margin of the basin, where folding and faulting of sediments was most intense. In addition to the deformation of the northern flank, where basement was thrust southward over sedimentary rocks, the sedimentary sequence in the central part of the basin interior was deformed into a complex system of folds and faults, probably with associated salt tectonics. Most fold axes are doubly plunging and oriented in an east-west direction. Major faults are generally aligned parallel to the basin margins. The southern basin margin is much less deformed and is defined along most of its expanse by an unconformable contact between a thin section of sediments and the mainly crystalline rocks of the Arunta Block. The western margin is truncated by an overthrust. The eastern basin margin is poorly defined with a veneer of Cainozoic sediments covering the Ngalia Basin sequence. This margin appears to be fault controlled. Two major types of faults are recognized in the Ngalia Basin. The first consists of high angle, reverse faults, often with large throws. These have resulted from compressional reactivation of earlier normal, fault-bounded basement blocks. The second type consists of low angle thrusts and imbricate structures, often facilitated by decollement surfaces within evaporite zones. Uplift and erosion of the sediments to the north and south of the Ngalia Basin probably commenced before, and continued during, the deposition of the Carboniferous Mount Eclipse Sandstone. After the Alice Springs Orogeny, thick sedimentary intervals overlying the uplifted basement to the north and south were removed and crystalline basement was exposed. Outcrops of older Precambrian rocks now separate the Ngalia Basin from neighbouring sedimentary basins. REMAINING PLAY POTENTIAL The Ngalia Basin is very similar to the Amadeus Basin, both structurally and stratigraphically. There is hence a possibility that large fields similar to the Palm Valley gas field or Mereenie oil and gas field may be found in the Ngalia Basin. Previous interest in this basin has been based on this analogy. However, after several years of exploration, the following points should be taken into consideration: -Of the 30 exploration wells drilled thus far in the Amadeus Basin, there have been two commercial discoveries to date, giving a commercial success rate of less than 7%. It should be emphasized, however, that Mereenie and Palm Valley are large accumulations by onshore Australian standards. -The source of the oil and gas in the Mereenie and Palm Valley fields is the Ordovician Horn Valley Siltstone. No equivalent source rocks have yet been found in the Ngalia Basin. Hence, alternative source rocks must be postulated at this stage. -No significant intergranular porosity was recorded in either of the two deep exploration wells drilled to date. The wells have sampled most the known stratigraphic sequence of the Ngalia Basin. Significant fracture porosity, however, was noted in both wells. -Petroleum exploration in the Ngalia Basin is in an infant stage and hence its petroleum potential has only been touched upon. The basin is only sparsely explored, but is known to contain large structures. Grassroots exploration is still required in most areas. The basin requires a large amount of seismic acquisition and the drilling of many wells to confidently and competently evaluate the basin. The following summarises and describes the main play types identified thus far in the Ngalia Basin: -Large faulted anticlinal structures have been identified in the Newhaven and Mount Allan areas, associated with the Newhaven Fault Blocks. Some of these features involved low scale thrust faulting. Some display faultindependent closure. The structures have not undergone the intense deformation seen on the northern basin margin. The Newhaven-1 well tested the largest known feature in the western part of this province. Its lack of hydrocarbon shows and poor reservoir characteristics has downgraded this play in this area. Similar structures appear to be present to the east in the Mount Allen area. The sedimentary sequence is thicker there than in the vicinity of Newhaven-1. It is possible that there may be access to source rocks that were not present near Newhaven-1. Lower Palaeozoic source rocks in the Blood wood Trough in the northern part of the Mount Allan area have been buried to over 4,000 metres, the deepest they have been buried anywhere in the basin, and are likely to have reached peak hydrocarbon generation conditions during the Alice Springs Orogeny. Lack of stratigraphic control, and the fact that Palaeozoic source potential remains conceptual at this stage means that source still remains a substantial risk. The results from Newhaven-1 also emphasis the risk associated with reservoir, even away from the northern margin, where the basin is less tectonised. A substantial seismic program would be required to mature leads in this area to drillable prospect status.

-Numerous anticlinal features have been identified within the Walbiri Fold Zone in the north central basin area in front of the Yuendumu Thrust. The Walbiri Fold Zone is an anticlinorium, characterized by relatively tight folds that are displaced by thrusts and associated faults to form a series of anticlines and synclines. The folds are considered to be frontal with respect to the Mount Doreen Salient thrust sheet. Numerous anticlines have been identified through surface definition (eg. Walbiri Anticline, Beantree Anticline, Kerridy Anticline). Existing data suggest that this area could contain one of the thickest sequence of sediments in the basin (Bloodwood Syncline) and potential mature source rocks could be developed here. Most units of the known stratigraphic section should be expected throughout this area, except over the crests of some anticlines from which the Mount Eclipse Sandstone has been eroded. Limited seismic data indicate the presence of additional subsurface anticlines. The fact that reservoir objectives are not buried very deeply, are subject to faulting, and that they overlie a thick sediment pile, makes anticlinal structures in this area viable exploration targets. The Beantree Prospect is considered to be the primary target in this area. Any success at Beantree would necessitate the acquisition of additional seismic data to mature follow-up prospects. -Subthrust features beneath the Waite Creek and Davis Thrust Nappe in the northwestern part of the basin present a more challenging play. The western and northwestern basin margins were adjacent to the deep depression of the Naburula Trough prior to the Mount Eclipse Orogeny. Potential carbonate and clastic reservoirs on the western margins of the basin may have been in a situation to attract generated hydrocarbons from sediments within the trough. The subsequently introduced nappe complex should have provided the necessary sediment load to mature underlying Palaeozoic potential source rocks to a generative phase. In places, basement rocks may form part of the overthrust sheet. This play type is conceptual at this stage. The play has been tested along the northern margin of the Amadeus Basin without success to date. -Near to the southern basin margin, any trap along the northerly dipping Stanley Platform would provide a relatively shallow drilling target. A lack of stratigraphic control in this area means that any assessment of source and reservoir potential would be purely conjectural. There has always been a concern about accessibility to mature source in this area and the lack of shows in the Newhaven-1 well to the north has increased this risk. No surface anticlines have been identified along the platform to date and there is currently no seismic coverage. This play is considered to be conceptual at this time. REFERENCES Questa Australia Pty Ltd, 1989. Northern Territory Geological Survey Petroleum Basin Study - Ngalia Basin. Published report.

THE GEORGINA AND PEDIRKA BASINS REVISITED Greg Ambrose Department of Mines and Energy, Northern Territory Geological Survey Centrepoint Building Smith Street, Darwin, NT, 0800

The Northern Territory Geological Survey is two years into a Petroleum/Minerals exploration initiative whereby program results and products are being made available free of charge to explorers. The results presented herein derive from this initiative. GEORGINA BASIN The southern Georgina Basin covers an area of 250,000 square kilometres and includes a prospective Middle Cambrian petroleum system which to date has attracted only minor exploration. Only 750km of modern seismic has been acquired in addition to stratigraphic drilling undertaken by Government agencies and an eight well exploration programme undertaken by Pacific Oil and Gas during the last decade (Figure 1). Most, if not all of these wells were drilled outside structural closure but hydrocarbon shows, mainly in the Middle Cambrian, are abundant. The southern portion of the basin is dominated by two depocentres, namely the Dulcie and Toko synclines, which include up to 1200m and 5000m of Palaeozoic sediments respectively. The basin was deformed during the Alice Springs Orogeny (Late Devonian - Early Carboniferous) by minor to moderate folding and faulting especially in the south and east. Recent work by Pacific Oil and Gas has shown that mainly flat lying Ordovician sediments can conceal and disguise earlier Palaeozoic structuring viz. Delamerian Orogeny. The presence of common oil shows throughout much of the Cambrian in wells drilled in the Dulcie and Toko Synclines, in addition to a small gas flow from the Ordovician in Ethabuka #1, suggest considerable volumes of hydrocarbons were generated in the southern Georgina Basin. A Russian research group estimated, from pyrolysis data, that in excess of 40 billion tonnes of hydrocarbons has migrated from the Middle Cambrian. Oils extracted from Middle Cambrian sediments are mainly unaltered, mature, aromatic crudes of marine algal/bacterial source affinity (Questa Australia Pty Ltd, 1994). The NT Geological Survey has undertaken a review of the southern Georgina Basin incorporating previously unpublished E-log correlations, acquisition of new stratigraphic and regional aeromagnetic data, seismic and field mapping, basin/thermal history modelling and relogging of available core and palaeontological studies. The entire stratigraphic section, from the Neoproterozoic to Devonian, is under review but this paper concentrates on the hydrocarbon potential of the main petroleum system related to the Middle Cambrian Arthur Creek Formation and Thorntonia Limestone. Figure 1 is a Palaeozoic isopach map which also outlines the extent of maturation in this sequence. New E-log correlations from the southern portion of the basin have resulted in a simplification of the previous stratigraphic subdivisions as described in Questa Australia Pty Ltd (1994). Two regional electric log markers denote the base and top of the Middle Cambrian Arthur Creek Formation, and are regional sequence boundaries. The elucidation of these lithostratigraphic markers has greatly clarified the geology of the Middle Cambrian petroleum system. The basal E-log marker denotes a 'hot' carbonaceous shale/siltstone lying unconformably on altered carbonate grainstones of the Thorntonia Limestone. Vugs, fractures and stylolites in the latter result in fair reservoir quality in several wells. Source and seal is provided by the overlying and near ubiquitous basal Arthur Creek Fm 'hot shale' which reaches TOC's of up to 16% and is enriched in microbial source material. This unit was deposited by a rapid transgressive event marked by anaerobic sedimentation, and preservation of organic matter under reducing conditions. The sediments are oil mature over a wide area of the southern Georgina Basin. The overlying sequence comprises dark dolomitic siltstones and shales with some excellent source potential but poorly developed reservoir facies. Shallow water and more oxygenated conditions prevailed in the upper Arthur Creek carbonates and reservoir quality 'shoal' grainstones (KMllOmd), offer reservoir potential and possibilities for stratigraphic entrapment. There was considerable structural growth in the main depocentres during deposition of the Arthur Creek Formation until sedimentation was terminated by minor uplift, erosion and peneplanation prior to deposition of the Arrinthrunga Formation. This unit has a regional sheet like extent with occasional source and reservoir facies, but seal is problematical. Late Cambrian structuring (Delamerian Orogeny) variably eroded this sequence prior to deposition of the Ordovician Tomahawk Beds. The main target petroleum system relates to the Thorntonia Limestone/Arthur Creek Formation reservoir source couplet. Reservoir quality in the former is variable and has been affected by diagenetic and post diagenetic alteration processes, but DST results from several wells are encouraging particularly in Ross #1. The unconformably overlying Arthur Creek 'hot shale' is a regional seal and world class source rock and the main

challenges to a commercial discovery are migration and entrapment. It is suggested the Thorntonia Limestone is best targeted as a structural play and a number of leads have been identified. Relatively thin grainstone 'shoals' and sandstones in the upper Arthur Creek Formation present opportunities for stratigraphic entrapment. PEDIRKA BASIN A discussion of the Pedirka area encompasses four superimposed sedimentary basins viz. the Palaeozoic Amadeus Basin, and Permo - Carboniferous Pedirka Basin, the Triassic Simpson Desert Basin and the Jurassic/Cretaceous Eromanga Basin. This paper concentrates on the Pedirka/Simpson Desert/Eromanga Basin petroleum systems with emphasis on the Permian/Mesozoic source - reservoir couplet which is believed to be highly prospective. The exploration history of the northern Pedirka Basin dates back to the early 1960's when the emphasis was on the Early to Middle Palaeozoic Amadeus Basin sequence (McDills #1, Hale River #1). The discovery of Permian gas to the south in the Cooper Basin in 1963 turned attention to sequences of similar age in the Pedirka Basin (e.g. Colson #1). The 1977 discovery of Jurassic and Triassic oil in Poolowanna #1 focussed efforts towards younger Mesozoic reservoirs (Thomas #1, Etingimbra #1 and Poeppels Corner #1). There is uncertainty about the veracity of these traps and all wells in the area predate now traditional exploration philosophy associated with the Permian/Mesozoic source - reservoir couplet in the Cooper Basin. As a result the Northern Territory Department of Mines and Energy (NTDME) undertook a programme of seismic interpretation in the northern Pedirka/Eromanga Basin in 1998, with the aim of updating the exploration potential of the area. For the first time a regional structural synthesis is available for key seismic horizons at Mesozoic and Palaeozoic levels. Alexander et al (1996) reviewed the hydrocarbon potential of the western most depocentre, the Eringa Trough, concentrating on maturation history utilizing fission track analysis. This paper concentrates on the exploration potential of another important depocentre, the Madigan Trough (Figure 2), which has a unique structural configuration and to date has received little attention. The earliest sediments in the area are a sequence of Neoproterozoic to Late Devonian intra-cratonic sediments of the AmadeusAVarburton Basins, which occur extensively in the subsurface and onlap Mesoproterozoic gneiss, amphibolite, and granite of the Musgrave Block. The Pedirka Basin and its associated depocentres, the Eringa and Madigan Troughs, date back to the Alice Springs Orogeny (Late Devonian - Early Carboniferous). The Permo-Carboniferous record is dominated by widespread glaciation and basal diamictites (Crown Point Formation) which are usually disconformably overlain by intracratonic sediments of the Early Permian Purni Formation. Triassic sedimentation was preceded by compressional reactivation of older fault systems, which deformed and eroded Pedirka Basin sediments, particularly along the McDills Trend. A regional southeasterly tilt was then imposed accommodating Triassic sedimentation in the Poolowanna Trough, the main depocentre of the Simpson Basin, where 300m of Triassic sediments are preserved. The basal unit, the Walkandi Formation, comprises continental shale, siltstone and sandstone and is probably the equivalent of the Nappamerri Group in the Cooper Basin. Unconformably overlying sediments of the Late Triassic Peera Peera Formation comprise shale, coal and sandstone. Uplift and erosion in the Late Triassic preceded deposition of the Eromanga Basin sequence. Regionally this sequence comprises laterally continuous sheet sandstones of fluviatile origin (Hutton Sandstone, Adori Sandstone, Namur/Hooray Sandstone) with intervening overbank and lacustrine - swamp deposits viz Poolowanna Formation, Birkhead Formation, Westbourne Formation and the Murta Member of the Hooray Sandstone. These pervasive shaley units provide source and seal to varying degrees throughout the Eromanga Basin, but only the Poolowanna and Birkhead Formation occur in the Pedirka area and then intermittently. The onset of full marine conditions during the Early Cretaceous is represented by the Wallumbilla/Toolebuc/Allaru/Mackunda sequence. In the Late Cretaceous non-marine conditions prevailed and the Winton Formation was deposited in a fluvial-floodplain environment. It was during the Winton Fm sediment loading that most hydrocarbon generation is presumed to have occurred. The hydrocarbon potential of the Permian/Mesozoic sequence is described in part by Alexander et al (1996). The Permian Crown Point is generally considered a poor source rock while the Purni Formation is a fair to good source containing type II/III kerogen. The Poolowanna Formation contains some of the richest source rocks in the area and coal seams are common and compliment the often abundant dispersed organic matter present in intraformational siltstones and shales. Similar source facies are recorded in the Triassic Peera Peera Fm which is also a viable source rock. On the eastern flank of the Eringa Trough coals within the Birkhead Formation are oil prone, being enriched in type II/III kerogen, but their extent into the Eringa Trough is uncertain, as is their maturity.

The Permian Purni Formation is oil mature in the northern Eringa and Madigan Troughs and also on the eastern basin margin. The Triassic and basal Jurassic sequences are oil mature in the Poolowanna Trough and perhaps also in the northern Eringa Trough and the main depocentre of the Madigan Trough (Figure 2). The petroleum systems operating in the Pedirka area comprise the basal Jurassic/Peera Peera (Triassic) petroleum system and the Permian (dominantly Purni Formation) petroleum system. The latter correlates well with the oil prone lower Patchawarra Formation in the Cooper Basin, which has charged fields such as Tirrawarra, Fly Lake and Moorari, where the Early Permian Tirrawarra Sandstone provides the target reservoir. However to date the only proven petroleum system in the Pedirka area is that relating to the Poolowanna Fm (Basal Jurassic)/Peera Peera Fm (Triassic) as evidenced by significant oil recoveries in the Poolowanna #1 discovery well. Geological and geochemical criteria, including maturity data, clearly indicate intra Poolowanna and Triassic sources (Alexander et al, 1996). Poor reservoir quality in the Poolowanna Trough hindered flow rates and oil volumes are small. Poor to fair oil shows occur in the Poolowanna Fm, and to a lesser degree the Peera Peera Fm in the Colson #1, Thomas #1, Erabena #1, Poeppels Corner #1, Killumni #1, Oolarinna #1 and Walkandi #1 exploration wells. At this level in the Cooper/Eromanga area there are also widely scattered oil shows but a dearth of commercial hydrocarbons with the exception of the Cuttapirrie and Gidgealpa fields in SA and also fields such as Black Stump, Bodalla South and Kenmore in Queensland. The bulk of Poolowanna reservoired oil in these areas is believed to be of Permian origin (Boreham and Summons, 1999). To date the potential for Poolowanna oil in the Pedirka area appears limited by source volume and maturation history and the fact that migration probably post dated diagenisis in the Poolowanna Trough which is the main source "kitchen". These factors militate against large commercial oil fields at this level but the likelihood of small, scattered accumulations is high. Maturation levels in the Poolowanna Trough reach Ro = 1.0 and generation was probably initiated at about Ro = 0.6. The intensity and significance of oil shows decreases westwards away from the Poolowanna Trough. The other Poolowanna Fm depocentres, the Madigan and Eringa Troughs appear, from regional comparisons, to have some potential for commercial hydrocarbons. Overall it is likely at least small volumes of Poolowanna oil have been generated but there are no adjacent wells and little seismic. A synthesis of new seismic mapping data over the NT sector of the Pedirka Basin suggests the Permian petroleum system is highly prospective and subordinates the previously favoured Poolowanna/ Peera Peera system. The Permian occurs in a number of contiguous depocentres having separate maturation histories. On the eastern margin of the Permian basin the sequence is thin but well within the oil window as predicated by pronounced tilt of the basin to the southeast during the Triassic. This is evidenced in Oolarinna #1 where the base Permian is oil mature (Ro = 1.0) and gas shows of up to 80 units recorded in Purni Formation coals indicate the onset of gas generation. Importantly, in this area of known mature Permian source rocks, there has not been a crestal structural test at Permian or Jurassic levels. The same is true in the northern Eringa Trough where the Purni is thick and is in the oil window. Hanging wall fault traps against the McDills Fault are also viable targets as is the Hooray Prospect immediately to the east. The other important Permian depocentre, the Madigan Trough, provides the best potential for Permian oil generation. Interpretation of early analog seismic indicates about 1500m of Permian sediments, including 750m of Purni Formation, which is buried to about 2800m with an expected maturity of Ro = 0.7 - 1.0, well into the peak oil generation window. As a result of these interpretations, prime targets within the NT sector of the Pedirka Basin are now viewed to be structures within the central Madigan Trough or first order structural traps on primary migration pathways out of this depocentre (Figure 2). A mitigating factor is the perceived absence of gas charge and associated displacement of oil to the basin margins. Limited oil migration dictates that the most proximal structures be tested at their crest, recognising that there has not been a valid structural test within 60km of this depocentre. Fortunately there are a number of suitably 'old' closures and structural noses encircling this source 'kitchen', none of which have been drilled (eg. the Simpson and Hooray Prospects). Further to the north the McDills Trend intersects the Hale River Fault zone which comprises a series of northwest trending, down to basin normal faults. A number of structural leads result including the Arrakis lead which is favourably located to trap hydrocarbons migrating northwards from the Madigan Trough. Overall in this area, and in the NT portion of the Pedirka Basin as a whole, there is a proliferation of exciting undrilled four way dip closures which should take precedence at this stage of the basin's exploration history. Available seismic also indicates a plethora of stratigraphic and fault dependant trapping mechanisms but prospect definition awaits further seismic. REFERENCES

Alexander, E.M., Pegum, D., Tingate, P., Staples, C., Michaelsen, B.H. and McKirdy, P.M. 1996.M., 1996. Petroleum Potential of the Eringa Trough in SA and the NT. The APPEA Journal 36(1), 322 - 348.

Boreham, C.J. and Summons, R.E. 1999. New Insights into the Active Petroleum Systems in the Cooper and Eromanga Basins, Australia The APPEA Journal 39 (1), 263 - 296. Questa Australia Pty Ltd (1994). Northern Territory Geological Survey Petroleum Basin Study - Georgina Basin, 203.

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BASIN-CENTRED GAS ACCUMULATIONS: A NEW GEOLOGICAL PARADIGM Richard Hillis National Centre for Petroleum Geology and Geophysics, University of Adelaide, Adelaide SA 5005

In considering the exploration for and development of low permeability gas, it is critical to determine whether the accumulation is of the conventional or basin-centred type. Basin-centred gas accumulations present a different paradigm from standard trapping mechanisms associated with the conventional hydrocarbon system. Basin-centred gas may lie downdip from water with no conventional impermeable barrier between. Accumulations are not necessarily constrained either by structural or stratigraphic closure. In the Elmworth Field of western Canada, the entire Mesozoic section from approximately 1 to 3 km depth contains gas in every stringer of reservoir rock. Basin-centred gas accumulations may be indicated by a regional increase in resistivity in electric log data from the basin flanks to the basin-centre. Subsequent testing may reveal continuous gas saturation and the absence of a water leg. Basin-centred gas reservoirs of the type first recognised in western Canada may occur in the trough areas of the Cooper Basin. If basin-centred gas accumulations are recognised, exploration need not be solely concerned with conventional traps, because below a critical pressure seal the entire basin is gas saturated. The nature of the sealing characteristics of this boundary are debated but may relate to low permeability units being permeable to singlephase flow and impermeable to multi-phase flow during hydrocarbon generation and primary migration. In the basins of the western United States 80% of cumulative gas production in these basins comes from within 600 m beneath the pressure seal. If electric log and testing data support the possible occurrence of basin-centred gas, it is necessary to delineate the regional pressure seal beneath which the basin is gas saturated. This involves detailed analysis of undercompacted zones from velocity data (sonic log and seismic processing) and must be undertaken with particular care in basins such as the Cooper Basin in which overcompaction due to uplift can mask overpressurerelated undercompaction. Having recognised, and in so far as possible mapped the extent of the regional pressure seal, the key to the successful exploitation of basin-centred gas lies in the recognition of natural sweetspots (structural, sedimentological or diagenetic) beneath the regional pressure seal. For example, shoreline/barrier bar sands have been particularly important in providing commercial flows of basin-centred gas in western North America. Ironically, such sweetspots may not be tight' per se, but their identification, outside of structural closure in basin-centred gas accumulations, requires the understanding and application of a new geological paradigm. Engineering approaches such as horizontal drilling and fracture stimulation are critical to the exploitation of both conventional and basin-centred tight gas resources. Furthermore, low permeability tight gas reservoirs are particularly prone to formation damage which should be minimised. However, engineering approaches are best applied to the optimum geological environment (ie. sweetspots), and may not be able to deliver commercial production in unfavourable geological environments.

GAS HYDRATES IN AUSTRALIA'S MARINE JURISDICTION: A POTENTIAL LONG-TERM RESOURCE? H.M.J. Stagg , P.A. Svmonds . N.F. Exon , J-M. Auzende , G.R. Dickens & S. Van de Beuque Australian Geological Survey Organisation, Canberra, ACT IFREMER, DRO/GM, c/- ORSTOM BP n°A5, Noumea, Nouvelle-Caledonie, France School of Earth Sciences, James Cook University, Townsville, QLD 4811 IFREMER, c/- Australian Geological Survey Organisation, Canberra, ACT 1

GAS HYDRATES Clathrate hydrates of gas, commonly referred to as gas hydrates, are ice-like crystalline solids formed from mixtures of water and gas. It is widely recognised that gas hydrate deposits exist in polar continental regions and beneath continental margins and it has been estimated that the mass of carbon as CH in the global gas hydrate reservoir is an amount about twice that for carbon in all known oil, coal and natural gas reserves (Kvenvolden, 1993; Gornitz & Fung, 1994). 4

Gas hydrates occur in sediments and sedimentary rocks where temperatures are low, but pressures and methane concentrations are high. These conditions can occur beneath the deeper parts of continental margins and oceanic plateaus, when a suitable source is present. The lower boundary of a methane hydrate deposit is located at the intersection of the geotherm and a methane-methane hydrate-pore water equilibrium curve (see fig. 1 in Exon et al., 1998). Gas hydrate deposits are typically underlain by sediment containing significant quantities of free methane gas, which consequently has relatively low acoustic velocity, and this boundary can produce a strong seismic reflection. As the depth of the boundary is controlled by the sub-seabed pressure and temperature regime, its reflection tends to parallel the seabed, regardless of the geometry of reflections produced by sedimentary strata. For this reason, a 'bottom-simulating reflector' (or BSR) is now considered to be compelling evidence for the presence of gas hydrates and underlying free gas. BSRs are most readily identified where the associated sedimentary strata are dipping or folded and where the BSR consequently cuts across reflections from these strata. Sediments above and through a BSR have been sampled in several locations around the world by the Ocean Drilling Program, and in each case, gas hydrates and associated free gas bubbles have been found. While it is generally considered that gas is probably supplied to most gas hydrate deposits through the upward recycling of bacterially generated methane over long periods of time, thermogenic gas has been identified in some deposits. If gas hydrates are proven to coincide with BSRs in the Australian region, and if analysis of the molecular and carbon isotope composition shows that gas to be thermogenic, then this will provide an important boost to exploration for conventional hydrocarbons in some of Australia's frontier exploration provinces. Until recently, potential gas hydrates had not been identified within Australia's marine jurisdiction. However, recent work on the northern Lord Howe Rise (Exon et al. (1998) pointed to strong evidence for their existence in this region and has increased awareness of their possible existence elsewhere around Australia. We have now identified prominent BSRs in three areas of Australian jurisdiction - Lord Howe Rise, South Tasman Rise / L'Atalante Depression, and Labuan Basin (Fig. 1) - based on seismic data that were acquired by the Australian Geological Survey Organisation's (AGSO's) Law of the Sea project. INTERPRETED GAS HYDRATES IN AUSTRALIAN WATERS Lord Howe Rise Lord Howe Rise is a foundered continental fragment that detached from eastern Australia during the formation of the Tasman Sea in the mid Cretaceous to Early Eocene. The rise extends for about 2000 km from northwest of New Zealand to west of New Caledonia and now lies at water depths generally deeper than 1000 m. It is flanked by the New Caledonia Basin to the east, and by the Middleton and Lord Howe Basins, Dampier Ridge and Tasman Basin to the west. BSRs have been identified at four locations on the rise - the initial location in the northeast, where it descends into the Fairway Basin (Fig. 2); in the west, where it descends into the Middleton Basin; on the crest above a half-graben; and in the south, in the Monawai Basin (Symonds et al., 1999). BSRs in the Fairway Basin were first identified in seismic profiles acquired jointly by AGSO and IFREMER across the Australia-France boundary between New Caledonia and Lord Howe and Norfolk Islands (Exon et al., 1998), and are the subject of intensive recent research, including the cooperative French-Australian ZoneCo 5 swath-mapping and seabed coring survey undertaken in late 1999. The depth of the BSR is about 600 mbsf, which Exon et al. (1998) concluded was close to the intersection of the geotherm and the methane-hydrateseawater equilibrium curve.

Recently acquired satellite synthetic aperture radar (SAR) imagery also contains some evidence of low-level oil slicks and films that are approximately coincident with the BSRs in the Fairway Basin and on the flank of the Middleton Basin (Symonds et al. 1999). Some of the SAR anomalies are associated with seismic evidence for fluid migration. Together, these data provide further evidence for hydrocarbon generation and active migration to the seafloor. South Tasman Rise The South Tasman Rise (STR) is a large and technically complex continental fragment, some 200,000 km in area, which assumed its present configuration during the later stages of the rifting of Australia and Antarctica, in the Palaeogene. The STR is flanked by the oceanic crust of the Australian-Antarctic basin to the west and the southern Tasman Basin to the east. 2

BSRs are evident on a number of the seismic lines, in water depths of 2500-4700 m. They are particularly prominent in isolated sediment depressions within the basement of the STR, where the cross-cutting reflection character is very strong, and beneath the L'Atalante Depression, which separates the STR from the East Tasman Plateau (Fig. 3). The rugged basement topography on the STR has probably introduced strong perturbations in the geotherm and, in turn, this appears to have had a strong effect on the geometry of the BSR with it appearing to crop out in some locations. A rather puzzling aspect of the BSR in the L'Atalante Depression is a second, fainter BSR, some -0.2 s deeper in the section than the prominent BSR (Fig. 3). This second BSR does not appear to be a processing artefact, and we speculate that it may be the diagenetic imprint of a 'fossil' BSR. Labuan Basin (Kerguelen Plateau) The Kerguelen Plateau, in the south-central Indian Ocean, is the world's largest mid-ocean plateau and extends for more than 2000 km north-northwestwards from the Antarctic margin. Despite two Ocean Drilling Program legs, the origins of the plateau are still uncertain, and it is currently considered to be an amalgam of both continental and oceanic components. The majority of the plateau falls within the Australian Exclusive Economic Zone and associated extended Continental Shelf. To the northeast, the plateau is flanked by the deep basement of the Labuan Basin, which is interpreted to have formed during the rifting of Kerguelen Plateau and Broken Ridge. The Labuan Basin contains -3 s TWT (ca 4-5 km) of sediment which has never been sampled. Figure 4 shows a BSR recently identified within the Labuan Basin. This BSR occurs as much as 0.7 s TWT (-800 m) bsf and is prominent over a distance of about 120 km due to its strong discordance with the associated strata. Seismic data are very sparse in the basin, and to date the BSR has only been identified on one line. CONCLUSIONS The identification of BSRs for the first time in Australia's marine jurisdiction is significant for an assessment of Australia's long-term, frontier hydrocarbon resources. As there are currently no techniques available by which methane can be commercially extracted from gas hydrates in the deep ocean, they are only a potential resource at this stage. In the shorter term, it is important that the source of these interpreted deposits - biogenic or thermogenic - be determined, and that their relevance to the conventional hydrocarbon resource potential of these frontier areas be assessed. In the event that they are of thermogenic origin, particularly in the Fairway Basin, then the conventional hydrocarbon prospectivity of the Lord Howe Rise region is substantially upgraded. REFERENCES Exon, N,F., Dickens, G.R., Auzende, J-M., Lafoy Y., Symonds, P.A. & Van de Beuque, S., 1998. Gas hydrates and free gas on the Lord Howe Rise. PES A Journal, 26,148-58. Gornitz, V. & Fung, I., 1994. Potential distribution of methane hydrates in the world's oceans. Global Biogeochemical Cycles, 8, 335-347. Kvenvolden, K.A., 1993. Gas hydrates - geological perspective and global change. American Geophysical Union Reviews of Geophysics, 31 (2), 173-187. Symonds, P.A., Stagg, H.M.J., Pecher, I., Exon, N.F., Van de Beuque, S., Borissova, I & Auzende J-M., 1999. Potential unconventional gas resources in the Lord Howe Rise region. In Queensland 1999 Exploration and Development, PESA (Qld) Petroleum Symposium, 23-27.

Figure 1: Australia's marine jurisdiction, showing areas where bottom-simulating reflectors (BSRs) have been identified: 1 - northern Lord Howe Rise; 2 - L'Atalante Depression, adjacent to the South Tasman Rise; 3 (inset) - Labuan Basin, adjacent to the Kerguelen Plateau.

Figure 2: Portion of AGSO seismic line 206-3 showing a BSR (arrow) in the Fairway Basin on the northeastern flank of Lord Howe Rise, Vertical scale in seconds of two-way time. Horizontal tick marks are every 3.75 km.

Figure 3: Portion of AGSO seismic line 202-12 showing a BSR (arrow) in the L'Atalante Depression, adjacent to the eastern flank of the South Tasman Rise. Vertical and horizontal scales as for Figure 3.

Figure 4: Portion of AGSO seismic line 179-7 showing a BSR (arrow) in the Labuan Basin, adjacent to the eastern flank of the Kerguelen Plateau. Vertical scale in seconds of two-way time. Horizontal tick marks every 10 km. 72

THE GREATER AMADEUS BASIN, NORTHERN TERRITORY, AUSTRALIA. Jamie M. Burgess Department of Mines and Energy, Northern Territory Geological Survey Centrepoint Building Smith Street, Darwin, NT, 0800

The Amadeus Basin is approximately 170,000 square kilometres in aerial extent in the southern Northern Territory (Figure 1). This basin is at the heart of a series of intracratonic basins on the Australian continent that share their origins in the break up of the supercontinent Rodinia (~lGa). Strong stratigraphic ties have been made between these basins, which include the Officer, Ngalia and Georgina Basins, leading to them being referred to collectively in later years as the Centralian Superbasin (Walter et al., 1995). Since the discovery of hydrocarbons in the 1960's, the Amadeus Basin has intermittently been the focus of oil industry activity culminating in the development of the Mereenie and Palm Valley Fields in the mid-1980's. It has more recently drawn the attention of mineral explorers seeking to find comparison with the gold deposits of the Witswatersrand Basin of South Africa. Mapping by geologists of the NTGS in the Petermann Ranges area on the southwestern margin of the presentday Amadeus Basin, has confirmed the presence of bimodal volcanics and sediments that represent the onset of rifting and basin formation. The Amadeus basin succession begins with sheet-like, tidally influenced deposition of the Heavitree Quartzite. Increase in accommodation space led to the deposition of the thick shallow-marine anoxic rocks of the Bitter Springs Formation. The Bitter Springs Formation contains variable volumes of basal evaporites and salt that form the foundation for diapiric structures observed throughout the Amadeus Basin. A basin-wide hiatus at the top of the Bitter Springs Formation coincided with structural evolution in the basin in which tectono-sedimentary regimes, comprising several sub-basins and a prominent central ridge, were established. This hiatus was succeeded by deposition of a sequence of glacial and interglacial deposits including representatives of the Sturtian (Areyonga Formation) and Marinoan (Olympic Formation) Glaciations. Intervening environments of deposition included periods of anoxia suitable for the preservation of organic matter (both Areyonga and interglacial Aralka Formations). Deposition through the latest Neoproterozoic Ediacaran period is predominated by marine-influenced clastics and carbonates of the Pertatataka, Winnall and Julie Formations among others. Movement associated with the Petermann Ranges Orogeny (~580-520Ma) rearranged basin palaeogeography and further localised sedimentation, introducing foreland basin-style sedimentation to the southwest of the basin and the extensive fluvial tongues of the Arumbera Sandstone to the north and east. Whilst clastics continued to be deposited in the south and west, the succeeding Cambrian succession in the north and east is dominated by marine and marginal marine deposition of dolomite and evaporitic mudstone incorporating organic rich facies in the Chandler and Giles Creek Formations. Relatively restricted sedimentation of clastic sequences in the Ordovician of the Amadeus Basin include the fluvial Pacoota Sandstone, predominantly siltstone with lesser black shale and carbonate of the shallow marine Horn Valley Siltstone and tidally-influenced Stairway Sandstone. The Alice Springs Orogeny (~400-300Ma) is represented in the east and across the northern margin of the Amadeus Basin by pronounced foreland basin-style sedimentation including fluvial and lacustrine lithofacies of the Pertnjara Group. Exploration began in the Amadeus Basin in the 1950's with a period of reconnaissance work by the then BMR. Since the discovery of the Mereenie Oil and Gas Field in early 1964 and subsequent Palm Valley Gas Field discovery in 1965, both in the Pacoota-HornValley-Stairway sequence, exploration and scientific study in the basin has largely focused on the Ordovican petroleum system in the northern and eastern part of the basin (Korsch and Kennard, 1991). However, with only 5 wells located away from the central ridge to the south and west and most recent data in some of these areas dating back to the 1960's, the greater Amadeus Basin must therefore be considered a "greenfields" area for petroleum exploration and thus worthy of qualification as a frontier basin. Good results have been observed indicating a number of active but yet poorly defined older petroleum systems in the Amadeus Basin. The yet uneconomic Dingo gas field is located 80km south of Alice Springs, is relatively little tested and has proven and probable reserves of 25 BCF. Dingo-1 was drilled in 1981 and tested 1.5 MMCFGD from the Neoproterozoic Arumbera Sandstone. The very first petroleum exploration well drilled in the Amadeus Basin (Ooraminna-1 by Exoil in 1963) encountered a small gas flow of 0.12 MMCFGD from the

Sturtian Areyonga Formation. Drilled in 1992, Magee-1 became the first (and still the only) hole in the Amadeus Basin to be drilled into the Heavitree Quartzite and it showed gas from this unit which flowed 63.1 MSCFGD in an open hole test. These results may be combined with those from correlative successions in the Centralian Superbasin to indicate yet more likely Amadeus Basin petroleum systems. Potential exists for development of Cambrian source rocks in the eastern Amadeus Basin like those of the Arthur Creek Formation in the southern Georgina Basin (Figure 1). Significant potential also exists for oil and gas occurrence similar to that observed in the Neoproterozoic (Adelaidean) of the Officer Basin of South and Western Australia. Because of the limited volume of thermal maturity data and restricted aerial extent of other data, the history of thermal regimes acting throughout the basin is not well understood. Similarly, in the more data intense areas, existing thermal and burial history models (Jackson et al., 1984) are significantly out of date and do not give a great appreciation of the evolution of hydrocarbons in this basin. Recently acquired maturity data at Wallara-1 in the centre of the basin, indicating that source rocks of the Neoproterozoic Aralka Formation are overmature for the generation of hydrocarbons, confirm that models of thermal maturity simply increasing towards the northern margin of the basin are inaccurate. A program of acquisition of modern aeromagnetic geophysics over the western and southern Amadeus Basin by the Northern Territory Geological Survey is underway (Figure 2). It is expected that the application of frontier techniques will supplement the outdated data available to explorers in these areas. There are numerous untested structures and play types throughout the basin, the gas show from the once tested Heavitree Quartzite at Magee-1 a glaring example. The existence of salt diapirs in the south and western regions of the basin is known only from the 1960's vintage mapping. Furthermore, oil shows in both the Horn Valley Siltstone and Bitter Springs Formation at Mt Winter-1 highlight the existence of good source rocks at generating maturities in an area once thought to be devoid of source rocks. Ongoing investigations in this and other basins by the Northern Territory Geological Survey are the result of a Minerals and Petroleum Exploration Initiative whereby program results and products are being made available free of charge to explorers. The results herein derive from this initiative. REFERENCES Korsch, R.J. and Kennard, J.M., (Compilers) 1991. Geological and geophysical studies in the Amadeus Basin central Australia. Bureau of Minerals Resources, Bulletin 236. Walter, M.R., Veever, J.J., Calver, C.R. and Grey, K., 1995. Neoproterozoic stratigraphy of the Centralian Superbasin, Australia. Precambrian Research, 73, 173-195. Jackson, K.S., McKirdy, D.M. and Deckelman, J.A. 1984. Hydrocarbon generation in the Amadeus Basin, Central Australia. APEA Journal, 24, 42-65.

SOUTHERNj &mmiUA \ BASIN !

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Figure 1.

Location of the Amadeus Basin

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SOUTH AUSTRALIA Amadeus West (1999) Airborne Survey Proposed Amadeus South 2000 Airborne Survey

Figure 2.

Well locations and modern NTGS geophysical surveys over the Amadeus Basin 75

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HYDROCARBONS OF THE WESTERN AUSTRALIAN OFFICER BASIN Greg M. Carlsen Project Manager, Petroleum Initiatives Team Geological Survey of Western Australia 100 Plain Street, E. Perth WA 6004 g.carlsen @ dme.wa.gov.au

EXTENDED ABSTRACT Hydrocarbons have been found in eleven wells within the Western Australian parts of the Neoproterozoic Officer Basin (Table 1, Fig.l). The most recent find was a gas show in the Geological Survey of Western Australia's (GSWA) stratigraphic test Vines 1. Hydrocarbons have previously been found in the form of gas, live oil, bitumen, oil fluorescence and oil stains in cores and cuttings. Three of the hydrocarbon shows were recorded in mineral exploration wells outside of seismic control. An additional three shows were recorded in stratigraphic tests outside of seismic control. Some wells drilled in the Officer Basin did not have gas detection systems and therefore additional gas shows may have gone unrecorded. Some of the shows are in cored intervals. Most of the hydrocarbon shows were found near the margins of the basin and occur in a variety of structural and stratigraphic settings indicating widespread hydrocarbon generation and migration. U^ ' 120-00'

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FIGURE 1. Wells with hydrocarbon shows in the Western Australian Officer Basin.

Table 1. Wells with hydrocarbon shows in the Western Australian Officer Basin. Well completion reports for all wells not listed as mineral bore holes are located at the Department of Minerals and Energy Western Australia (DME) and are referenced through the WAPEX data base, S-Series. Results for mineral bore holes are located at the DME and are referenced through the WAMEX data base, M-Series. Well Name Year Hydrocarbon shows Operator Browne 1 1962 gas cut mud and good fluorescent cuts in well cuttings, no gas Hunt Oil detection system used Browne 2 1962 gas cut mud and good fluorescent cuts in well cuttings, no gas Hunt Oil detection system used NJD 1, extensive bitumen filled veins and bleeding oil 1981 Western mineral bore Mining Corp. Kanpa 1A 1983 fluorescence and brown oil stains in sandstones and dolomites Shell Dragoon 1 1982 mud gas shows with methane values up to 1 % and other Eagle Corp. hydrocarbon gases up to pentane present Hussar 1 1982 impsonitic and thucholitic bitumen. Eagle Corp. LDDH 1, 1993 bitumen in fractures. Geochemical analysis confirmed this oil Normandy show (Ghori, 1998) mineral bore Exp.Ltd. OD 23, 1996 bitumen in fractures, live oil in vugs and fractures. Jubilee Geochemical evaluation confirmed this oil show. mineral bore Gold Mines Boondawari 1 1997 Fluorescence in core confirmed by geochemical analysis. Amadeus Petroleum 1997 Fluorescence in core confirmed by geochemical analysis. Mundadjini 1 Amadeus Petroleum gas peaks equivalent to 10% methane in air. There was no Vines 1 GSWA 1999 chromatograph on this drillhole. Excellent oil source rocks have been found in NJD 1 on the Westwood Shelf. Additional oil source rocks with fair oil-generating potential have been identified in the Browne and Hussar Formations (Fig.2) in Yowalga 3 and Kanpa 1A in the Yowalga area. Within the northwestern Gibson area, Neoproterozoic oil source rocks have been identified in the mineral exploration drillhole LDDH 1 (Ghori, 1998).

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FIGURE 2. Stratigraphy and petroleum systems of the Officer Basin, Western Australia 77

On the Westwood Shelf, Neoproterozoic rocks are marginally to fully mature for oil generation. In the thick succession of the Yowalga area, maturity ranges from immature to overmature for different Neoproterozoic formations, depending on maximum burial depth. The highest maturity was observed in the northeastern Gibson area at Dragoon 1, where more than 2500 m of section has been removed during compressional and halokinetic uplift. Along the southern margin of the Gibson area the Neoproterozoic section is partly within the oilgenerative window, whereas in the northwestern part of the sub-basin it is mature to overmature (Ghori, 1998). Modelling indicates that the main phases of oil generation from the Neoproterozoic formations occurred during the latest Neoproterozoic, Cambrian, and Permo-Triassic. These phases occurred at different stratigraphic intervals in different parts of the basin (Ghori, 1998). The available geochemical dataset is insufficient to identify source rocks to account for all of the gas, oil and bitumen shows in the western Officer Basin (Ghori, 1998). The Geological Survey of Western Australia has an ongoing program of field studies, stratigraphic coring and geochemical analysis to further define the organic facies and depositional position of source rocks of the Officer Basin. No samples have been collected that could be analysed for biomarkers, however all of the source rock analyses indicate that the hydrocarbons are sourced from Neoproterozoic cyanobacteria. All analysed source rocks of the Officer Basin with TOC's greater than 0.5%, where mature for hydrocarbon generation today, are in very thin laminations. Thicker intervals of source rocks located to date are presently in the gas generation window. Source rock depositional models for the Officer Basin, based on benthic, photic cyanobacteria as the principal source or organic carbon, explain the predominance of hydrocarbon shows along the margins of the basin and provide a firm basis for further exploration (Carlsen et al, 1999). Additional stratigraphic drilling to locate thick source rocks in the oil generation window is planned by the Geological Survey of Western Australia. Lateral migration paths for hydrocarbons generated in the Officer Basin are provided by source rock-reservoir couplets in all of the formations with identified source rock potential. Additional lateral migration pathways are provided by facies variations. Vertical migration pathways are compartmentalised by regional seals in the Browne, Hussar, Kanpa and Steptoe Formations. Along various local structural trends, migration between compartments has been provided by regional unconformities which downcut into most formations. Additional vertical migration pathways are provided by regional and local scale faults that in the Officer Basin have a complex history of tensional and compressional strain. Potential hydrocarbon-related diagenetic zones (HRDZs) and vertical hydrocarbon plumes have been suggested from visual inspection of Officer Basin seismic data. These seismic expressions of hydrocarbon migration have not been investigated using modern processing and modelling techniques. Until live hydrocarbon pools are found little more can be said of the potential migration pathways in the Officer Basin. A wide variety of traps remain poorly tested or untested in the Officer Basin. The GSWA has identified all of the following trap styles: normal faults, thrust faults, thrust ramp folds, compressive folds, drape folds, lateral salt seals, unconformity truncations, pinchouts, lateral facies changes, erosive channels and valleys and unconventional reservoirs such as fractured carbonates (Apak and Moors, 2000). Structural closure ranges from very large four-way dip to complex fault blocks with multiple fault intersections. Stratigraphic traps range from regional facies variations onto the southern ramp margin of the basin to rapid local variations in a number of nearshore mixed clastic and carbonate environments. The Officer Basin in Western Australia contains at least five distinct structural zones. A northeastern margin basement overthrust, a northeastern salt-ruptured zone including the Browne and Yowalga structural trends, a central thrusted zone including the Lungkarta and Kanpa structural trends, a western platform tested by Empress 1/1A and NJD 1 and a complex salt dominated region typified by possible Gulf of Mexico analogue mini-basins. The Waigen area has no seismic data and the single stratigraphic test in this area, Vines 1, did not provide a complete penetration of the Neoproterozoic section. Perincek (1998) identified at least 9 structural episodes affecting the Officer Basin. As various structural units and various potential source intervals of the basin can be demonstrated to have subsided and matured at different times, individual traps will need to be assessed as to their own access to potential charge. GSWA basin analysis and petroleum system studies indicate that very good access to maturing source rocks exists for many potential traps. A wide variety of play styles as described previously remain untested within the basin. All of the physical and temporal elements of an effective petroleum system have been proven for the basin. What remains to be achieved is a correctly placed exploration borehole based on a modern understanding of this Neoproterozoic basin. Much of the basin is not currently under licence and the two exploration companies currently holding permits and applications in the basin are actively seeking venture partners.

REFERENCES

Apak, S.N. and Moors, H.T., 2000, A sequence stratigraphic model of Neoproterozoic strata, Yowalga area, Officer Basin, Western Australia. The APPEA Journal 40 (1), p. 15-25. Busbridge, M., 1993, Lake Disappointment, summary of lithological and analytical data for diamond drillhole (LDDH 1) (license 45/1064): Western Australia Geological Survey, M-series, ItemM7567 (unpublished). Busbridge, M., 1994, Lake Disappointment exploration licence 45/1064, third annual report: Western Australia Geological Survey, M-series, Item M7567 (unpublished). Carlsen, G.M., Apak, S.N., Ghori, K.A.R., Grey, K. and Stevens, M.K., 1999, Petroleum potential of the Neoproterozoic Western Officer Basin, Western Australia, based on a source-rock model from Empress-IA: APPEA Journal v. 39 (1), p. 322-341. Ghori, K.A.R., 1998, Petroleum source rock potential and thermal history of the Officer Basin, Western Australia: Western Australia Geological Survey, Record 1998/3, 52p. Hunt Oil Company, 1965, Yowalga 1, Lennis 1, Browne 1 and 2; prints: Western Australia Geological Survey, S-series, S234 (unpublished). Jubilee Gold Mines NL, 1996, Western Australia Geological Survey, M-series, Item M51195 (unpublished). Includes OD23. Karajas, J,, and Taylor, D., 1983a, Dragoon No. 1 well completion report: Western Australia Geological Survey, S-series, S2185 A8 (unpublished). Karajas, J,, and Taylor, D,. 1983b, Hussar 1 well completion report: Western Australia Geological Survey, Sseries, S2242 A4 (unpublished). Perincek, D., 1998, A compilation and review of data pertaining to the hydrocarbon prospectivity of the Officer Basin. Western Australia Geological Survey, Record 1997/6, 209p. Shell Company Of Australia Ltd, 1983a, Kanpa 1/1A well completion report: Western Australia Geological Survey, S-series, S2281 V1/A2/V1 (unpublished). Shell Company Of Australia Ltd, 1983b, Kanpa 1/1A well completion: Western Australia Geological Survey, Sseries, S2281 V1/A2/V2 (unpublished). Shell Company Of Australia Ltd, 1983c, Kanpa 1/1A well completion report (Officer Basin, EP 178): Western Australia Geological Survey, S-series, S2281 V1/A2/V3 (unpublished). Stevens, M.K. and Apak, S.N., 1999, GSWA Empress 1 and 1A well completion report, Yowalga Sub-basin, Officer Basin, Western Australia: Western Australia Geological Survey, Record 1999/4, 11 Op. Stevens, M.K., Apak, S.N., and Moors, H.T., (in prep.) GSWA Vines 1 completion report, Waigen Sub-basin, Officer Basin, Western Australia: Western Australia Geological Survey, Record 2000/in prep. Warris, B., 1998, Amadeus Petroleum NL, Boondawari No 1 well completion report: Western Australia Geological Survey, S-series, S20442 A1 (unpublished). Warris, B., 1998, Amadeus Petroleum NL, Mundadjini No 1 well completion report: Western Australia Geological Survey, S-series, S20441 A1 (unpublished). Western Mining Corporation Ltd, 1981, Terminal report on the Neale temporary reserves 8165H, 8166H, 8167H, 8168H, and 8169H for the period 27 February 1981 to 9 November 1981: Western Australia Geological Survey, M-series, Item M2752 (unpublished). Includes NJD 1.

A NEW APPROACH TO THE ESTIMATION OF MIXING RATIOS IN RESERVOIRS CONTAINING MULTIPLE OIL CHARGES X. Yu1. K.R. Arouri1, D.M. McKirdy1 and A J . Hill2 1. Organic Geochemistry in Basin Analysis Group, Department of Geology and Geophysics, University of Adelaide, Adelaide, SA 5005 2. Petroleum Group, Primary Industries and Resources South Australia, Level 7,101 Grenfell Street, Adelaide, SA 5000

Notwithstanding extensive previous work on the origin of petroleum in the Cooper and Eromanga Basins, the relative hydrocarbon contributions by their source rocks to any given reservoir remain difficult to determine. Although oils of Jurassic and Cretaceous origins are evident locally, it is widely accepted that most oil pools are either entirely Cooper-sourced, or are of mixed source affinity. Various methods have been employed to assess the relative contributions of different source rocks to individual oil pools in basins containing more than one petroleum system. In the case of the Cooper and Eromanga Basins, these include: (1) age-specific biomarkers (Alexander et al., 1988), (2) maturity contrasts between light- and heavy-end aromatic compounds (Alexander et al., 1996), (3) rc-alkane carbon isotopic profiles (Boreham and Summons, 1999) and (4) mixing curves obtained by cross-plotting aromatic source and maturity parameters (Michaelsen and McKirdy, 1999). All these approaches are at best semi-quantitative (although the last one has a resolution of ±10%). Moreover, the methods that make use of biomarkers appear to over-estimate the contribution from less mature Eromanga source rocks, thereby under-estimating the Cooper input. A mathematical model - based on a comprehensive mass balance of light and heavy components and inspired by the work of Alexander et al. (1996) - has been devised in an attempt to better quantify the mixing ratios of discrete oils in a given reservoir. A simplified two-source model is discussed here using as examples "pure" Cooper and "pure" Eromanga oils, and the full spectrum of mixing ratios represented by the 72 oil and condensate samples analysed in this study. For an oil pool of multiple origins (n sources each containing m components or groups of components), the weighted average value (Mj) of a certain chemical property (e.g. maturity; isotopic composition) can be calculated according to the general formula: Mj = J My (Xy yi/xj) where Xj = £ Xy y{; i = l,2,3...n; j = l,2,3...m; and m > n. A key to the terms in this equation (and those below) can be found in the Appendix. Taking into account the observed variations in the chemical composition and maturity of Cooper- and Eromanga-derived crudes (the former are generally more mature and contain more gasoline-range hydrocarbons), the theoretical model can be adapted to a dual source scenario. Thus, for example, the maturities of the light (ML) and the heavy (MH) fractions of the composite oil can be calculated using the following equations: M L = MQL X P L 0 PQ/(POL PO + PYL PY) + MYL X P y l Py/(PQL PO + PYL PY) M H = M O H X P 0 H P O / ( P O H P o + PYH P Y ) + M Y H x P Y H P Y / ( P O H P O + PYH P Y )

Here, each oil charge is simplified to contain only two groups of components: light hydrocarbons (C5 - Ci0) and heavy (Cn + ) hydrocarbons. Thermal maturity (as determined by the aromatic parameters MEBI or TMBI for the light ends, and TNR or MPI for the heavy ends: see Appendix) is taken as the property of interest in the petroleum charges received by the reservoir from both basins. Figure 1 shows the results of digital imitation of the dual source model. The less mature (Eromanga) oil is assigned a maturity value 1 for both its light and heavy components (i.e. MYL = 1 and MYH = 1)> while the more mature (Cooper) oil is given a maturity value 100 (i.e. M0L = 100 and M0H = 100). Point E represents "pure" Eromanga oils, whereas point C represents "pure" Cooper oils. Upon mixing of two oils each comprising equal amounts of light and heavy hydrocarbons (i.e. PYL ' PYH = 1 and P 0 L • POH = 1)> the resulting blend will plot along the straight line EAC ( 1 1 1 1 ) , with Cooper-to-Eromanga mixing ratios ranging from 0 (at point E) to 100 (at point C). However, the larger the compositional contrast between the two oils mixing in the reservoir, the greater the deviation from the central line EAC. Composite oils plotting above this line are the result of mixing of gasoline-rich Cooper crude with heavy-enddominant Eromanga oil. Thus, for example, the curve EBC (1221) represents oil pools composed of an Eromanga charge in which light ends are half as abundant as heavy-end hydrocarbons (PYL : PYH = 1:2) mixed

with a Cooper charge containing two times more light than heavy hydrocarbons (P L : POH = 2:1). Likewise, data plotting along the curve EDC (1551) represent an even greater differential between light and heavy hydrocarbons in the Eromanga (PYL : PYH = 1:5) and Cooper (P : POH = 5:1) charges. A hypothetical mixture falling into the area below the line EAC in the M -M cross plot is geologically improbable, as oils of high maturity normally contain more gasoline-range components, whereas less mature crudes have more heavy-end hydrocarbons. Therefore, the curve EFC (5335) is highly unlikely to occur in nature. Certainly, none of the 72 oil and condensate samples from the Cooper and Eromanga Basins analysed in this study exhibits any such affinity. 0

Principal components analysis of the TMBI-1 versus MPI distribution of the whole sample set (Fig. 2) reveals that the first two components control 98% of the data variation, of which 80% (the main principal component) is represented by the major axis of the ellipse. Digital imitation of the two-oil-charge model indicates that the major principal component reflects the mixing ratio of the two oils (x = P - Py)> whereas the second reflects the difference in their chemical composition (y = [P H - PYL] - [POL - POH])- This digital imitation clearly demonstrates that the distribution pattern of the maturity data in a suite of mixed oils is influenced not only by the mixing ratio, but also by the compositional difference between the individual oil charges. 0

The match between the results calculated using this model and the actual data set is demonstratable (Figs 1 and 2), and such a calculation can therefore be used to more precisely predict the relative contributions of multiple sources to an oil accumulation. Amongst the samples analysed here, the Tirrawarra condensate at Bookabourdie (sample #85) can be treated as the most mature end-member, based on its composition (light hydrocarbons with no conifer biomarkers) and maturity (TMBI-1 = 0.83, MPI = 1.56). The least mature end-member is best represented here by the Namur oil at Taloola (sample #95: TMBI-1 = 0.56, MPI = 0.53). A 60:40 mixture of these two crudes charging a given reservoir would theoretically mingle to produce a composite oil with the following properties: TMBI-1 = 0.79, MPI = 0.73, light-to-heavy-end ratio = 3. These data closely resemble the measured maturity parameters of the Westbourne oil from the Thungo field (sample #41: TMBI-1 = 0.80, MPI = 0.69) located on the structural high that separates the Nappamerri Trough from the northern Cooper Basin. Other instances of a striking consistency between measured and calculated data are provided by the oils in vertically-stacked reservoirs of the Sturt, Taloola and Tantanna fields on the southwestern margin of the Patchawarra Trough. In the Taloola field, three geochemically-distinct oils (# 95, 94, & 93) are produced from its Jurassic Namur, Hutton and Poolowanna reservoirs. The deeper the reservoir, the greater the hydrocarbon charge received from a Permian source (viz, < 30%, 30%, and 55%, respectively). These estimated mixing ratios are consistent with the respective araucariacean signatures (retene/phenanthrene = 2.5, 1.2, & 0.6) and maturity levels (MPI = 0.40, 0.62, & 0.75) of the oils in question (Fig. 2). The observed composition and maturity of oils pooled in the Murta Formation lend further credence to the proposed mathematical model. Where totally indigenous, these accumulations should exhibit the lowest maturity of all the Eromanga-sourced oils and display a predominance of Cn+ hydrocarbons (among them the araucariacean conifer biomarkers). If, in addition, Cooper-derived oils are to find their way into Murta reservoirs, they will most likely show the effects of long-distance migration and perhaps water washing (i.e. marked depletion of heavy-end hydrocarbons; preferential loss of the more soluble gasoline components) as well as being highly mature. When two such oils mingle, the mixture will inherit the chemical properties of both oils, including their maturity contrast. Hence, its MPI value will indicate a barely-mature oil whereas its TMBI-1 value will be indicative of a very mature crude. Consequently, such a mixed sample will plot in the upper left sector of both the M -M plot (Fig. 1) and the TMBI-MPI plot (Fig. 2). L

REFERENCES Alexander, R., Larcher, A.V., Kagi, R.I. & Price, P.I., 1988. The use of plant-derived biomarkers for correlation of oils with source rocks in the Cooper/Eromanga Basin system. APEA Journal 28(1), 310-324. Alexander, R., Bastow, T.P. & Kagi, R.I., 1996. Novel approaches to the determination of the origins of petroleum hydrocarbons in the Cooper-Eromanga Basin System. Unpublished report to the Department of Mines and Energy, South Australia. Boreham, C.J., Crick, I.H., & Powell, T.G., 1988. Alternative calibration of the Methylphenanthrene Index against vitrinite reflectance: Application to maturity measurements on oils and sediments. Org. Geochem. 12, 289-294. 81

Boreham, C.J. & Summons, R.E., 1999. New insights into the active petroleum systems in the Cooper and Eromanga Basins, Australia. APPEA Journal 39(1), 263-296. Michaelsen, B.H. & McKirdy, D.M., 1999. Aromatic hydrocarbon signatures of oils from the Cooper and Eromanga Basins, central Australia: Evidence of multiple sources and in-reservoir mixing. 19th International Meeting on Organic Geochemistry, Istanbul, Turkey. Abstracts, pp. 645-646.

APPENDIX MEBI = methylethylbenzene index (this study) = [l-methyl-3-ethylbenzene + l-methyl-4-ethylbenzene] / [l-methyl-3-ethylbenzene + l-methyl-4ethylbenzene + l-methyl-2-ethylbenzene] TMBI-1 = trimethylbenzene index-1 (Alexander et al., 1996) = 1,3,5-trimethylbenzene/ 1,3,5-trimethylbenzene + 1,2,3-trimethylbenzene TMBI-2 = trimethylbenzene index-2 (Alexander et al., 1996) = 1,2,4-trimethylbenzene/ 1,2,4-trimethylbenzene + 1,2,3-trimethylbenzene TNR-1 = trimethylnaphthalene ratio-1 (Alexander et al., 1988 and references cited therein) MPI-1 = methylphenanthrene index-1 (Boreham et al., 1988 and references cited therein) Key to equations: My Xy yi Xj M M Po PY Pol POH PYL PYH ML MH Myl MH l

= value of a certain property of the jth component (or group of components) in the ith oil source = portion of the jth component (or group of components) in the zth oil source = portion of oil from the ith source = portion of the jth component (or group of components) in the mixture = weighted average maturity of the light-end hydrocarbons in the mixture = weighted average maturity of the heavy-end hydrocarbons in the mixture = portion of hydrocarbons sourced from the more mature (older) rock = portion of hydrocarbons sourced from the less mature (younger) rock = portion of light-end hydrocarbons from the more mature rock = portion of heavy-end hydrocarbons from the more mature rock = portion of light-end hydrocarbons from the less mature rock = portion of heavy-end hydrocarbons from the less mature rock = maturity of light-end hydrocarbons from the more mature rock = maturity of heavy-end hydrocarbons from the more mature rock = maturity of light-end hydrocarbons from the less mature rock = maturity of heavy-end hydrocarbons from the less mature rock

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TMBI-2 Oil/gas field

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KILOMETERS

1:140°: - L Figure 1. Map of the SA sector of the Cooper Basin, showing major hydrocarbon fields. AGE

ROCK UNIT SW MARGIN

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Figure 3. Projection of the Cartesian coordinates consisting of the first two principal components on the crossplot of MEBI vs MPI.

WALLUMBILLA FORMATION

BULLDOG SHALE MT ANNA SST MBR

WYANDRA SST MEMBER CADNA-QWIE FORMATION, MURTA MEMBER Ml M00GA MCKINLAY MBR FORMATION NAMUR SANOSTONF

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WESTBOURNE FORMATION ADQRI SANDSTONE

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* • • • TOOLACHEE FORMATION DARALINGIE FORMATION ROSENEATH SHALE EPSILON FORMATION

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MURTEREE SHALE FWTCHAWARRA FORMATION •

TIRRAWARRA SANDSTONE

MERRIMELIA FORMATION CAMBRO -PRO

WARBURTTON BASIN

Figure 2. Stratigraphic column of the Cooper and Eromanga Basins.

100

M H

Figure 5. A representation of the digital imitation of the two-end-member mixing model.

ILLITE, THE KEY TO IDENTIFYING RESERVOIR QUALITY IN THE MERRIMELIA FORMATION; COOPER BASIN, SOUTH AUSTRALIA. C. Cubitt1* and A. Kaiko2** *National Centre For Petroleum Geology and Geophysics (NCPGG) Thebarton Campus, The University of Adelaide, South Australia SA 5005 **The Gartrell School of Mining, Metallurgy and Geology, University of South Australia The Levels The Merrimelia Formation, the lowermost unit in the Cooper Basin, consists of (Carboniferous to Permian) Gondwanan glacigene sediments. This formation has been traditionally regarded as economic basement and subsequently was not targeted for hydrocarbon exploration. Williams and Wild (1984) reinterpreted the Merrimelia Formation and Tirrawarra Sandstone association concluding that both units formed a sedimentary continuum. Consequently, a number of hydrocarbon discoveries followed as explorers targeted older sandstone packages at Malgoona, Merrimelia and Pondrinie Fields. However, permeabilities encountered varied enormously. This variability has been attributed to facies as matrix-rich facies in terminoglacial environments form poorly permeable intervals and proglacial quartzose facies exhibit better reservoir qualities (Chaney et al., 1997). Twenty one glacial facies types were identified in the Merrimelia Formation. Two of these facies have the potential to reservoir hydrocarbons: glacio-aeolian and longitudinal bar sandstones. Distal proglacial glacio-aeolian sandstones exhibit the best porosity of any facies type in the Merrimelia Formation. Hydrocarbons are reservoired in these sediments at the Merrimelia Field. Longitudinal bar forms are also common in the proglacial setting and are typically quartzose. Commercial quantities of oil were discovered in these sandstones at the Malgoona Field. The aeolian sandstones have average porosities of 18% whereas longitudinal bar sandstones average 12%. Longitudinal bar sediments, however, have higher permeability than the more porous glacio-aeolian sandstones. The disparity in reservoir quality has been linked to the presence of illite and illite morphology. In general, illite was found to dictate reservoir quality in all Merrimelia facies. Consequently, understanding the morphology, formation, timing and distribution of illite is critical for risking the likelihood of favourable reservoir attributes in the Merrimelia Formation. Three basic illite morphologies were recognised in Merrimelia sediments; 1) Filamentous 2) Box work 3) Platy. Filamentous illite fills pores, coats framework grains and is the main constituent of matrix. Filamentous illite was also observed on the scalloped edges of various illite box work textures. Box work morphologies are associated with unstable framework components and are therefore commonly described in lithologies rich in ductile rock fragments. Platy illite coats framework grains in glacio-aeolian sandstones of the Merrimelia Field. Generally, the presence of illite in a sandstone reservoir is seen as a negative influence on reservoir quality. Illite drastically reduces the reservoir potential of the majority of Merrimelia facies. However, the presence of illite does not necessarily negate a potential reservoir interval as distribution is as important as mere presence. The longitudinal bar sandstones at Malgoona show boxwork illite morphologies isolated as clumps formed from the breakdown of feldspars. This mode of illite occurrence has little effect on reservoir quality as the clay does not block pore throats. Conversely only a small proportion of illite in the porous glacio-aeolian sandstones of the Merrimelia Field drastically diminishes the quality of these reservoirs. Filamentous and platy illite coats framework grains and blocks pore throats to reduce flow between pores. Galloway (1979) states 6 that platy illite flakes surrounding quartz framework grains act as baffles to retard fluid flow. He concluded that the addition of clay rims around a typical detrital grain produces a 1 to percent increase in the radius of the Current Addresses 1 Santos Ltd. Level 10, Santos House 91 King William St Adelaide SA 5000 Centre of Excellence in Petroleum Geology, School of Applied Geology, Curtin University, WA.

grain. The very rounded grains of glacio-aeolian sandstones maybe regarded in the simplest terms as packed spheres. In this theoretical arrangement permeability is proportional to the square of the pore throat size and a 6% increase in grain diameter translates to a 26% reduction in pore throat diameter. The glacio-aeolian and longitudinal bar facies show that understanding the distribution, morphology, formation and timing of illite are key factors in unlocking the potential of illitic reservoirs. Facies type dictates illite distribution as argillaceous facies contain high proportions of illite and arenaceous facies have much less. Illite in Merrimelia sediments forms or reforms by one or more of four mechanisms: 1) Grain coating (transformation) 2) Pore-filling (neo-formation) 3) Partial or total replacement of unstable feldspars/rock fragments (transformation) 4) The transformation of detrital smectite to illite (transformation) Illite growth is accelerated by the presence of fine grained detrital clay and argillaceous rock fragments. The less reworked terminoglacial facies have a greater percentage of matrix and rock fragments and contain more illite than proglacial or arenaceous facies. Other factors which accelerate illite formation include: 1) Rock fragment type (argillaceous as opposed to arenaceous) 2) Elevated basin temperatures 3) Fluid/rock ratios (low permeability) 4) Access to illite-forming reactants The timing of illite formation is critical. Does illite formation occur before hydrocarbon charge, preventing hydrocarbons entering pore spaces or after? Does illite formation occur early, weakening framework grains, preventing silica growth and accelerating compaction and pore space reduction? To answer these questions a paragenetic sequence was established using petrographic observations, illite dating (Figure la) and geohistory analysis (Figure lb). The paragenetic sequence (Figure lc) indicates that illite formation occurs at an early stage. In argillaceous sediments, illite development promotes the destruction of porosity and permeability. The effects are less in arenaceous intervals as there is less muddy matrix and rock fragments. Preliminary results from illite dating and geohistory analysis (Figures la & lb) indicate that peak illite formation occurs between 80°C and 100°C, coincident with the oil generation window. These interpretations are, however, based on a limited sample set but ages do show good agreement with other constrained diagenetic observations (Figure lc). The dating results presented here give an indication of trends rather than an absolute age and the current interpretations are contingent on further analysis. Preliminary results suggest that this technique can be applied successfully in the Cooper Basin and may be refined to better indicate the timing of illite formation and hydrocarbon charge.

Sample Name 2 M A L 4H 2MRI I8B

<4 Micron

192 l.5±Ma 156 l.3±Ma

<2 Micron

168 l.4±Ma 138 !±Ma

MALGOONA 4

Merrimelia-Tirrawarra Glacial Complex Diagenetic Event 1 - Compaction 2 - Smectite/lllite transformation of grain coating clay, muddy matrix + 3 - Alteration of RF's 4 - S I Siderite (Micritic) 5 - Syntaxial Silica 6 - Oogenetic Silica/Kaolin 7 - Feldspar Dissolution 8 - Pore Filling Kaolin 9 - Dickite 10 - D1 Siderite Dissolution - S2 Siderite (Zoned) 12 - Chlorite 13 - 2nd Porosity Formation 14 - D 2 Siderite Dissolution 15 - S3 Siderite (Sparry, Poikilotopic) 16 - Calcite 17 - Drusy Quartz 18 - Ferroan Dolomite 19 - Pyrite 20 - Pyrophyllite (Very Limited Extent)

E |

Time (Ma)

\ EXPDEV 082

Figure 1 a) Potassium-Argon illite dates of <2 and <4 micron illite fractions from Malgoona #4 (2MAL 4H) and Merrimelia #18 (2MRI18B) b) Geo-history plot of Malgoona #4 with illite formation dates superimposed c) Paragenetic sequence of the Merrimelia Formation. The variable nature of reservoir quality in the Merrimelia Formation is attributed to the presence of illite which need not negate the assessment of a sand as a viable reservoir. This study has shown that the uncertain nature of Merrimelia reservoirs can be reasonably predicted by understanding the distribution of illite and its various morphologies. Potential reservoirs should be assessed using the following criteria: 1) Timing of illite formation 2) Illite proportion 3) Distribution of illite 4) Dominant illite morphology

REFERENCES Chaney A J., Cubitt C.J. and Williams B.P.J. (1997) Reservoir Potential Of Glacio-Fluvial Sandstones: Merrimelia Formation, Cooper Basin, South Australia. APPEA Jour, 37 (1), pp. 154-176. Galloway W.E. (1979) Diagenetic Control Of Reservoir Quality In Arc-Derived Sandstones: Implications For Petroleum Exploration. SEPM Special Publication No. 26, pp. 251-262. Moore D.M., and Reynolds R.C. (1989) X-Ray Diffraction and The Identification and Analysis Of Clay Minerals. Oxford University Press. Rezaee M.R. (1996) Reservoir Characterisation Of The Tirrawarra Sandstone In The Moorari and Fly Lake Brolga Fields, Southern Cooper Basin, South Australia Unpubl PhD Thesis NCPGG-The University Of Adelaide. Williams B.P.J., Wild E.K. and Sutill R.J. (1985) Paraglacial Aeolianites: Potential New Hydrocarbon Reservoirs, Gidgealpa Gp. Southern Cooper Basin. APEA Jour. Vol. 25 (1), pp. 291-310. Williams, B.P.J. and Wild, E.K., (1984a) The Tirrawarra Sandstone and Merrimelia Formation of the Southern Cooper Basin, South Australia the sedimentation and evolution of a glacio-fluvial system. APEA Journal, 24(1), pp. 377-92. ACKNOWLEDGEMENTS The authors would like to thank Gerry Carne, Sharon Tiainen and especially Drs Peter Tingate and Nick Lemon for proof reading and improving the original manuscript. Their suggestions and critical assessment of the technical aspects of this abstract were invaluable. We would also like to thank the NCPGG, for providing facilities and funding for this study. Finally we sincerely thank the staff at CEMMSA for helpful microprobe and SEM tips, as well as the Santos Ltd. Drafting Dept. The authors acknowledge the support of PIRSA and Santos Ltd. (South Australian Business Unit).

NATURAL FRACTURE PLAYS OF THE SOUTHERN COOPER AND EASTERN WARBURTON BASINS, SOUTH AUSTRALIA Xiaowen Sun Sun Petroleum Geoservices, 32A Lincoln St., Kensington Gardens, SA 5068

Detailed studies of natural fractures in the Cooper and underlying Warburton Basins by Sun (1999) and Sun (in preparation) confirm that natural fracture plays are important for exploration and production. Characterisation and analysis of natural fractures from the two basins, and their comparison are summarised herein. Orientations of open and partially open fractures and fracture systems, and their implication to production and further exploration in the basins are briefly addressed. COOPER BASIN The Cooper and Eromanga Basins in northeastern South Australia and southwestern Queensland are the largest Australian onshore oil and gas provinces (Gravestock et al. 1998). Sun (in preparation) has delineated and classified various forms of natural fractures from selected lithological units, mostly Merrimelia Formation, Tirrawarra Sandstone, Patchawarra Formation and Nappamerri Group of the southern Cooper Basin in some 44 wells. Detailed core studies of some 64 wells in conjunction with the use of dipmeters and FMS (Formation MicroScanner) logs from 9 wells, and examination of core descriptions in well completion reports of an additional 40 wells, have resulted in recognition of fractures in 44 wells. Generally speaking, open fractures are developed mainly within brittle sandstone of the Tirrawarra Sandstone such as in Gidgealpa 49, Kurunda 2, Pondrinie 11 and Pelican 2. These open fractures are mostly high angle to subvertical, with measured apertures of up to 2mm. Many fractures are partly or completely mineralised. Fracture filling includes silica, carbonates, pyrite and kaolinite. Absolute fracture orientation data are obtained from 111 measurements of cores and FMS logs from 9 wells. Two sets of steeply dipping regional fracture systems are essentially similar to those identified from the underlying Warburton Basin by Sun (1999). These regional fractures have the most potential for oil and gas production; WNW (110° - 290°) orientation possibly is one of the prominent strike directions. The deviation angle of future wells should be approximately 20° from horizontal in the fracture zones to maximise the likelihood of such wells encountering high angle open fractures. 9

Many tectonic fractures are low angle and normal microfault related. There are also some reverse and thrust microfaults occurring mainly along the Gidgealpa-Merrimelia-Innamincka (GMI) Ridge and other structural culminations. Tectonic fractures, especially normal microfaults related fractures are cemented with silica or associated with carbonaceous clays or both. The silica cemented zones were damaged and less permeable than adjacent matrix, thus these fractures are unlikely to be reservoir efficient fractures. However, the intensely reverse fault-deformed zones contain numerous fractures, which may be open or partially open due to episodic reactivation of pre-existing structures. A semi-quantitative estimate of fracture density has been determined for 41 wells. The greatest fracture density is located in major fault (e.g. strike-slip) zones or structural culminations (e.g. the GMI Ridge). WARBURTON BASIN Cambro-Ordovician Warburton Basin strata and intrusive Early Carboniferous granites are conventionally regarded as economic basement beneath the Cooper-Eromanga oil and gas province, and thus not explored seriously. Oil has flowed in commercial volumes from fractured Cambrian ignimbrite in Sturt 6 and 7, gas has been tested in Moolalla 1 and Lycosa 1 in Cambro-Ordovician sandstone and fractured siltstone lithologies respectively. Their very low permeability and declined hydrocarbon production suggest that they are fractured reservoirs (mainly Type C and Type B reservoirs) (Sun, 1999; Sun & Gravestock, in preparation). Because the fractures contain oil and gas sourced from Cooper Basin rocks, effective secondary hydrocarbon migration into fractured, basement traps confirms existence of natural fracture plays at the interface between the Warburton and Cooper Basins. Sun (1999) characterised fractured reservoirs and delineated fracture patterns, for the first time, in order to predict the orientation of open fractures and thus potential reservoirs. It identified and mapped a regional fracture system through upper levels of the Warburton Basin. Considerable information has been gathered from a detailed core study of 91 wells in conjunction with the use of dipmeters and Formation Micro-Scanner (FMS) logs from 27 wells. Absolute orientation data are obtained from measurements of cores and logs from 23 wells (Figure 1), and additional relative orientation data are collected from 24 wells. From these data, two systems of

Figure 1 Map of Cooper Basin showing absolute orientation of strike directions of high angle, regional fractures of the Warburton Basin.

orthogonal high angle fracture sets have been identified for the first time across local structures, and extend beneath the Cooper Basin in South Australia. System I has a pair of orthogonal fractures, striking NNE-SSW (20-200°) and ESE-WNW (110-290°). System II has a pair of orthogonal fracture sets, striking NE-SW (60240°) and NW-SE (150-330°). Open, steeply dipping SW fractures striking WNW and NW within systems I and II are interpreted from FMS both in Lycosa 1 and Malgoona 4, and also core 1 of Lycosa 1. The results indicate that an optimum well trajectory designed to maximise intersection with open natural fractures should be 200210° and 240-250°, and possibly also 270-290°. The deviation angle should be approximately 30° from horizontal in the fracture zone due to the high angle and subvertical fracture dips. A semi-quantitative estimate of fracture density has been determined for 91 wells, and the greatest fracture density is located in major fault zones or structural culminations as expected. Generally speaking, fractures are mainly developed within brittle rather than ductile rock types if they are frequently interbedded. Fracture fairways exist in brittle sandstone, dolomite and ignimbrite, and any rock types with the above suggested orientations of the two systems of orthogonal fracture sets. The basement fracture play suggests that future wells should be drilled at least 400 feet (vertical depth) into the Warburton Basin where Cooper Basin source rocks lie down dip. Proper testing for hydrocarbons in the Warburton Basin is recommended. Wireline logs should include dipmeter or FMS, especially where bedding dips are suspected to be significant. COMPARISON BETWEEN WARBURTON AND COOPER BASINS Generally speaking, fractures in the Warburton Basin are more widely and strongly developed than those in the Cooper Basin. Frequency of fracture occurrence in Cooper Basin wells is approximately 35%, comparing with 95% in the Warburton Basin. Fracture density in the Cooper Basin is generally low whereas it is moderate to high in the Warburton Basin. The studied Cooper Basin fractures have relatively higher percentage of open fractures than the Warburton Basin data. Gouge-filled fractures, severe brecciation and slickensided fractures are uncommon in Cooper Basin data whereas Warburton Basin fractures have many gouge-filled fractures and slickensides. Generally speaking, there are fewer phases of fracturing, faulting and fracture fill in the studied Cooper Basin than the Warburton Basin data. Apertures of mineral-filled fractures in the Warburton Basin are broader than in the Cooper Basin. Mineralogy of fracturefillin the Cooper Basin seems to be simpler than that of the Warburton Basin. Stylolites are much more common in sandstone of the Cooper Basin than in the Warburton Basin, this may be due to lack of carbonaceous or organic material in the Warburton Basin. A few tension gashes associated with stylolites have been observed in the sandstone of the Cooper Basin, but they are quite common in the Warburton Basin. Three main types of natural fractures were identified in the Warburton Basin, namely regional, tectonic and contractional (Sun, 1999). The contractional fractures have been recognised in acid and basic volcanics. The regional high angle fractures comprise two systems of orthogonal pairs. The similarity of the regional fracture systems in the Warburton Basin and the lineaments recognised by Campbell & O'Driscoll (1989) and Boucher (1998) suggests that the lineaments are related to the deep- seated fracture systems. The tectonic fractures include fractures related to mainly folds, thrust and reverse faults, and minor normal faults. From a few oriented wells, fault planes of thrust and reverse faults along the GMI Ridge dip SE, slickensides are very common and have majority orientation NW-SE. These features confirm a compressive tectonic regime interpreted by many authors (Sun, 1997 and references therein). The tectonic fractures are superposed on the regional fractures. In the Cooper Basin there are two main types of fractures: tectonic and regional. The tectonic fractures comprise mainly fault-related fractures including many normal, some reverse and thrust microfaults. However, there are no graben-type normal faults, instead mainly thrust and reverse faults and fold related tectonic fractures in the Warburton Basin. Comprising high angle, either open or filled fractures, the regional fractures in the Cooper Basin also form two fracture systems (4 fractures) which are essentially similar to those identified in the Warburton Basin (Sun, 1999) (Figure 2). In the Warburton Basin, many fractures are averaged into mean values, but in the Cooper Basin data, value of every single fracture is used (Figure 2). Further comparison can be made between absolute dip azimuths and strike directions of high angle fractures measured from the Warburton Basin and immediately overlying Cooper Basin strata in the same well. Similar to the case in the Warburton Basin that regional fractures in Lycosa 1 produced commercial volume of gas (Sun, 1999), the steeply dipping regional fractures in the Cooper Basin are likely to provide reservoir efficient fractures.

M e a n strike d i r e c t i o n o f 4 5 f r a c t u r e s , Warburton Basin

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Figure 2 Histograms showing strike orientations of high angle, regional fracture systems of the Warburton and Cooper Basins REFERENCES Boucher, R.K., 1998. Lineament associations in the Cooper Basin region, South Australia: basement controls on hydrocarbon distribution. South Australia. Department of Primary Industries and Resources. Report Book 98/00030. (unpublished). Campbell, I.B. and O'Driscoll, E.S.T., 1989. Lineament-hydrocarbon associations in the Cooper and Eromanga Basin. In: O'Neil, B.J. (ed.), The Cooper and Eromanga Basins, Australia. Proceedings of the Petroleum Exploration Society of Australia, Society of Petroleum Engineers, Australian Society of Exploration Geophysicists (S.A. Branches), Adelaide, p.295-313. Gravestock, D.I., Hibburt, J.E. and Drexel, J.F., (Eds), 1998. The petroleum geology of South Australia Volume 4: Cooper Basin. Report Book 98/9. Primary Industries and Resources SA, p. 159-181. Sun, Xiaowen, 1999. Fracture analysis of the eastern Warburton Basin (Early Palaeozoic), South Australia. Report Book 99-00014. Primary Industries and Resources SA. (unpublished). Sun, Xiaowen, in preparation. Natural fractures of the southern Cooper Basin, South Australia. Report Book. Primary Industries and Resources SA. (unpublished). Sun, Xiaowen & Gravestock, D.I., in preparation. Potential hydrocarbon reservoirs in upper levels of the eastern Warburton Basin, South Australia. Report Book. Primary Industries and Resources SA. (unpublished). Acknowledgements: The author is grateful for receiving a Postdoctoral Fellowship from the Petroleum Group, Primary Industry and Resources South Australia (PIRSA) for this comprehensive study at the National Centre for Petroleum Geology & Geophysics, the University of Adelaide. She highly appreciates constant encouragement and supervision from Dr Dave Gravestock (PIRSA). She would like to express sincere thanks to Prof. Richard Hillis, Dr Scott Mildren, and Mr Jerry Meyer for their permission and help with using Borview software to interpret FMS data. She would like to thank Messrs Brian Logan, Michael Pate, Kevin Braithwaite with excellent service of core inspection. Many thanks also go to Messrs Alan Sansome and Don Vinall for transferring digital data, and to Gayle Bruggemann, Jeff Weber, Adrian Francis for excellent drafting skills.

ABOUT THE AUTHORS Elinor Alexander is currently a Senior Geologist with Petroleum Group PIRSA and is responsible for the promotion of SA petroleum exploration opportunities through geological studies and marketing activities. She joined the SA Department of Mines and Energy in 1985 after completing an Honours Degree in Geology at the University of Adelaide. Elinor has worked on many SA basins (including the Eromanga, Otway, Cooper, Pedirka, Simpson, Arrowie and Stansbury Basins) and topics including reservoir petrophysics, clastic and carbonate sedimentology and basin analysis - often in collaboration with the late Dr Dave Gravestock. Elinor is a former President of the S A Branch of PES A and is also a member of the IAS and SEPM. Greg Ambrose completed his BSc with Honours in 1973 at the University of Adelaide. He subsequently joined the South Australian Geological Survey before spending 20 yrs in the oil industry with Santos Ltd and Lasmo Pic in Australia and the Arabian Gulf Oil Company in Libya. He is currently the Senior Petroleum Geologist attached to the Northern Territory Geological Survey. His interests lie in all aspects of basin analysis as related to hydrocarbon exploration and field development and appraisal. Khaled Arouri received his B.Sc degree in earth and environmental sciences from Yarmouk University, an M.Sc. degree in geology and organic geochemistry from the University of Jordan, and a Ph.D. (1996) in petroleum geochemistry and geology from the University of Adelaide. Following a postdoctoral fellowship at Macquarie University, he returned to Adelaide University in 1999 to undertake research in the fields of sourcereservoir geochemistry and petroleum migration in Cooper and Eromanga basins. Jean-Marie Auzende holds a PhD "3rd cycle" from the University of Paris (1969), and "Es Sciences" at the same University (1978). He has been employed for 31 years by IFREMER in the Marine Geoscience Department. He is in charge of Regional Cooperation for IFREMER at Noumea and of the French side of FAUST joint project (French Australian Seismic Transect). He is theScientific Coordinator of ZoNeCo program for the evaluation of the Economic Potential of the New Caledonia Economic Zone. Tom Bernecker received an MSc from the University of Aachen, Germany and holds a PhD from Melbourne's La Trobe University. He spent three years teaching general geology and sedimentology at the University of Melbourne, before joining the Petroleum Development Unit in Victoria's Department of Natural Resources and Environment. He is a geologist/explorationist in the Basin Studies Group and his current work focuses on a regional geological investigation of the Gippsland Basin with special emphasis on stratigraphic correlation and controls on depositional facies changes. He also maintains a strong interest in post-depositional processes, in particular in the context of hydrocarbon emplacement. He is currently secretary of PESA's Vic/Tas-Branch and is also a member of IAS, SEPM and GSA. Jane Blevin is a Senior Research Scientist in AGSO's Petroleum and Marine Division. She obtained a BS and MS in Geology (Texas, USA), and worked in the exploration industry in Houston before coming to Australia in 1989 to undertake PhD studies at James Cook University. Jane is the Area Leader for AGSO's newly formed East and Southeast Regional study group. She was involved in the sequence stratigraphic and petroleum systems analysis of the Bight Basin, and formerly Project Leader of AGSO's Browse Basin High Resolution study. Jane has also been involved in basin analysis, prospectivity and palaeogeographic studies on the North West Shelf, and has provided advice to the Commonwealth's Acreage Release program since 1991. She is a past-President of the PESA ACT Branch. Irina Borissova has been working in the Law of the Sea project for the past three years. She has a PhD in marine geology from Shirshov Institute of Oceanology, Russian Academy of Science. She started her career in Russia working on tectonics of mid-ocean ridges and oceanic fracture zones. For the last seven years she worked on a number of projects at AGSO including compilation of geological maps, survey planning, development of new techniques for Law of the Sea work and geological framework studies. Jamie Burgess graduated from the NCPGG with first class honours in 1994. In 1999 he completed a PhD with Adelaide University's Organic Geochemistry in Basin Analysis Group on the application of stable isotopes to Precambrian stratigraphic correlations. Since 1998 he has worked for the Northern Territory Geological Survey in the Regional Geoscience of Sedimentary Basins programmes. Other professional interests include the analysis of fault geometries in extensional regimes and the palaeoenvironment that lead to the Ediacaran boom. He is a member of the AAPG and is currently Chair of the NT Division of the Geological Society of Australia.

Greg Carlsen is currently employed by the Geological Survey of Western Australia as Project Manager for work being carried out in the Canning, Officer and Amadeus Basins. He started his Liberal Arts and Sciences Degree at the University of Southern California and completed his Degree in Geology from Augustana College in 1976. He later completed a Master of Science Degree from Northern Illinois University in 1978. His career began as a Geophysicist with Getty Oil Company, Houston in 1978 where he completed mapping projects for the Gulf of Mexico and the North Slope of Alaska. He moved on after 2 years to join Marathon International Oil Company, working in Libya, Egypt, Australia, Indonesian and Syria. In 1990 Greg was promoted to Chief Geophysicist for Marathon in Ireland. Greg is an experienced geophysical interpreter and project leader whose responsibilities have included comprehensive interpretations, contract negotiations, government liaison, risk reduction analysis, strategic planning, cost analysis and fiscal control. Jim Colwell is a Principal Research Scientist in AGSO's Petroleum and Marine Division. Jim was a former member of the Southern Margin Frontiers project, and is currently the Area Leader for AGSO's North and Northwest Regional study group. He is a graduate of the Australian National University and Hinders University (BSc Hons, MSc). He has published in the fields of coastal and nearshore sedimentology and marine geology, as well as on the geology of the Bass and Gippsland Basins, Kerguelen Plateau, Solomon Islands and the North West Shelf. Jim is a member of PESA, AAPG and GSA. Chris Cubitt obtained a BappSci (Geology) from the Royal Melbourne Institute of Technology in 1991. Before commencing an honours degree he worked as a contract geologist for various mining, mineral exploration and environmental geology companies. He then spent 1992 at the National Centre for Petroleum Geology and Geophysics (NCPGG) where he graduated with a BSc Hons in Petroleum Geology. Currently he is submitting his PhD through the NCPGG where he has been working on the provenance and diagenesis of the Merrimelia Formation in South Australia and Queensland, in close collaboration with the University of Aberdeen. Chris has been with SANTOS Ltd for the last three years as an exploration/development geologist. Bob Dalgarno graduated from Adelaide in 1958 and worked for 5 years as a Regional Surveys geologist in the SA Department of Mines. He had a return to the fold for 18 months as Supervisor Regional Section in the late 70s with intervals either side totalling 20 years in the minerals industry. He was Director of Geological Survey of Victoria for eight years and then Manager of their Initiatives Program till end 1998. He is now semi-retired to Mount Gambier. Dr Jerry Dickens is a Lecturer in geochemistry and oceanographic studies at the School of Earth Sciences at James Cook University, who obtained his PhD from the University of Michigan in 1996. He is a world leader in the study of oceanic gas hydrates and geochemical cycling during major oceanographic changes. Other current research interests are iron deposits and their deposition from deep-sea hydrothermal plumes, and the nature of continental margins where mixed carbonates and clastics were deposited or are being deposited. As regards the present paper, his studies of gas hydrates are most relevant. These include participation in past and future sampling on Ocean Drilling Program legs, and Jerry has published benchmark papers on the distribution and composition of gas hydrate in sedimentary columns, experimental work on the thermodynamic conditions of gas hydrate formation and dissociation, and numerical models pertaining to the release of methane into the ocean and atmosphere. Jerry is in the forefront of research into abrupt Cainozoic climate changes, some of which are almost certainly related to catastrophic release of gas hydrate from below the oceans. In the Australian region his gas hydrate research has been concentrated on the enigmatic bottom simulating seismic reflector on the Lord Howe Rise, and the gas hydrates that are assumed to cause the reflector. Dr Neville Exon is a marine geologist and Research Group Leader at AGSO where he has broad responsibility for Law of the Sea, Antarctic and international studies. He worked for some years with BMR in field mapping and basin studies in Queensland, before obtaining his PhD from the University of Kiel in Germany in 1971. Since then he has worked as a marine geologist/geophysicist in sedimentary basins off western and southeastern Australia. In recent years his research has been largely off southeastern Australia, often in conjunction with foreign institutions and university scientists. A major area of interest has been the continental areas around Tasmania, where he has led swath mapping, seismic and sampling cruises that have led to greatly increased understanding of the west Tasmanian margin, the South Tasman Rise and the East Tasman Plateau. He has just returned from two months at sea as Co-chief Scientist on ODP Leg 189 off Tasmania, during which JOIDES Resolution continuously cored sequences representing the last 75 million years of breakup and drift history between Antarctica and Australia. In the last couple of years he has also worked with others in

mapping and studying the bottom simulating seismic reflector and sedimentary diapirs in the Lord Howe Rise region, which suggest that the Fairway Basin is generating thermogenic gas and has long-term petroleum potential. Hector Gordon is Exploration and Production Manager for Beach Petroleum N.L. He gained a BSc (Hons) in Geology from The Flinders University of South Australia in 1976 and, since that time, has been employed in the Australian petroleum exploration and production industry in a variety of technical and management positions. Prior to joining Beach in 1996 Hector's employers included Delhi International Oil Corporation, Esso Australia, AGL Petroleum and Santos. He is a member of AAPG, SPE, PESA and the Australian Institute of Company Directors. John Gorter earned his BSc (Hons) from ANU and a PhD from the University of New South Wales. In a career spanning 28 years in geology and the petroleum exploration industry, since 1972 he has worked for the Bureau of Mineral Resources (now AGSO), ESSO, Pancontinental Petroleum, AGIP, Sydney Oil Company, Command Petroleum, Petroconsultants and NORCEN. In 1990 he joined Petroz in Perth, then moved to Hardy Petroleum Limited (now British-Borneo Australia Limited) in 1992, where he is currently Manager Geosciences. He is a member of PESA, AAPG and the Geological Society of Australia. David Gravestock worked as a Technical Officer at the Weapons Research Establishment, Salisbury for nine years, during which time he completed his BSc part time at the University of Adelaide. In 1975 he embarked upon a Ph.D. investigating the palaeontology and biostratigraphy of Archaeocyatha and the Degree of Doctor of Philosophy was conferred in 1981. Later that year and after a brief period with Delhi Petroleum, Dave joined the then Fossil Fuels Section of the SA Department of Mines and Energy, where he worked until his death. There, he made many significant and diverse contributions towards knowledge of the petroleum geology of SA. His special interests included carbonate sedimentology, sandstone reservoirs, Cambrian biostratigraphy and basin analysis. David's expertise was also recognised academically through his appointment as a Visiting Research Fellow at the NCPGG and membership of the Faculty of Science Advisory Board of the University of Adelaide. In 1992, Dave was asked by the PESA Federal Committee to become Honorary Technical Editor for the new PESA Journal and served PESA in this capacity for 5 years. Dave was diagnosed with cancer in early 1999 and valiantly managed to keep working with dignity and style, in spite of a variety of aggressive treatments. Dave died on the 15th of December 1999, at age 52. He was posthumously awarded PESA Distinguished Membership in May 2000 at the APPEA Conference. Paul Grech graduated with a BSc (Hons) from the University of Technology, Sydney. In 1994 he commenced his PhD studies at the NCPGG on the sedimentology and stratigraphy of the Re wan Group, Bo wen Basin. He is currently finishing his PhD while doing casual work at Wiltshire Geological Services (WGS) interpreting and correlating wireline logs from the Carnarvon Basin in a major study of the North West Shelf. Over the two years he has interpreted all open file wireline logs from the Bonaparte, Vulcan, Browse and Canning Basins. Paul has experience in field mapping and core logging of both ancient and modern sedimentology and facies analysis. Cedric Griffiths, a graduate of Durham University (UK), works for CSIRO Petroleum. He has been involved with solving geological problems since 1972. He has worked with field mapping in Angola and Zambia and worked on oil rigs in SE Asia, Texas, and the North Sea. His main research interest since 1979 has been in the prediction of geological units and properties away from observations. He has authored and co-authored over fifty papers in the fields of quantitative stratigraphy and petrophysics, and for the past fifteen years has widely promoted and encouraged the use of numerical simulation of stratigraphy in three dimensions. He is a council member of the International Association of Mathematical Geologists. Tony Hill is a graduate of the Royal Melbourne Institute of Technology (B.Sc. in Applied Geology). Since 1981 he has held positions with Bass Strait Oil and Gas NL and Weeks Australia. In 1982 he joined the South Australian Department of Mines and Energy (now PIRS A) where he is now Acting Manager of the Petroleum Geology Branch of the Petroleum Group undertaking basin studies in the Cooper, Bight-Duntroon and Otway Basins, with particular emphasis in the fields of geochemistry and burial history. He is also the current coordinator of the NGMA Cooper-Eromanga Project Team (comprising AGSO and Queensland, Northern Territory and NSW Departments of Minerals and Energy) developing a dynamic model for the generation and accumulation of hydrocarbons. He is a committee member of PESA (SA Branch).

Richard Hillis holds the State of South Australia Chair in Petroleum Reservoir Properties/Petrophysics at the National Centre for Petroleum Geology and Geophysics, University of Adelaide. He graduated BSc (Hons) from Imperial College (London, 1985), and PhD from the University of Edinburgh (1989). After positions at Flinders University, Adelaide, the British Geological Survey, Edinburgh, and the Department of Geology and Geophysics, University of Adelaide, Richard joined the NCPGG in 1999. His main research interests are in sedimentary basin tectonics and contemporary stresses in the oil patch. Richard is a member of AAPG, AGU, ASEG, EAGE, GSA, GSL, PESA and SEG. Rhodri Johns has a BSc from Manchester University and a PhD from Cambridge University. He has worked for Shell international in Holland and Brunei and for Sun International in the UK and in various European and African ventures. Since joining Santos in 1993 he has worked in the Corporate Exploration Review and Audit Department and currently holds the title of Manager Exploration Audit. Rhodri is a member of the AAPG, PESA, PESGB and the Geological Society of London. Alex Kaiko completed his PhD in 1998 at the University of South Australia and the NCPGG. During 1998 and 1999, he worked for Mobil Exploration and Producing Australia Pty Ltd as a consulting geologist. At the end of 1999 he joined the Centre of Petroleum Geology at Curtin University as a Research Fellow. His research interests include thermal and tectonic modelling, the application of combined fluorescence and reflectance to overcome vitrinite reflectance suppression problems and the application of organic geochemistry parameters to petroleum exploration. He is a member of PESA and the AAPG. John Kennard is a Principal Research Scientist in the Petroleum and Marine Division of AGSO. John obtained a Bachelor of Science (Honours) degree in Geology from the Australian National University in 1974, and a PhD in Carbonate Sedimentology from the Memorial University of Newfoundland, Canada, in 1989. John has undertaken sedimentological and petroleum studies of the Palaeozoic basins of central Australia (Georgina and Amadeus Basins) and the Upper Palaeozoic-Mesozoic basins of onshore and offshore northwestern Australia (Canning and Bonaparte Basins). John's current studies are focussed on the application of sequence stratigraphy to basin analysis and petroleum systems on Australia's northwest margin. He is a member of PESA and AAPG. Nick Lemon graduated with a BSc (Hons) in 1972 then worked for BHP Minerals for 10 years. Based in Whyalla, he worked in iron ore then coal/oil shale exploration. He returned to the University of Adelaide to take up PhD studies on sedimentation around active diapirs in the Flinders Ranges. He is now a Senior Lecturer at the National Centre for Petroleum Geology and Geophysics, concentrating on oilfield structure and reservoir petrology but still maintains a keen interest in the geology of the Flinders Ranges. Graham Logan graduated with BSc (Hons, Geology, University of Glasgow, 1988) and £ PhD (Organic Geochemistry, University of Bristol, 1992). After leaving the UK he worked at Indiana University on Proterozoic biogeochemistry for 3 years before joining CSIRO Petroleum in 1995. He joined AGSO in 1997 and worked on the involvement of organic matter in lead-zinc mineralization before joining the Southern Margin Frontiers project. He is a member of EAOG and ANZSMS and is an associate editor Geochemical Transactions. John Lindsay received his early education at the University of New England, in Australia before going on to graduate studies at The Ohio State University in Columbus, Ohio, USA. At Ohio State he was involved in Polar expeditionary work in Alaska, the Yukon and Antarctica. After graduation he joined NASA at the Johnson Space Centre where he took an active role in the Apollo Program in the late 1960s and 1970s. Following a sojourn with the Marine Science Institute of the University of Texas he moved to industry working with Exxon Production Research in Houston, Texas. In 1984 he returned to Australia after 20 years in the abroad to join the Australian Geological Survey Organisation in Canberra. He is now with the Research School of Earth Sciences at the Australian National University. John is a soft-rock geologist with considerable experience in seismic stratigraphy and an interest in large-scale basin analysis problems. His main research interest at the present time is in intracratonic basins and in the use of stable isotopes as an aid to understanding their evolution. Paul Lipski is a petroleum geologist with 17 years' industry experience. He has worked in a variety of exploration and production companies in Sydney, Perth, Calgary, and Brisbane. Paul currently works for Magellan Petroleum in Brisbane, where he is exploration supervisor. Although much of the exploration focus is now on the North West Shelf and Cooper Basin areas, Magellan has historically been linked to the early exploration of the Amadeus Basin, and more recently, frontier areas such as the onshore Maryborough Basin and the Ngalia Basin.

Brian McGowran is an Associate Professor in the Department of Geology & Geophysics, The University of Adelaide. His main fields of interest are biostratigraphy and earth and life history. He worked as a micropalaeontological consultant in petroleum and other exploration in Australia, Papua New Guinea and Indonesia, and was Head of Palaeontology in the Geological Survey of South Australia for several years. He has been at the University of Adelaide for three decades but has held academic positions at the University of Vienna and Princeton University. His recent research has been in the Cainozoic stratigraphy and environments of southern Australia, including the place of the neritic realm-its strata and fossils, environments and evolutionbetween the oceanic realm and the terrestrial realm. Results and reviews have been presented in forums as diverse as regolith and minerals exploration, rainforest biology, marine geology and deep-ocean drilling, vertebrate palaeontology, and basin exploration. He believes strongly in the autonomy of his scientific disciplines: thus, geology is more than a strange subset of basic sciences; palaeontology is more than a kind of imperfect biology; and the earth sciences underpin not only minerals and fuels exploration but also the environmental sciences. David McKirdy is a graduate of the University of Adelaide (B.Sc. Honours, M.Sc.) and the Australian National University (Ph.D.). Since 1970 he has held positions with the Bureau of Mineral Resources, the South Australian Geological Survey, Conoco, Inc., and AMDEL Ltd. In 1987 he returned to the University of Adelaide, where he is now an associate professor undertaking research in the fields of source rock and petroleum geochemistry, isotope chemostratigraphy, and in the use of organic geochemistry as a tool in basin analysis. He is a member of the Geochemical Society, European Association of Organic Geochemists, Geological Society of Australia, and Petroleum Exploration Society of Australia. Aidan Moore received an honours degree in Geology from Trinity College, Dublin University, in 1961, and an MA from the same university in 1976. After working as a seismic interpreter and prospect generator for oil exploration operators in the British Isles, West Africa and Australia he joined the Australian Geological Survey Organisation in 1987. Since then he has worked on the assessment of basin histories, structure and hydrocarbon prospectivity around the continental margins of Australia and in areas of the Philippines and Melanesia . Currently he is engaged in geological mapping of the Australian offshore territories in the Law of the Sea project. Member Petroleum Exploration Society of Australia (PESA) David Moore (BSc, Australian National University, 1968) is a Senior Geophysicist with the Minerals and Petroleum Branch of the Victorian Department of Natural Resources and Environment. He has had a varied career, mostly in the minerals sector, working for both government and industry. Over the last 10 years, both with BHP and with the Minerals and Petroleum Branch, he has interpreted potential field data in ways that are both geologically and geophysically reasonable. His most recent project has been to interpret the Gippsland Basin basement. Before this he was joint author of the 1:1 000 000 Pre-Permian Geology map of Victoria. He is a member of GSA, ASEG, AIG and PESA. Geoffrey O'Brien is the Research Group Leader of the Marine Environment and Regional Basin Studies Program with the Petroleum and Marine Division (PMD) of the Australian Geological Survey Organisation (AGSO. His present work is focussed upon the application of multi-disciplinary research strategies to basin evaluation on the Australian margin. Dr O'Brien has previously worked for BHP and for Western Mining Corporation. He is a member of PESA (PESA Australian Lecturer, 1992), AAPG and AGU. Tony Stephenson is currently a Principal Research Scientist in AGSO, where he leads the Basin Evaluation Project. He had various petroleum-related roles within the Bureau of Resource Sciences from 1991-98, and prior to that was with the Bureau of Mineral Resources from 1981-91 working on the Murray Basin and petroleum resource assessment, and in the mineral exploration industry from 1977. Howard Stagg graduated from the University of Queensland in 1974 with a B.Sc. App. (Geophysics, Honours) degree. He is a Principal Research Scientist in the Petroleum & Marine Division of the Australian Geological Survey Organisation. He has worked on the northwestern and southern Australian margins, offshore Antarctica, Kerguelen Plateau and Lord Howe Rise, and is currently working of geological framework studies in the Law of the Sea Project. He is a member of PESA and GSA.

Heike Struckmeyer is a Senior Research Scientist in AGSO's Petroleum and Marine Division. She graduated from the University of Gottingen, West Germany, in 1981 and received a PhD from the University of Wollongong, NSW, in 1989. Heike is the Area Leader of AGSO's newly formed West and Southwest Regional study group. Since joining AGSO in 1988, her work has been focused on the evolution of Australia's northern, northwestern and southern margins, and on regional basin analysis. In particular, she has worked on projects on the Townsville Basin, the Northern Carnarvon Basin, the Timor Sea, the Browse Basin, the Roebuck Basin and, more recently, the Great Australian Bight. Heike was the project leader of AGSO's former Southern Margin Frontiers project. She is a past-President of the PES A ACT Branch, and is also a member of GSA. Xiaowen Sun graduated with a BSc (Hons) from the Nanjing University in 1982, and then obtained a MSc from Nanjing Institute of Geology and Palaeontology, Academia Sinica, China, and a Ph.D. in Geology and Geophysics from the National Centre for Petroleum Geology & Geophysics in 1997. Xiaowen has since been undertaking several projects sponsored by the Petroleum Group of the South Australian Department of Primary Industries (PIRSA) for more than 3 years, working on fractured reservoir studies of the Warburton and Cooper Basins, and revision of boundaries between the Warburton and overlying Cooper and Eromanga Basins, and electrofacies of the Cooper Basin. She has extensive training and experience in petroleum exploration, specialising in Early Palaeozoic basin studies, sequence stratigraphy, sedimentology and structures, and naturally fractured reservoirs. In November, 1999, she established a geological consultancy - Sun Petroleum Geoservices. Philip Symonds graduated from the University of Tasmania with a BSc (Hons) in geophysics in 1970, while a Cadet Geophysicist with the then Bureau of Mineral Resources (BMR). He joined the Marine Sub-section of BMR's Geophysics Division in 1971 and is now a Principal Research Scientist in the Petroleum and Marine Division of AGSO. He has been involved in research programs over most parts of the Australian margin and is currently project leader of AGSO's Law of the Sea project, which has responsibility for defining the outer limits of Australia's seabed resource regime. He is an Australian government's adviser on technical matters related to seabed boundary definition and the Law of the Sea. He has been a UN technical expert on the definition of the Continental Shelf, Chairman of the Australian Ocean Drilling Program Scientific Committee and the Australian/Canadian member of the JOIDES Tectonics Panel. Philip is a member of PES A Jennie Totterdell is a senior geologist in AGSO's Petroleum and Marine Division. She holds a BSc in Geology from the Australian National University. Jennie's work at BMR/AGSO has included studies of the Palaeozoic palaeogeographic evolution of Australia, basin analysis and resource (hydrocarbon and coal) potential of Australia's eastern onshore basins (particularly the Bowen-Gunnedah and Surat basins), and basin analysis projects in the Browse and Roebuck basins. Her work is currently focused on the depositional and structural evolution of the basins of the Great Australian Bight. Jennie is a past-Secretary of the PES A ACT Branch a member of GSA. Les Tucker joined the South Australian Department of Mines and Energy (now Pirsa) in 1980. He has been involved in basin studies in the Cooper, Officer, Pedirka, Arckaringa and Stansbury Basins. He holds an associate diploma in geo-science and is currently studying for a B.App. Sc. in Environmental Management at the University of South Australia. Sabrina Van de Beuque holds a PhD in Marine Geology from the University of Brest (1999) and completes a post-doct, supported by IFREMER and ZoNeCo program, at AGSO in the Law of the Sea Project, Petroleum and Marine Division. She is involved in the FAUST joint project (French Australian Seismic Transect). Her work is focussed upon seismic interpretation of the northern Lord Howe Rise and of the North Norfolk Basin. Mike Woollands received both a BSc. in geology (1964) and PhD. in stratigraphy and sedimentology (1970) from the University of London, University College. He worked as an exploration geologist with Shell in Holland, Libya and Norway from 1967 to 1974. He subsequently held geological and exploration team leader positions with BP in Southeast Asia, Australasia and U.K. North Sea from 1974 to 1982. Emigrating to Australia in 1982, he became an exploration manager for BHP Petroleum with responsibility at different times for Western Australian operations, regional evaluations and acreage acquisition in the Australian and Asian New Ventures Groups. Since 1997 he has been Manager Basin Studies in the Petroleum Development Unit of the Department of Natural Resources and Environment in Melbourne. His interests cover basin evaluations and petroleum systems, particularly in clastic depositional regimes. He is a member of PESA, AAPG, GSA and a Fellow of the Geological Society of London.

David Wong is a Senior Petroleum Explorationist with Victoria's Department of Natural Resources and Environment. He received his BSc Honours degree in applied geology from the University of Malaya, and undertook postgraduate studies in basin evaluation with ESRI, University of South Carolina. He is currently enrolled in a part-time MSc-program at Monash University studying the Sherbrook Group of the Port Campbell Embayment and Sherbrook Trough, eastern Otway Basin. He has worked in Australia and SE Asia for BHP, WMC Petroleum, Sun International, Hall Houston, Petronas and various independents in evaluating exploration permits as well as in exploration and development operations roles. He is a member of PESA, AAPG and GSM. Xinke Yu received his B.Sc. degree in organic chemistry from Lanzhou University (China), an M.Sc. degree in organic geochemistry from the Chinese Academy of Sciences (CAS). Since 1988, he has held positions with the CAS, and is currently studying at the University of Adelaide for a PhD degree in organic geochemistry. Wenlog Zang received his PhD degree from the Australian National University in 1989. His researches have involved the study of the Amadeus, Georgina, Arrowie, Stansbury and Officer Basins in Australia and Neoproterozoic - Cambrian stratigraphy in China. Currently he is employed by PIRSA and mapping on Yorke Peninsula and Stansbury Basin.