WABS 3 symposia

The Sedimentary Basins of Western Australia 3

Edited by M. Keep & S. Moss

Contents

• Introduction
• Regional Geology
• of the North West Shelf
• Stratigraphy and Palaeontology
• Geochemistry and Fluids
• Timor Sea
• Carnarvon Basin
• Canning Basin
• Perth Basin
• Onshore Basins
• Poster Abstracts

Borehole image log interpretation: making the most of your data and understanding its limits; an illustration using shallow and deep marine, fluvial, and carbonate depositional environments
A.A. Bal , K.A.A. van Noord, P.V. Grech & J.D. Prosser

Tidally influenced deposition on the delta plain: Lower Cretaceous Barrow Group sandstones, Barrow Sub-basin, Northern Carnarvon Basin
A.J. Bond, N. Mader, F.E. Burns, M. Thompson & A.D. George

Revised tectonic evolution of the North West Shelf of Australia and adjacent abyssal plains
C. Heine, R.D. Müller & M. Norvick

Restoration of a Deepwater profile from the Browse Basin: Implications for structural-stratigraphic evolution and hydrocarbon prospectivity
K.C. Hill & N. Hoffman

Diagenesis impacts fluid pressures, reservoir quality, and seal integrity of deep Jurassic targets, Norwegian Sea
J.C. Matthews & H.M. Helset

The tectono-stratigraphic history of the northern margins of the Australian Plate from the Carnarvon Basin to Papua New Guinea
M. S. Norvick

Application of K/Ar and Rb/Sr geochronology to constrain the timing of sedimentary deposition and diagenesis: preliminary results from Western Australian basins
H. Zwingmann & B. Hatcher

Historical perspective of hydrocarbon volumes in the Westralian Superbasin – Where are the next billion barrels?
E. Kopsen

Abstract
The Northern Carnarvon Basin and the Northern Basins (Browse and Bonaparte basins, including the Vulcan Sub-basin) within the Westralian Superbasin have each now been tested by around 400 new field wildcat wells. The P50 (proven and probable) reserves and resources in the Carnarvon currently amount to some 96 trillion cubic (TCF) of gas, 1.8 billion barrels (BBO) of oil
and nearly 1.5 billion barrels (BBC) of condensate. In comparison, the Northern Basins presently account for around 61 TCF of gas, 1.6 BBC and just 1/2 a BBO.

A clear pattern of discoveries has been recognised over many years with huge gas/ condensate fields lying in the outer basin platform areas bounding deep Mesozoic hydrocarbon kitchen areas and more liquids-prone fairways in inshore areas.

An important liquids-rich component of the resources occurs through the aborted Jurassic rift centre (Central Fairway) and these areas are still quite under-explored. Further exploration through the Inner Fairway in the Northern Basins and in the Central Fairway areas should yield significant liquid reserves additions.

Important trends have emerged over the last decade, namely:
• New Northern Carnarvon Basin discoveries in reservoirs sealed by formations older than the Muderong Shale regional seal.
• The emergence of the Exmouth Sub-basin as a significant new oil province with surprisingly little gas reserves in the total hydrocarbon mix.
• New large gas/condensate discoveries made in the Central Fairway of the Browse Basin, details of which remain scant.

The industry is also confronted by anomalies in the exploration record that still remain unresolved:
• The commercially unsuccessful exploration track record in the Vulcan Graben where prime Upper Jurassic marine source rocks have expelled around nine billion barrels of oil from just two small grabens.
• Limited success of the Echuca Shoals petroleum system in the Northern Basins, particularly in the Browse Basin.
• No commercial production and few oil recoveries from offshore Palaeozoic reservoirs in the region, despite frequent oil shows.
Nevertheless, the last decade has seen dramatic growth of hydrocarbon reserves and resources through exploration
drilling on the Westralian Superbasin and the creaming curves for the region show no clear signs of "tailing-off". This is a healthy sign for future new field discoveries even though the discovery index, a measure of exploration success per metre drilled, has fallen away in the most mature basin, the Northern Carnarvon Basin.

Abstract
Petroleum exploration activity in Western Australia, boosted by the positive results of many new discoveries, is continuing at a high level. Recent exploration has focussed primarily on the North West Shelf but with significant exploration in frontier areas offshore and onshore. Significant discoveries in 2001/2002 resulted from further exploration in previously explored areas in the Carnarvon and Perth basins, as well as a new play offshore in the Perth Basin. The short-term outlook for Western Australia is good as a result of existing work commitments including an average of 43 exploration wells to be drilled each year for the next three years. Onshore, where exploration has been subdued, there are signs of a pick up in activity, particularly in the Perth Basin following recent discoveries. The Western Australian Government is playing a key role in promoting petroleum exploration in the State through gazettals, promotional activities – conferences and publications, acquiring pre-competitive data and making petroleum data more accessible. The Government-funded Petroleum Exploration Initiatives programme is continuing and efforts are being made to facilitate exploration. Sustained high oil prices, improvements in technology and efforts to expedite access to land are just some of the factors that will assist companies in their endeavours. In the longer term, continued growth in Western Australia's petroleum industry is projected, in particular as some of the huge offshore gas resources are brought to commercialisation.

The North West Shelf of Australia - a Woodside Perspective
I.M. Longley, C. Buessenschuett, L. Clydsdale, C.J. Cubitt, R.C. Davis, M.K. Johnson, N.M. Marshall, A.P. Murray, R. Somerville, T.B. Spry, & N.B. Thompson

Abstract
The North West Shelf of Australia is a world class gas province with minor oily sweet spots. It is a marginal rift with pre-rift Permo-Triassic intracratonic sediments, overlain by Jurassic to Cainozoic syn- and post-rift successions. These were deposited in response to rifting and seafloor spreading of at least three continental blocks in Oxfordian, Tithonian and Valanginian times. Rifting was initiated in the central Argo area in the Oxfordian. In Tithonian times, the rifting jumped to the north of Timor (where the spreading record has been subsequently subducted), then in the Valanginian it moved to the southern Cuvier area. This break-up history produced a complex spatial and temporal distribution of rift and post rift deposits, which strongly control the efficiency and liquid hydrocarbon potential of the margin's petroleum systems.

Since exploration drilling commenced in 1953, some 754 exploration wells have been drilled (at Dec 2001), discovering estimated reserves of 2.6 billion bbls of oil, 2.6 billion bbls of condensate and 152 Tcf of gas within 233 hydrocarbon fields. Most of the successful traps comprise sands within rift-related horsts and tilt blocks, or sands within overlying drape structures. Almost all (97%) of the margin's resources are reservoired beneath the (dominantly Cretaceous) regional seal. Other more complex traps have been rarely successful, in general the margin offers little encouragement for stratigraphic entrapment due to the sandy section beneath (and above) the regional seal.

The dominance of gas (84% by boe) is due to the quality, and often the high maturity, of the source rocks within all identified hydrocarbon systems. Rare oil-prone source rocks are present, but their effectiveness in producing economic oil-fields relies on protection from gas flushing, and/or biodegradation or the selective loss or separation of the dominant gas charge via fault leakage or water washing. Effective oil source rocks are found locally within mainly Jurassic pre- and syn-rift deltaic, or syn-rift marine settings, within partially restricted depositional settings, whereas sediments deposited in open marine environments are typically lean and gas-prone.

The extensive coverage of 3D seismic acquired in the late 1990s over the 'oily' portions of the margin has not resulted in large exploration successes. This is due to the simple effective traps at base regional seal level being beneath the amplitude floor and had been previously identified with 2D data. Small traps were identified by 3D in these areas, and these discoveries will be developed as infrastructure matures, and economic thresholds decrease.

Some 119 Tcf of gas reserves remain undeveloped, together with an estimated 1400 mmbbls of potential condensate reserves. The future of the North West Shelf hydrocarbon province largely lies in developing these resources and exploring for traps surrounding the future infrastructure. The province is still under-explored by global standards, especially outside of proven oily areas, where large potential volumes remain in untested deepwater Mesozoic basins, and inboard poorly explored Palaeozoic basins.

The North West Shelf of Australia provided the initial growth platform for Woodside, and Woodside will continue to be committed to further significant exploration in the province. With vast discovered, but undeveloped, gas reserves, Woodside is focussed on developing existing gas reserves, whilst continuing exploration for oil. However, the low probability of discovering a new oily sub-basin, simple trap geometries, gassy charge and the poor record of 3D seismic in proven oily areas, creates a challenge to compete for exploration funds for oil exploration on the North West Shelf when compared against global oil opportunities.

Similarities and differences in the tectonics of two passive margins: the Northeast Atlantic Margin and the North West Shelf
A.G. Doré & I. Stewart

Abstract
The Northeast Atlantic margin (NEA) and the Australian North West Shelf (NWS) are both well-known passive margins, and have much in common in terms of size, orientation, water depth and economic importance. Comparison of their tectonic histories highlights issues that may have general significance for passive margins. In global kinematic terms the NEA and NWS were linked by the fragmentation of Pangea and the closure of Tethys. The NWS occupied an exterior position in Pangea and underwent a succession of extensional episodes, each one leading to break-up of a portion of the extended terrane. In contrast, the NEA occupied an interior position and break-up occurred after several failed rift episodes, the evidence for which is preserved on both sides of the young ocean. Despite these factors and a ca. 80 million year difference in plate tectonic maturity, there are remarkable evolutionary similarities between the margins. These include segmentation of the margin by diffuse NW-SE transfer zones, transition of some segments from shear margin to passive margin during early spreading, and pre-break-up volcanism. The detachment of microcontinental strips is also characteristic of both areas, and may be a paradigm for stretched passive margins during plate reorganisation.

Both margins are dominated by a NE-SW extensional "super-basin", with a sedimentary fill dominated by Permo-Triassic on the NWS and Cretaceous on the NEA. Both strongly overprint older basement and basin fabrics. Reactivation of faults occurs in both areas and there is a common assumed connection between basin development and basement substructure. However, direct evidence for this link is surprisingly difficult to find and requires systematic work to be properly substantiated. On both margins, depth-dependent extension models have been invoked to explain disparities between upper crustal extension and thermal subsidence during rifting. This phenomenon appears to be typical of passive margins at time of break-up, and is being documented in an increasing number of passive margins worldwide.

Volcanism associated with the Iceland mantle plume was a major feature of Paleocene-Eocene break-up in the NEA, perhaps the world’s best-known volcanic margin. The Oxfordian-Valanginian volcanism on the Argo, Cuvier and Gascoyne margins was of a somewhat lesser scale and was not associated with the widespread permanent uplift typical of NW Europe. Rapid finite rate extension, and/or depth-dependent extension may explain excessive melt production on the NWS. However, both the wide range of common phenomena and the plate tectonic setting suggest that plume models should still be strongly considered. Characterising the heat input associated with break-up rifting and volcanism is a key issue for maturation modellers on these and other passive margins.

The thick rift-sag successions on both margins underwent compressive reactivation during the Cenozoic, but both cause and effect were different. Inversion on the NWS was caused by oblique continental collision and distributed transtension and transpression along the length of the margin. On the NEA it was caused by forces orthogonal to the margin, probably attributable to ridge push. The implication of different types of inversion for hydrocarbons preservation is a particularly fertile field for comparative study.

The NWS and NEA both host multiple source rocks. The most important are syn-rift Jurassic mudrocks, a global supersource related to an important phase of Pangean break-up. On the whole, source rocks are more gas-prone on the NWS. In both areas, oil systems are more prevalent in inboard rift basins while gas dominates in the deeper water areas. On the NWS, this transition is due to absence or immaturity of the Jurassic in outboard areas allowing the system to be dominated by older, gas-prone source rocks. On the NEA it is due to Cretaceous Similarities and differences in the tectonics of two passive margins: the Northeast Atlantic Margin and the Australian North West Shelf subsidence and deep burial of the Jurassic. Continued exploration of the deep water NEA will probably favour the discovery of gas, bringing the oil-gas balance more in line with that of the NWS.

Geohistory of the NW Shelf: a tool to assess the Palaeozoic and Mesozoic motion of the Australian Plate
G.D. Borel & G.M. Stampfli

Abstract
The Phanerozoic motion of the Australian plate was compared with the geohistory of the North West Shelf of Australia, combining stratigraphic, sedimentary and palaeontological data from 42 wells drilled offshore and onshore along the North West Shelf. This analysis shows stepwise tectonic subsidence curves reflecting a succession of rifting events and uplifts, and allows tectonic and thermal subsidence events to be distinguished.

The latitudinal plate motion was derived from global palaeo-plate reconstructions integrating plate tectonic constraints such as ocean spreading rates, plate buoyancy, and dynamic plate boundaries. Latitudinal motion, velocity and rotation of the Australian plate were calculated using virtual palaeo-poles derived from these reconstructions.

The Late Devonian extensional faulting event can be correlated with a rapid southward drift of the Australian plate. The Late Carboniferous-Early Permian opening of Neo-Tethys corresponds to the shift in drift direction from south to north. The Triassic Fitzroy movement is linked with the closures of Palaeo-Tethys and the evolution of the Bowen Basin. Jurassic rifting of the Argo Abyssal Plain is probably a consequence of a rotation of the plate.

Tertiary Foundations and Quaternary Evolution of Coral Reef Systems of Australia's North West Shelf
L.B. Collins

Abstract
The North West Shelf is a modern tropical ramp, which is underlain by Cretaceous-Tertiary carbonates, with clastic reservoirs at depth. Coral reef systems, discontinuously developed during the Late Tertiary-Quaternary, vary from fringing reefs to isolated reefs which rise from deep-ramp settings. Quaternary evolution of the reef systems is being documented using regional mapping, seismic imaging, coring and U-series dating. The well-constrained sea level data from the Houtman Abrolhos carbonate platforms (at 28-29°S) have also been applied to the North West Shelf reefs. The Ningaloo fringing reef at 20-22°S, records Holocene and Last Interglacial phases of reef growth in a tectonically stable environment. It overlies Tertiary carbonates of the Cape Range, which is flanked by uplifted Plio-Pleistocene terraces and reefs. Scott Reef (at 14°S) is a macrotidal, isolated reef which overlies a carbonate platform and a major gas discovery. Seismic profiles reveal a Last Interglacial (ca.125,000 year) reef system, but reefs which apparently grew to sea level are 30 m below present sea level, indicating significant subsidence in the Late Quaternary. Contemporary reefs grew during the Holocene in the accommodation space provided by subsidence and are up to 35 m thick. The Rowley Shoals (15-17°S) comprise one of the most perfect morphological series of reefs known, and these emergent, annular reefs rise from depths of 200-400 m. Seismic profiles suggest Late Quaternary subsidence has been an important control on reef growth, while differential subsidence has influenced reef morphology.

The spatial association between reef systems and hydrocarbon seeps and the reservoir potential of the Tertiary section are now receiving attention. As further exploration and development occur in and around coral reefs, and the level of management intensity increases, there is a need for better understanding of human and natural impacts (cyclones and coral bleaching), biological processes, and the geological controls on reef growth and development, as part of management plans.

Documentation and Refinement of the Middle to Late Cretaceous Calcareous Nannofossil and Foraminiferal KCCM Zonation
R.J. Campbell, R.W. Howe, J.P. Rexilius, & C.B. Foster

Abstract
Petroleum companies operating on the North West Shelf typically employ the composite calcareous microfossil (KCCM) zonation to correlate middle to Upper Cretaceous strata. This zonation combines both calcareous nannofossil and foraminiferal biostratigraphic events to provide high-resolution biostratigraphic subdivisions and correlation. The zonation was locally developed to overcome problems in the application of the standard (Tethyan) schemes, caused by biogeographic differentiation of Cretaceous nannofossil and foraminiferal assemblages. Examination of the Maastrichtian – uppermost Campanian interval has: i) identified new nannofossil and planktonic foraminiferal events, including the highest occurrences (HO’s) of Petrarhabdus vietus and Stoverius sp. 1, and the lowest occurrences (LO’s) of Pseudotextularia intermedia and Racemiguembelina powelli; ii) shown that the LO of Abathomphalus mayaroensis predates the LO’s of Racemiguembelina fructicosa and Contusotruncana contusa thus redefining KPF Zones 1 and 2; and iii) indicated the presence of a Lower Maastrichtian disconformity/condensed section on Exmouth Plateau and to a lesser extent the Vulcan Sub-basin. Documentation and refinement of the hitherto unpublished KCCM zonation is important for consistent well correlation on the northwestern Australian margin, higher resolution biostratigraphy, and more accurate correlation to the international chronostratigraphic scale.

Conodont biostratigraphy and palaeogeography of the Triassic on the western, northwestern and northern margins of the Australian Plate
R.S. Nicoll

Abstract
In the Triassic the northern margin of Gondwanan Pangea opened onto the Meso-Tethys Ocean. The then continental margin was formed by the Lhasa and West Burma Blocks and the New Guinea portion of the Australian Plate. Along what would become the margin of the Australian Plate were a series of cratonic basins, from the Perth Basin in the south, through the Bonaparte Basin to poorly defined Triassic basinal structures on islands of the Banda Arc. Only along the northern margin of present-day New Guinea and some of the islands of the Northern Banda Arc did continental margin shelf areas open directly onto the Meso-Tethys Ocean. Within this setting Triassic sediments were deposited in tectonically controlled basins. Conodonts and other fossils are beginning to allow high-resolution correlation of sedimentary sequences and events within and between these basins.

Palynological zonation and correlation of the latest Triassic, Northern Carnarvon Basin
J. Backhouse, B.E. Balme, R. Helby, N.G. Marshall & R. Morgan

Abstract
A revised palynological zonation for the latest Triassic (Norian-Rhaetian) of the North West Shelf is presented. The definition of the Ashmoripollis reducta Spore-pollen zone is modified and three subzones are recognised within both the Minutosaccus crenulatus and A. reducta Zones. The Rhaetogonyaulax rhaetica and Dapcodinium priscum Microplankton zones are each sub-divided into two subzones. Five significant palynofloral modifications, called Major Bioevents, are identified and are used to construct a scheme for high-resolution correlation on the Rankin Platform. In addition, seventeen informal biostratigraphic units, referred to as Tr units, are erected.

A range of swamp palynofacies associations, interspersed with floodplain, channel and oxidised palynofacies characterise the M. crenulatus Spore-pollen zone. A marine incursion, represented by the H. balmei Microplankton zone, is associated with swamp facies below, and a brief return to swamp facies above. A blocky sandstone unit, the E unit of Woodside Energy Ltd, is developed above the H. balmei Zone on the Rankin Trend, and represents brackish-marginal marine, or channel palynofacies without dinocysts. The return of marginal marine deposition at the base of the A. reducta Spore-pollen zone (= base R. rhaetica Microplankton zone) also marks the base of the Brigadier Formation. Within the Brigadier Formation horizons with common dinocysts are interpreted as flooding surfaces.

The Triassic-Jurassic boundary is placed at that of the A. reducta and Corollina torosa Spore-pollen zones. A fundamental change in spore-pollen assemblages occurs at this horizon, demonstrating a significant regional palaeofloral event, and probably indicating a disconformity.

Trace Fossils as Tools in Glauconitic Reservoirs: Examples from the Lower Cretaceous of the Carnarvon Basin, North West Shelf
F.E. Burns

Abstract
Trace fossil analysis is a key tool in the understanding of reservoir heterogeneity within the glauconitic Lower Cretaceous strata of the Carnarvon Basin. Twelve wells with core through the M. australis and Mardie Greensand intervals in the Stag Field and Chervil area constitute the dataset for this study. The M. australis sandstones in the Stag Field represent deposition within a wave- and storm-influenced, lower shoreface to inner shelf setting of intermediate wave energy. The proximal lower shoreface is characterised by laminated and partially bioturbated sandstones, with mottled and Ophiomorpha-Skolithos ichnofabrics dominant. The highest diversity trace fossil assemblages occur within the highly bioturbated distal lower shoreface sandstones. 'Teichichnus zigzag'-, Rhizocorallium- and Palaeophycus-dominated ichnofabrics are abundant, characteristic of bioturbation at fairweather wavebase. Inner shelf strata are characterised by variable degrees of bioturbation, with muddy heterolithics displaying low degrees of bioturbation alternating with highly bioturbated sandstones. Teichichnus-, Palaeophycus- and Planolites-dominated ichnofabrics are characteristic of these strata. Claystones deposited on the outer shelf are reworked by sparse bioturbation dominated by Chondrites and Zoophycos.

In the Chervil area, the Mardie Greensand is dominated by highly to intensely bioturbated, glauconitic sandstones, representing deposition within an inner and outer shelf setting. Significant stratal surfaces are recognised through concentrations of Skolithos, Diplocraterion habichi and Thalassinoides. At both flooding surfaces and downshift surfaces these firmground burrows cross-cut the background softground ichnofabrics, are differentially cemented, and often contain coarse sand and pebble grade material, all suggesting that colonisation took place at a sediment starved surface (i.e. omission surface).

Sharp-based, quartz-rich sandstones are present in the Stag and Chervil areas. The presence of primary stratification, the dominance of Ophiomorpha and their abrupt juxtaposition over inner shelf strata indicate deposition during forced regression.

Abstract
Correlations of the Permian sequences for sixteen regions of north eastern Gondwana during the Permian are presented in this review. These correlations are compared with Permian sequences of the Australian continent. Broad conclusions on palaeoclimatic change and tectonic events are summarised for six time intervals of the Permian Period.

The Asselian-Sakmarian-early Artinskian time interval indicates a change from cold to temperate depositional environments. Glacial deposits and low diversity Gondwanan marine faunas are succeeded by younger, warmer water, clastic and bioclastic sequences with moderately diverse marine faunas. Deposition of these sequences is occasionally associated with basaltic volcanism and initial rifting of the peripheral northern Gondwanan margin.

During the Late Artinskian-Kungurian (including Early Ufimian) time interval, climate amelioration occurred with the onset of carbonate deposition in several Cimmerian terranes. Basaltic volcanism in several terranes is indicative of significant rifting and the opening of the Meso-Tethys.

The Roadian (Late Ufimian) and Wordian-Capitanian (including Kazanian-Midian) time intervals were characterised by widespread, subtropical, marine carbonate depositional sequences. These occurred throughout the Cimmerian blocks as they drifted northward and on the more northerly parts of the Meso-Tethyan southern margin. These transgressive sequences may rest on significant unconformity surfaces. Equivalent carbonate units are known in the offshore and subsurface sequences of western Australia. Andesitic, convergent plate margin volcanism and volcaniclastic sequences are present in eastern Australia.

The Wuchiapingian time slice is characterised by widespread marine transgressions which extended into the north western basins of Australia.

The Changhsingian time slice is represented by relatively minor marine transgressive events in the Trans-Himalaya with the Selong section of Tibet being probably the most complete Permo-Triassic sequence for the southern margin of the Meso-Tethys.

Development of a Solid-Phase Biodegradation Assay for Drilling Fluids Under Tropical Conditions
J. Woodworth, L. Evans & Y. Tsvetnenko

Abstract
The presence of cuttings piles containing high concentrations of drilling fluids are of concern on the North West Shelf of Western Australia, as drilling fluids have the ability to persist in the environment. Previously, several types of aerobic and anaerobic assays have been used to obtain comparative rates of biodegradation of drilling fluids. Most of these laboratory-based biodegradation assays utilise an aqueous media. However, a method which determines absolute biodegradation rates of drilling fluids using a solid-phase media is considered to be more representative of conditions on the sea floor surrounding drilling operations and within the cuttings piles.

This paper discusses the results gained from MERIWA Project M290 to develop a solid phase biodegradation assay to demonstrate the biodegradation rate of synthetic drilling fluids that are used on the North West Shelf. The half-lives of six drilling fluids (four ester, one iso olefin and one paraffin) were determined by adding the base fluids to a solid-phase matrix then inoculating with both anaerobic and aerobic bacteria and incubating in flow-through sea water at 24°C in the dark. The half-lives varied between esters, ranging from 15 days to 57 days at initial concentrations of 100 ppm. The half-lives calculated for the paraffin and iso olefin base fluids at 100 ppm were 35 and 20 days respectively. In all treatments the half-lives increased with increasing concentrations.

Use of aromatic compound distributions to evaluate organic maturity of the Proterozoic middle Velkerri Formation, McArthur Basin, Australia
S.C. George & M. Ahmed

Abstract
The middle Velkerri Member is a rich Proterozoic source rock in the McArthur Basin. A decrease in hydrogen index from > 500 mg pyrolysate/g TOC in shallow immature sediments to around 150 mg/g in deeper sediments has been suggested to coincide with the main oil generation window. Thermal maturity in Proterozoic rocks can not be determined by conventional vitrinite reflectance, because these ancient sediments predate the evolution of the land plants. The uniform nature of the organic matter type in these rocks suggests that molecular maturity parameters may be useful. Aromatic hydrocarbon fractions were isolated from middle Velkerri rocks in three McArthur Basin wells (Walton 2, Shea 1 and McManus 1), covering a wide maturity range and forming a composite depth section. Maturity-sensitive ratios based on alkylnaphthalenes, alkylphenanthrenes, alkylbiphenyls, and alkyldibenzothiophenes have been calculated.

The aromatic ratios best suited for examining variations throughout the oil window in the Mesoproterozoic sediments of the McArthur Basin are the alkylphenanthrene ratios, in particular the methylphenanthrene index and the methylphenanthrene distribution fraction, which are sensitive to maturity variations at least from the initial phase of oil generation to the late oil window. Some trimethylnaphthalene and tetramethylnaphthalene ratios are sensitive to maturity variations in the early oil window, but then reach equilibrium, whereas alkylbiphenyl ratios are sensitive to maturity variations in the peak to late part of the oil window but show little change at lower maturities. Application of the liquid reaction environment concept (van Aarssen et al., 2000) suggests that the middle Velkerri Member in Shea 1 and McManus 1 has or had oil generation potential, consistent with the aromatic hydrocarbon ratios that suggest maturities in the oil window or above. The middle Velkerri Member in Walton 2 has a less well developed liquid reaction environment, consistent with the lower maturities in this well. An igneous intrusion in the upper Velkerri Member that has now been eroded is inferred to have locally raised the maturity of the upper part of the middle Velkerri Member in Walton 2.

Hydrocarbon accumulation processes in the Dampier Sub-basin as revealed by polar compounds
T.P. Bastow, B.G.K. van Aarssen, R. Alexander, R.I. Kagi & K. Liu

Abstract
Hydrocarbon accumulation processes in the Kendrew Trough system of the Dampier Sub-basin were investigated using phenols and carbazole abundance in crude oils. Crude oils were placed into two groups based on the relationship between phenols and carbazole. High phenols and carbazole concentrations were observed in crude oils that were close to the major depocentre areas, which we suggest is related to relatively short migration distances. The results indicate that these parameters are useful for reconstructing migration pathways and distinguishing different crude oil sources.

Applications of methylated naphthalenes: Resolving mixtures of crude oils
B.G.K. van Aarssen, T.P. Bastow, R. Alexander & R.I. Kagi

Abstract
The relative abundances of methylated naphthalenes present in crude oils provide an excellent tool for resolving crude oils that result from in-reservoir mixing of two or more charges. This is especially significant when the mixture consists of two non-biodegraded oils of significantly different maturity levels, or when one of the components is biodegraded. Depending on the level of biodegradation, the methylated naphthalenes can give insight into the level of maturity of the original oil. In this study four cases are presented, highlighting different mixing scenarios.

Estimating formation water salinity from wireline pressure data: Case study in the Vulcan Sub-basin
J.R. Underschultz, G.K. Ellis, A. Hennig, E. Bekele & C. Otto

Abstract
Characterising the concentration of total dissolved solids (TDS) in formation water is important for wireline log analysis, reserves calculations, and understanding the hydrodynamic processes occurring in the subsurface. Unfortunately, measured TDS values from formation water samples are scarce and subject to poor sampling conditions and contamination. Water analysis data can be supplemented with wireline log-derived salinity estimates but uncertainty in these arise from assumptions required in the calculation method. There is a need to define a method for estimating formation water salinity that does not require a water sample and is independent from wireline log analysis.

An alternative approach is to estimate formation water salinity from wireline pressure data. Within a single aquifer, the pressure gradient at any specific geographic location is related to the density of the formation fluid. The formation water salinity is calculated from density, temperature and formation pressure. The calculated water salinity is for in-situ conditions and is unaffected by drilling fluid invasion. Results from this method compare favourably with TDS measurements from produced formation water and salinity values derived from wireline electric logs for the Plover Formation in the Vulcan Sub-basin. A hydrodynamic analysis of these strata is shown as a case study.

Hydrodynamic analysis of the Early Cretaceous aquifers in the Barrow Sub-basin in relation to hydraulic continuity and fault seal
A.L. Hennig, J.R. Underschultz & C.J. Otto

Abstract
Formation pressure measurements from the Mardie Greensand and the Barrow Group were of sufficient quantity and quality to enable a hydrodynamic analysis of the flow systems to determine how flow systems interact laterally and across formations. This has increased the understanding of how the aquifer systems underlying the hydrocarbon accumulations in the Barrow Sub-basin interact and has implications for the long term development of the sub-basin in terms of interaction between producing fields via the aquifer and in the potential use of the aquifer as a fluid disposal site.

The study concluded that in parts of the basin the Mardie Greensand and the Flacourt Formation can be considered a single aquifer, and there exists the possibility of a separate water leg above the hydrocarbons in some parts of the Mardie Greensand. The Flag Sandstone and the Flacourt Formation appear to be in hydraulic communication and acting as a single aquifer system, and areas where either the Flacourt Formation or the Flag Sandstone and the Malouet Formation are in hydraulic communication were identified. Overpressure is confined to the Malouet Formation and, over geologic time, locally drives the aquifer flow systems. A regional flow model for the Flacourt (Zeepaard)/Flag Aquifer and the Malouet Aquifer shows that in both systems flow is toward hydraulic lows at the centre of the basin, appearing to overwhelm the effects of compaction-driven flow systems. Exit points are postulated at either end; one near Altair 1, the other in the vicinity of the Bambra wells, but there is little evidence at this stage to conclusively support either.

Geochemical evolution of formation water in the Talisman Oil Field, North West Shelf, Australia: Implications for oil exploration and production
G.K. Ellis

Abstract
Produced formation water from the Angel Formation in the Talisman Oil Field, North West Shelf, Australia, was analysed on a regular basis during water production, from December 1989 to the termination of production in July 1992. Evaluation of these analyses has defined chemical changes to the formation water, particularly a reduction in sulphate and an increase in bicarbonate content, close to the oil-water contact. These changes, in conjunction with the recovery of live and fossilised sulphate-reducing bacteria, point to bacterial reduction of formation water sulphate close to the oil-water contact. The Talisman formation water chemical signatures, indicative of bacterial sulphate reduction close to an oil accumulation, have the potential to provide valuable proximity to oil pay indicators for exploration.

From a production perspective, the routine water analyses enabled identification of current sulphate-reducing bacterial activity in the surface production equipment and facilitated remedial biocide additions to eliminate metal corrosion and contamination of the produced oil. In addition, subtle differences, observed in the chemistry of the formation water produced from the ‘B’ and ‘C’ sands of the Angel Formation in Talisman 1 and 7 respectively, even though the water is from the same regional aquifer, were used to determine the contribution of each well to co-mingled water production.

Neogene Tectonic and Structural Evolution of the Timor Sea Region, NW Australia
M. Keep, M. Clough & L. Langhi

Abstract
Neogene deformation styles in the Timor Sea vary from flexure-dominated in the NE to transtension-dominated towards the SW. Neogene faults generally preserve overall normal displacement despite sometimes complex reactivation histories. Controls on fault style include proximity to the Timor Trough, and position relative to basement highs. Basement faults often control the location of Neogene faults, with both hard- and soft-links preserved throughout the area. Cretaceous and Upper Jurassic shales and claystones act as ductile horizons and cause detachment of basement from the Neogene in some areas. Three main pulses of deformation at the Early Miocene, Late Miocene and late Early Pliocene correspond to regional tectonic events in the region. The Late Miocene event in particular seems widespread, with synchronous deformation through the Indo-Australian plate.

Late early to mid Miocene Patch Reefs, Ashmore Platform, Timor Sea - Evidence from 2D and 3D Seismic Surveys and Petroleum Exploration Wells
J.D. Gorter, J.P. Rexilius, S.L. Powell & S.W. Bayford

Abstract
Discrete contemporaneous buried structures are identified as anomalous seismic packages within the generally continuous reflectors characteristic of Miocene strata in the western Timor Sea. Petroleum exploration wells Pascal 1 and Lucas 1 drilled two of the structures. Palaeontological analyses of cuttings from Lucas 1 show the upward progression from a shallow marine bank, sub-reef facies to reef. In Pascal 1, drilled in the centre of one of these features, shallow open marine strata are overlain by a protected shallow water facies, probably an inner reef lagoon. The Pascal and Lucas structures are interpreted as Early Miocene patch reefs developed on the Ashmore Platform. Other nearby structures, including the Puffin Structure, previously interpreted as a possible simple impact crater, are likely also to be of the same reefal origin as the Pascal and Lucas structures. Oil shows in contemporaneous facies in wells in the area suggest that porous reef-associated carbonate facies of these patch reefs may be prospective for hydrocarbon accumulations.

3D structural analysis of hydrocarbon migration in the Vulcan Sub-basin, Timor Sea
G. Chen, K.C. Hill & N. Hoffman

Abstract
A 3D structural model of the Vulcan Sub-basin, Timor Sea was constructed through interpreting and depth converting Geoscience Australia's seismic data grid of 27 regional lines. The model was progressively back-stripped, decompacted and restored to reveal its palaeo-architecture in the Valanginian, Late Eocene and Late Miocene, which correspond to major periods of hydrocarbon expulsion, as interpreted by Kennard et al. (1999). Knowing the palaeo-architecture of the Plover Formation reservoir horizon at those times, the up-dip migration paths over the reservoir horizon have been determined to constrain the source risk for prospective traps. Two models for the source kitchen were tested, one using a minimum 140°C isotherm and the second using a saturation-based expulsion model, with expulsion driven by compaction.

Migration path modelling using the saturation-based expulsion model is consistent with the drilling results of the discovery wells and dry holes, and confirms breaching of the structures at Allaru, Paqualin, Puffin and Swan, and preferential gas leakage in the East Swan and Skua fields. The only discrepancy is the oil/gas found in Oliver, indicating probable oil generation in the central Cartier Trough.

The methodology is ideal for application in a commercial environment using detailed modern 3D datasets, and will be of greater utility in areas with less tectonic reactivation than the Vulcan Sub-basin. Since the precise details of palaeo-architecture can have a strong effect on individual trap risk through charge focusing and migration shadowing, it is vital that the effects of subtle tectonic movements and regional tilting are recognised and included in prospect risking to maximise exploration success.

Controls on the Trap Integrity of the Skua Oil Field, Timor Sea
A. Gartrell, M. Lisk & J. Underschultz

Abstract
A new fill-spill model has been produced for the Skua Oil Field that challenges the importance of Mio-Pliocene fault reactivation as the principal control on trap integrity. Integration of contemporary and palaeo-fluid-flow indicators within a 3D structural framework, guided by 3D structural restoration, highlights the important role of pre-existing fault intersections.

The intersection between a subordinate rift fault and a cross-trending pre-rift fault is identified as the key leak point. Creation of structural permeability through the seal at the fault intersection predates initial hydrocarbon charge in the late Tertiary and is suggested to be associated with Late Cretaceous to Early Tertiary fault reactivation. The coincidence between the fault intersection and the position of both the original (palaeo-) and current oil-water contacts indicates that this leak point has been the principal control on the volumetric capacity of the Skua trap. Post-charge modification of the trap by southwesterly tilting provided continual supply of hydrocarbons to this leak zone, which may have contributed to the maintenance of structural permeability. Contemporary fluid flow directions derived from hydrodynamic assessment of the reservoir support flow towards this leak point with vertical flow out of the system continuing at the current day. The location of the leak point also corresponds with the position of the largest overlying Hydrocarbon Related Diagenetic Zones, and is broadly consistent with the hydrocarbon seepage recorded in the water column.

Subsequent episodes of fault reactivation may have affected the leak zone, but there is no evidence of substantial Mio-Pliocene fault movement in the Skua trap. Strong reactivation of the nearby Rowan Fault may have partitioned strain in the Skua area and effectively shielded the Skua Fault from reactivation during the Mio-Pliocene.

The results highlight the ability of structural networks formed at fault intersections to act as efficient long-lived fluid conduits, and these may be an important control on trap integrity throughout the Timor Sea region.

Subsidence and thermal history modelling: New insights into hydrocarbon expulsion from multiple petroleum systems in the Petrel Sub-basin, Bonaparte Basin
J.M. Kennard, I. Deighton, D.S. Edwards, C.J. Boreham & A.G. Barrett

Abstract
Subsidence and thermal history analysis of 24 wells and seismically-defined depocentre sites has been undertaken to investigate the generation and expulsion history of the Early Carboniferous and Permian petroleum systems in the Petrel Sub-basin. Younger Mesozoic units are shown to be non-effective source rocks.

Modelled oil and gas expulsion from postulated oil-prone source units within the Lower Carboniferous Milligans Formation is restricted to two offshore depocentres immediately north and south of the Turtle-Barnett High. Expulsion commenced in the Late Carboniferous, reached its peak in the Early Permian, and minor expulsion continued throughout the Permian and Early-Middle Triassic prior to the onset of regional uplift associated with the Late Triassic Fitzroy Movement. Limited gas expulsion is also modelled in the onshore Carlton Sub-basin, and although this unit is sufficiently mature in this area to have generated oil, the models suggest that generated volumes are insufficient for expulsion of oil.

Modelled oil and gas expulsion from mudstones and coaly mudstones of the Lower Permian Keyling Formation is restricted to the central and outer portions of the Petrel Deep. Expulsion from the outer Petrel Deep occurred in the Late Permian-Early Triassic, and expulsion from the central Petrel Deep commenced and peaked in the Early Triassic, with subsequent phases of minor expulsion in the Late Triassic-Cretaceous. Oil expelled from these source units may have migrated to pre-Fitzroy Movement structures and stratigraphic traps within and on the flanks of the Petrel Deep, but to date the only possible indication of such an oil charge are low confidence SAR slick anomalies east and southeast of the Petrel Field.

Modelled gas expulsion from the Upper Permian Hyland Bay Formation is limited to the outboard limits of the Petrel Sub-basin, and occurred in the Jurassic-Cretaceous with peak expulsion in the mid-late Cretaceous. This unit is considered too lean to expel significant quantities of oil.

These expulsion models are integrated with the known distribution of hydrocarbon accumulations, shows and satellite oil slick anomalies to map the extent of the petroleum systems in the Petrel Sub-basin. These maps can then be used to assess the likely source(s) of the recent Blacktip 1 gas discovery, and to evaluate the charge potential of traps within the sub-basin, including those within the 2002 offshore acreage release areas.

Assessing a basin's potential for Geological Sequestration of carbon dioxide: an exapmle from the Mesozoic of the Petrel Sub-basin, NW Australia
C.M. Gibson-Poole, S.C. Lang, J.E. Streit, G.M. Kraishan & R.R. Hillis

Abstract
Assessing the suitability of a sedimentary basin for CO₂ sequestration requires detailed geological and geophysical studies. An example is presented from the Mesozoic succession of the Petrel Sub-basin. Two stratigraphic intervals were investigated as potential Environmentally Sustainable Sites for CO₂ Injection (ESSCI): the Plover ESSCI (Plover and Elang formations, sealed by the Frigate Formation) and the Sandpiper ESSCI (Sandpiper Sandstone, sealed by the Bathurst Island Group). The Plover ESSCI reservoirs are laterally extensive, fluvial to deltaic sand bodies that are likely to have an excellent degree of interconnectivity. The Sandpiper ESSCI reservoirs are predominantly shoreface sand bodies, in which the interconnectivity depends on the degree of shoreface attachment, but is thought to be moderate to excellent. Reservoir quality, as indicated by detailed petrology, is considered to be good. The Bathurst Island Group regional seal has good to excellent seal potential, with the capability to withhold an average CO₂ column height of 400 m. A geomechanical assessment indicates that the orientation of W-WNW, NNW-NNE and NE- trending faults near the basin margin would permit their reactivation within the inferred stress regime. However, most of these faults occur outside the potential CO₂ containment area. The potential CO₂ storage capacity is vast, in the order of several thousand Megatonnes (100s of TCF) of CO₂ . This study illustrates how basin-scale geological sequestration may provide a technical solution to the problem of reducing greenhouse gas emissions.

Evidence for an early, marine-sourced oil charge to the Bayu Gas-Condensate Field, Timor Sea
S.C. George, M. Lisk, P.J. Eadington & R.A. Quezada

Abstract
The distribution of oil-bearing fluid inclusions (FI) in Jurassic reservoir sandstones from Bayu 1 (Northern Bonaparte Basin, Timor Sea) is consistent with the presence of a palaeo-oil column of at least 20 m height, beneath a 46–53 m thick palaeo-gas cap. The reservoir currently contains a thick (155 m) gas-condensate column. In order to assess the origin of the oil trapped in the fluid inclusions and its relationship, if any, to the gas condensate, a detailed molecular geochemical study was carried out on a sample of extracted FI oil and a sample of condensate recovered from a similar interval by Modular Formation Dynamics Tester (MDT). Compared to the condensate, the FI oil was generated from a more marine-influenced, less clay-rich source rock or source facies, which was deposited in a less oxic environment with greater eukaryotic input. The source rock of the condensate was more terrigenous and had greater microbial input. The Bayu FI oil contains a greater amount of C28 and C29 tricyclic terpanes than the Bayu condensate, and particularly compared to the Elang/Plover-sourced oils from further to the northwest (e.g. Corallina and Laminaria), which are more terrestrially-dominated. The Bayu condensate has previously been attributed to either the Cretaceous Echuca Shoals Formation, or mixed sourcing from the less terrestrially-influenced facies of the Elang and Plover formations, together with the Flamingo Group. Analysis of the FI oil confirms a more marine-influenced source facies but suggests that the Echuca Shoals is the most likely source based on oil-oil and oil-source correlations. The FI oil appears to represent a marine source end-member and it is likely that mixing of this oil (sourced from the Echuca Shoals Formation) with hydrocarbons sourced from the more terrestrially dominated Plover/Elang source facies could account for the intermediate composition of the currently reservoired condensate. A discrete "Flamingo Group" is not required and this oil family may not be present in the Bayu area. The differences are nevertheless subtle and a contribution from the Flamingo Group cannot be completely discounted. The FI oil has a mid-oil window maturity (~0.75% vitrinite reflectance equivalent), whereas the currently reservoired condensate has a higher maturity (~0.9%). These maturity data are consistent with early expulsion from the more labile marine-derived organic matter in the Echuca Shoals Formation, followed by expulsion of large amounts of condensate from the more terrestrially-dominated Elang and Plover formations. Three possible transition mechanisms from gas over oil to condensate are consistent with the fluid inclusion petrographical and geochemical data. The first charge may have (1) been lost by breaching of the seal, (2) been displaced by the condensate, or (3) been partly dissolved in the later condensate charge. A combination of factors 2 and 3 is considered most likely, but further investigation is required to assess these options.

Recent discoveries in the Barrow Sub-basin: Linda, Gipsy, North Gipsy, Rose, Lee, Gibson, Simpson, South Plato, Double Island, Victoria, Little Sandy, Pedirka and Hoover
Apache Energy Ltd

Abstract
Apache Energy Ltd and its TL/1,5,6 co-venturers (Kufpec Australia Pty Ltd and Tap (Harriet) Pty) have drilled several discovery wells in the Barrow Sub-basin of the Carnarvon Basin since 1998. These include eight new discoveries (Gibson, South Plato, Simpson, Double Island, Victoria, Pedirka, Little Sandy, Hoover) in the proven Lower Cretaceous Flag Sandstone play fairway. In addition, four new fields were discovered within the Upper Triassic to Lower Jurassic fluvio-deltaic/littoral sandstones in structural traps along the Gipsy-Rose-Lee trend on the eastern side of Apache’s acreage in the sub-basin (Gipsy, North Gipsy, Rose, Lee). The Linda discovery established a new play for the sub-basin with the discovery of gas and condensate within Upper Jurassic shoreface sandstones stratigraphically trapped within the Dingo Claystone.

John Brookes Gas – The voyage to discovery
K. Auld, B. Thomas, J. Goodall, L. Elliott & J. Benson

Abstract
John Brookes 1/ST 1 discovered an 85 m gross dry gas column within Carnarvon Basin permit WA-214-P during 1998, in the area today forming the John Brookes location. The primary objective was to test a structural closure at the base of the Muderong Shale regional seal, up-dip from Tryal Rocks 1, drilled in 1970. Tryal Rocks 1 was initially considered a dry hole, however, a well review in 1997 suggested that it might contain a hydrocarbon column. The mapping of the structure using initially 2D, then 3D data, indicated that Tryal Rocks 1 was drilled off the crest, with significant closure existing up-dip. The John Brookes 1/ST 1 location was selected to test this up-dip potential, and the discovery confirmed the structural model. The surprising nature of the reservoir, interpreted to be a well developed Birdrong Sequence turbidite channel of P. burgeri age, changed the emphasis from purely structural to a play with structural/stratigraphic potential. An amalgamated turbidite complex model was invoked, inferring that the sandstone represents a confined channel system cut into the underlying substrate. This model explains the John Brookes 1/ST 1 gas reservoir being in direct continuity with the sandstones at Tryal Rocks 1. A review of the 3D seismic data over the field and seismic modelling supports the palaeo-depositional model.

Basal Oligocene Channelling, Barrow Sub-basin, Carnarvon Basin, Western Australia
J.D. Gorter, D.J. Hearty, J.P. Rexilius & S.L. Powell

Abstract
In the area east of the Woollybutt oilfield in the northern Barrow Sub-basin of the Carnarvon Basin, Australian North West Shelf, channels are clearly defined on 2D and 3D seismic profiles, and by isochrons within mostly carbonate middle Tertiary strata. Woollybutt 2A intersected the seaward extension of one of these channels, and coarse-grained porous sandstone was encountered. Microfossils indicate that infill of this channel occurred during the early Early Oligocene. These data suggest a mechanism for basinward transport of coarse-grained clastics to where they may form viable petroleum traps below sealing marls and fine-grained carbonates of the Oligo-Miocene Mandu Formation progradational facies. In addition, infill facies velocities grade laterally from west to east with significant pull-up of the Base Tertiary seismic horizon.

Pressure seal and deep overpressure modelling in the Barrow Sub-basin, North West Shelf, Australia
S. He & M. Middleton

Abstract
A deep overpressured system occurs in the thick Jurassic sequence, and parts of the Cretaceous Barrow Group of the Barrow Sub-basin. This has been confirmed by repeat formation tests and drill stem tests which reveal excess pressures ranging from 24 MPa to 28 MPa at depths between 3100-3650 m. The overpressured system is coincident with an increase in mud weights, as well as high sonic transit times and low formation resistivities in fine-grained rocks over depths between 2650-4650 m. The data suggest that a top pressure sealing zone (pressure transition zone) may exist, comprising lithologies with 60-80 % claystone and siltstone, with permeabilities of 10^–19-10^–22m² (10^–4-10^–7 md). Basin modelling indicates (1) that excess pressure was generated during the Jurassic and Cretaceous, and (2) that most of the porosity in the Jurassic source rocks has been lost through compaction, and pressure cells have been formed and there have been low sedimentation rates since the Cainozoic.