1

Understanding the Late Triassic Mungaroo and Brigadier deltas of the Northern Carnarvon Basin, North West Shelf, Australia

K.R ADAMSON1 S.C. LANG1, 2, N.G. MARSHALL1, R.J. SEGGIE1, N.J.

ADAMSON1 & K.L. BANN3. 1 Woodside Energy Ltd. Woodside Plaza. 240 St. Georges Terrace. Perth. WA

6000. Australia 2 Present address: Chevron Energy Technology Company.

3 Ichnofacies Analysis Inc, Calgary, Alberta, Canada keith.adamson@woodside.com.au,

The Triassic fill of the pre-rift Northern Carnarvon Basin was deposited during a period of tectonic quiescence in a broadly ramp-type or intracratonic setting with gentle depositional gradients. The Triassic Mungaroo Formation of Carnian to Norian age, and Brigadier Formation of Rhaetian age, are interpreted as alluvial and deltaic deposits and are thought to have been emplaced by a series of third and possibly fourth order duration regressive-transgressive cycles, superimposed on an overall 2nd order transgressive cycle. In detail this deltaic system represents a transgressive sequence set with the fluvially-dominated Mungaroo units passing gradationally upwards into the dominantly deltaic Brigadier reservoirs. A similar alluvial through delta plain to delta front transition is recognised in a proximal to distal sense within the Mungaroo Formation (broadly from east to west). This is even more striking in the Brigadier Formation where delta plain through delta front units are locally replaced basinward by platform carbonates. Fluvial channel sandstones of various types represent the main exploration and development targets in the Mungaroo Formation reservoirs while distributary channel, mouth bar and inter-distributary bay deposits dominate within the Brigadier Formation. Non-reservoir baffles and barriers include soils, coals and lacustrine mudrocks in the Mungaroo Formation while interdistributary bay and pro-delta mudrocks dominate in the Brigadier Formation.

2

Permo-Carboniferous glacial channel systems on the margin of the Lennard Shelf, Canning Basin, Western Australia: implication for ice sheet

dynamics

J. AL-HINAAI AND J. REDFERN Basin Studies and Petroleum Geoscience, School of Earth, Atmospheric and

Environmental Sciences, University of Manchester, UK jalal.al-hinaai@postgrad.manchester.ac.uk,

Interpretation of a recent high quality 3D seismic dataset acquired on the Lennard Shelf, Canning Basin, integrated with data from 20 wells within the survey area, allows analysis of seismic facies and the depositional architecture of Permo-Carboniferous glaciogenic sediments. The recognition of a system of large glacial channels within the Carolyn Formation of the Grant Group offer new insights into ice sheet dynamics and distribution in the region. The Carolyn Formation (140-620 m thick) consists of massive and cross-bedded sandstones interbedded with mudstones. Seismic facies vary from chaotic high amplitude to discontinuous low amplitude reflector packages. Two distinct erosional surfaces are observed within this interval on the seismic data, which are interpreted to record two major glacial advances, separated by a significant glacial retreat and fluvio-glacial deposition. A N-S trending valley system is recognised that, in places, completely erodes into the underlying section almost down to the base Grant Unconformity (620 m of erosion). Root-mean-squared (RMS) attribute extractions image the presence of a network of anastomosing NW-SE oriented channels trending oblique to the regional structural trend of the Fitzroy Trough. The morphology and size of this large valley system suggests a glacial origin, and this is interpreted to be a series of tunnel valleys developed during the latest glacial advance, a final glacial phase previously unrecorded in the basin. These results provide valuable data on the Permo-Carboniferous glacial evolution in the basin and development of channel systems within a section that has proven hydrocarbon potential.

3

Hunting for the Cracks: Identifying Fracture Permeability for Geothermal Exploration in the North Perth Basin

MARK BALLESTEROS & RALF OPPERMANN

Green Rock Energy Ltd OPPtimal Exploration and Development Pty Ltd

Hot Sedimentary Aquifer (HSA) geothermal systems share many characteristics with petroleum systems, and similar data and work flows are used to define them. Key geological ingredients for a working geothermal system include a heat source and a heat trap in the form of thermally insulating rocks such as coals or low thermal conductivity shales with, most importantly, underlying naturally permeable, cavernous or fractured reservoir rocks (Cooper & Beardsmore, 2008). The North Perth Basin (NPB) offers one of the most attractive areas for Hot Sedimentary Aquifer (HSA) geothermal projects in Australia, with available data supporting the presence of all of these attributes. The fundamental conundrum of HSA systems is that while temperature generally increases with depth, porosity and permeability generally decreases. In most cases, degradation of matrix porosity and permeability as a result of compaction and diagenesis means it can be difficult or impossible to achieve necessary flow rates. However, naturally occurring open fractures are common in some areas well below these depths and can offer a viable alternative reservoir target. Examples for this can be found in southern Germany, where currently three commercial HSA geothermal power plants exist, the Unterhaching plant near Munich in the southern German Molasse Basin (Luschen, et. al, 2011), as well as two plants in the Upper Rhine Graben at Landau and Insheim (Schindler et al., 2010) produce exclusively from fractures. A water temperature of about 150oC is generally considered suitable for HSA projects aimed at generating electricity. Although electricity can be generated with water temperatures of less than 100oC, the efficiency of the conversion process drops quickly and it becomes difficult to commercialise the resource. The technical evaluation of the NPB has identified a number of attractive geothermal target areas, with permeability associated with open natural fractures providing the most promising potential reservoir. The challenge is to devise a method that identifies areas with open fractures and then to apply a work flow that can be used to understand, in detail, the nature, distribution and orientation of the fractures. This in turn facilitates drilling programs to be devised that maximise the chances of intersecting multiple open fracture zones.

4

Oil exploration potential in the greater northern Australian –New Guinea super gas province

PETER M. BARBER ISIS Petroleum Consultants P/L, 47 Colin Street, West Perth, Western Australia,

6005. pbarber@isispetroleum.com.au

The Greater Northern Australia–New Guinea Super Gas Province lies on the Northern Australian continental margin, within which over 270 tcf gas and 8.2 billion bbls oil have been discovered. The province extends from the Northern Carnarvon Basin, through the Browse Basin into the Bonaparte Basin, and along the southern edge of the New Guinea Fold Belt. This paper explores the reasons why gas is the dominant hydrocarbon and identifies ‘sweet spots’ for oil. Within the Mesozoic–Cenozoic succession of the northern margin, the main source rock type is widespread lower delta plain coaly facies (Organofacies D/E), which typically produce 70% gas and 30% oil. In contrast, conditions favourable for oil-prone source rocks, such as restricted marine shales (Organofacies B) and, to a lesser extent, marine carbonate muds (Organofacies A), are found within a few rhomboid syn-rifts including the Late Jurassic to Early Cretaceous Barrow, Dampier, Exmouth and Vulcan sub-basins, the Papuan Basin and the Neogene Salawati Foreland Basin respectively. Oil-prone marine carbonate mudstone source rocks (Organofacies A) of Late Triassic age are believed to be present in various allochthonous basins along the Banda Sea margin. Along the northern Australian continental margin the distribution of these various source rocks, the migration phase history of the expelled hydrocarbons and resultant hydrocarbon field and type are largely controlled by: (i) Late Paleozoic-Mesozoic passive margin architecture; (ii) Cenozoic collision with the SE Asia island arc system, creating the Banda Arc and New Guinea foldbelt and foreland; (iii) Cenozoic loading either via passive margin subsidence or compressional tectonics in the New Guinea Fold Belt; and (iv) 2nd order global-eustatic cycle overprinting, including high impedance efficiency of the Valanginian floodback shale regional seal. Burial history regimes, source rock compositions, and inorganic sources, in conjunction with secondary effects such as biodegradation and water-washing, have impacted on the relative abundance of CO2 and Gas-Condensate Ratios (CGRs) in many accumulations. Yet-to-find (YTF) fractal graph analysis suggests that at least nearly 32 billion boe in total remain to be discovered, including a number of significant multi-tcf gas resources. Oil accumulations will tend to be modest in size, except where under-explored plays can be invoked. These are likely to occur below the Oxfordian regional seal in rhomboid rift basins such as the Vulcan Sub-basin and the Barrow-Dampier-Exmouth rift system, or beneath sub-thrust belt plays within the New Guinea Fold Belt in both West Papua and Papua New Guinea, where large economically viable targets >100 MMbbls are expected to be present. Such materiality is considered essential to compensate for high operational costs due to the remote mountain topography or extensively forested flood plain terrains.

5

Stratigraphic interpretation and reservoir modelling of the Barrow Group

below Barrow Island

I. BARRANCO1, E. MAHON1 AND P. SIXSMITH2

1Chevron Australia Ltd., 250 St Georges Tce., Perth, WA 6000, Australia; 2Chevron Energy Technology Pty. Ltd., 250 St Georges Tce., Perth, WA 6000,

Australia,

An integral component of the Chevron operated Gorgon Project is the proposal to dispose of reservoir carbon dioxide by underground injection into the Dupuy Formation below Barrow Island. As part of this project, Chevron has undertaken a new assessment of the geology at Barrow Island, including the re-analysis, and stratigraphic interpretation of the Barrow Group which overlies the Dupuy Formation. Core from 24 wells were reviewed to define depositional facies. Biostratigraphic data was reviewed for 13 wells and wireline-log data from 41 wells were used for well correlation, facies interpretation and petrophysical evaluation. In addition to the well data, regional seismic data was used to map reflectors believed to represent the paleo-shelf edge of three major progradational events in the Barrow Group, named K10, K15 and K20. The mapped position of the paleo-shelf edge of K10 is located some 100 km to the South West of Barrow Island, for the K15 it lies some 20 km to the South of Barrow Island, and for the K20 it crosses Barrow Island. As a result of the integration of this data, the Barrow Group in the Barrow Island area is interpreted to have been deposited predominantly by gravity driven processes below storm-wave base, with nearshore marine deposits encountered only at the very top of the succession. An early integration of pressure, production and salinity data into a simple stochastic geocellular model allowed us to identify stratigraphic features impacting flow behaviour. A more complex geocellular model was dynamically history matched to ensure consistency between the depositional model and dynamic reservoir data.

6

Seismic stratigraphy of a Plio-Quaternary intra-shelf basin (Bonaparte

Shelf, NW Australia)

J. BOURGET1*, R. NANSON2, R. B. AINSWORTH2, S. COURGEON3, S. J. JORRY3, H. AL-ANZI2

1 School of Earth and Environment, Centre for Petroleum Geoscience and CO2

Sequestration, University of Western Australia, 35 Stirling Hwy, Crawley, WA 6009, Australia

2 Australian School of Petroleum, 3 Department of Marine Geosciences, IFREMER,

julien.bourget@uwa.edu.au. The Bonaparte Basin is marked by the development of a wide (ca. 630 km) continental shelf where carbonate and siliciclastic sediments accumulated during the Late Pliocene and Quaternary (ca. 3.5 Ma BP onwards). This unusually large platform is associated with an up to 200 km-wide, low-gradient intra-shelf basin (ISB) that reaches 220 m water depth at the present day. The Malita ISB shares architectural similarities with carbonate-rich intra-shelf-basins of Palaeozoic to Mesozoic age, and probably constitutes the first Quaternary example of this type. Its architecture and seismic stratigraphy are here investigated through 3D and 2D seismic datasets. In the context of early collision between Australia and the Banda Arc, flexure-induced Neogene deformation shaped a very low gradient (< 0.07°) basin in the middle of the continental shelf. The late Pliocene-Quaternary intra-shelf basin depocentre is very similar to the rift-inherited Malita Graben Mesozoic depocentre, highlighting the role of basement reactivation in shaping the initial ISB topography. Two main seismic sequences are recognized. A first period of active aggradation of carbonate platforms persisted during the late Pliocene and early Quaternary. This was followed by a second phase of reduced carbonate production, and infill of the intra-shelf basin with clastic and mixed sediments. This change is tentatively attributed to the onset of 100 kyr-long, large amplitude glacio-eustatic cycles at the early/late Quaternary transition. Longer falling-stage and lowstand periods of the late Quaternary promoted silliciclastic input from the southern catchment and partial burial of most of the early Quaternary ISB platforms, suggesting conditions of relatively high subsidence. Thus, relative sea-level changes are the most important factor controlling the stratigraphic development of the Malita ISB during the Quaternary.

7

Evaluating the role of stress factors in trace-fossil distribution along mixed-influence deltaic systems of an embayed shoreline (Middle Jurassic, Sunrise Field of the Timor Sea, Australia and Timor-Leste)

L. BUATOIS1, F. BURNS2 & R.B. AINSWORTH3 1Department of Geological Sciences, University of Saskatchewan, Canada

2Firmground Pty Ltd, Nelson, New Zealand 7011 3Australian School of Petroleum, University of Adelaide, Australia, SA 5005

Emphasis has been traditionally placed in characterising ichnological signatures of the classical end members of the genetic ternary plot, namely river-, wave- and tide-dominated deltas. However, recent years have witnessed progress in the understanding of how these processes vary along strike, and down depositional dip resulting in a complex interplay of stress factors affecting the distribution of benthic faunas and their associated biogenic structures. The Middle Jurassic Plover Formation in the Sunrise Field of the Bonaparte Basin (Timor Sea, Australia and Timor-Leste) represents deposition in deltaic systems that display variable influences of wave, tidal and fluvial processes. Although wave and fluvial processes were dominant, tidal influence was persistent due to the embayed nature of the coastline. Ichnological studies demonstrate significant ichnological variability along strike in the Plover deltaic systems. Maximum stress levels are detected in stacked fluvial-dominated, tide-influenced multistorey channel complex and fluvial-dominated, tide-influenced channel deposits, which are sparsely bioturbated by Skolithos and/or Ophiomorpha. Fluvial-dominated, tide-influenced mouthbar deposits show good preservation of the primary fabric, locally overprinted by facies-crossing trace fossils, such as Skolithos, Ophiomorpha, Planolites and Teichichnus. However, the presence of Phycosiphon colonising event beds signals the local re-establishment of fully marine conditions. Offshore heterolithic deposits are dominated by Chondrites, Phycosiphon and Zoophycos, displaying more intense bioturbation than their prodelta counterparts, which tend to show sparse bioturbation conducive to good preservation of the primary fabric. Wave-dominated, tide-influenced delta front deposits display lower to moderate degrees of bioturbation and dominance of facies-crossing forms, with the addition of Phycosiphon colonising tempestites.

8

Assessing Controls on Nearshore Clastic Deposition in the Plover and Elang Formations using Ichnology: Case Studies from the Bonaparte

Basin (Timor Sea, Australia and Timor-Leste)

F. BURNS1, L. BUATOIS & R.B. AINSWORTH3 1Firmground Pty Ltd, Nelson, New Zealand Email: firmground@iprimus.com.au

2Department of Geological Sciences, University of Saskatchewan, Canada 3Australian School of Petroleum, University of Adelaide, SA 5005

Deltaic settings are highly complex with regard to the interaction of wave, river and tidal processes. As benthic organisms respond differentially to these processes due to a variety of stress factors, this results in complex faunal behavior. This paper focuses on the ways in which ichnology can help to assess the affects of waves, rivers and tides on the deposition of the Middle Jurassic Plover and Elang formations, Bonaparte Basin using three specific case studies. In the Bayu-Undan Field, the Plover succession is dominated by well-developed fluvially dominated distributary channel packages alternating with levee, splay and floodplain strata. Tidal influence increases gradually upwards, resulting in a mixed fluvial and tidal system, with well-developed Ophiomorpha irregulaire, Thalassinoides isp. and Skolithos linearis at the tops of distributary channel fills. In the Jahal-Laminara area, located further to the north, the Plover and overlying Elang formations are dominated by a mixed-influence system. Ichnologically, the bay-fill deposits are highly variable, with highly stressed packages devoid of bioturbation alternating with more open marine strata with often intense bioturbation. Distributary channel deposits display numerous tidal features, although ichnologically they are highly variable. In the Sunrise Field, located in the most northerly or open end position of the basin (and therefore more marine influenced), the early Plover Formation is dominated by fluvially dominated but tidally influenced distributary channels feeding the bay. As a result, stressed bay heterolithic strata devoid of bioturbation alternate with units with high levels of bioturbation. Maximum stress levels are detected in the stacked fluvial-dominated, tide-influenced multi-storey channel complexes, tidal channel packages and mouth bar strata. They are either non- or sparsely bioturbated (by Skolithos linearis and/or Ophiomorpha irregulaire), or bioturbation is sporadic with monospecific trace fossil suites characteristic. Location with regard to the large-scale embayment (i.e. the Bonaparte Basin) is thought to have a significant control on deposition. Although fluvial processes are dominant during deposition of the early Plover Formation in all the study areas, tidal processes have also had a major influence on deposition. Wave influence gradually increases up the succession in the Jahal-Laminaria section, but are minimal in the lower part of the succession. This change is even more pronounced in the Sunrise Field, and is thought to reflect an overall shift to deposition further outboard in a more open-ended, or marine-influenced, part of the embayment.

9

A regional assessment of the co2 storage potential of the petrel sub-basin (Bonaparte Basin), offshore Northern Territory

C. CONSOLI, K. HIGGINS, D. JORGENSEN, D. LESCINSKY, K. KHIDER, R.

MORRIS & V. NGUYEN Geoscience Australia, Canberra, ACT, chris.consoli@ga.gov.au Geoscience Australia has completed a regional study investigating the carbon dioxide geological storage potential for the Petrel Sub-basin (Bonaparte Basin), offshore Northern Territory. The aims were to acquire pre-competitive data and to evaluate the geosequestration potential. Geoscience Australia has acquired 4091 line km of high-resolution 2D seismic data in the sub-basin to better define potential storage sites. An integral part of the assessment was a marine survey comprising seabed mapping and characterisation to provide a link between the deep (to 3000 m) and shallow (0–60 m) subsurface to the seabed. This information was utilised to determine the effectiveness of the regional seal. Through the integration and interpretation of publicly accessible information, including seismic and well data, two plausible reservoir-seal pairs were identified: (1) lower reservoir of the Jurassic Plover, Elang and Lower Frigate Shale formations and the Jurassic Frigate Shale Formation seal; and (2) the upper reservoir of Cretaceous Sandpiper Sandstone Formation with the Cretaceous Bathurst Island Group, particularly the Wangarlu Formation as the seal. Static and dynamic modelling of injected CO2 has identified several prospective areas suitable for CO2 storage in the central part of the sub-basin. This is the first of a series of assessments of the offshore Australian basins for CO2 storage to be undertaken by Geoscience Australia.

10

The impact of multi-azimuth seismic over Tidepole

D.DICKINSON & SCOTT GAGEN Woodside Energy Ltd, 240 St Georges Terrace, Perth

david.dickinson@woodside.com.au The Tidepole Gas Field, located in WA-5-L on the North West Shelf, Australia was discovered in 1971. The field is covered by the high-resolution Demeter 3D seismic survey acquired over the central North West Shelf in 2003, but further appraisal of the Tidepole field remained difficult due to poor seismic data quality. The successful results from model studies led to the acquisition in 2007 of two additional azimuths over the Tidepole field to complement the existing Demeter data. The two new datasets were acquired at azimuths 60 and 120 degrees apart from Tidepole to maximise the azimuthal coverage. To resolve velocity differences in the different acquisition directions multi-azimuth anisotropic pre-stack depth migration was proposed. During the model building process the conventional residual moveout from all three azimuths was used to perform a multi-azimuth tomography. Initially an isotropic model was used to solve for heterogeneity. Then anisotropic layers were introduced where residual moveout remained. The resulting single model was used to migrate all three azimuths to the same depth. The new data significantly changed the interpretation of the field by removing multiples allowing better delineation of dipping structures and faults. Improved QI work allowed the separation of hydrocarbons from coals using AI and Vp/Vs volumes and a tie with the Goodwyn wells was achieved for the first time. In this paper we demonstrate that a multi-azimuth anisotropic pre-stack depth migration results in a significant improvement in seismic data quality and interpretation over the Tidepole field.

11

Insights from the Automated Extraction of Surfaces from the Bunda 3D Seismic Survey

J.K. DIRSTEIN1, T. RUDGE2, R.LI1 & A.J. STANLEY1

1Total Depth Pty Ltd., 21 Churchill Ave, Subiaco, WA, 6008, Australia jim@td.iinet.net.au,

2Buru Energy Ltd The Lennard Shelf in the Canning Basin has long held the lure of commercial hydrocarbons. Home Energy discovered the Blina Oil Field in 1981, the first of several small fields found during the 1980's on the shelf. Buru Energy’s predecessor ARC Energy took over the fields during 2007 and subsequently acquired the Bunda 3D Seismic Survey in 2009. This was the first 3D survey in the basin and was designed to image the existing oil fields and the surrounding leads and prospects. Buru Energy has undertaken a comprehensive study of the 3D volume using an automated segmentation algorithm that was inspired by the Human Genome Project to globally and simultaneously identify virtually all trough and peak surfaces (GeoPopulations) that are related to a genetically common waveform (Genotype). A number of these surfaces and their attributes were extracted and selected for further analysis using sub-segmentation techniques for seismic facies mapping, and curvature analysis using an advanced implementation of differential geometry. The curvature analysis was undertaken on a series of surfaces surrounding the Laurel Formation (source rock interval), to investigate whether morphometric analysis of observed collapse features could be mapped vertically through the section. While fluid flow out of the Fitzroy Trough has been implied based on its structural position in the basin, observations based on indications from the seismic data attributes would validate perceived fluid pathways and help reduce risk associated with trap charge and reservoir development. The interpretation of the Bunda 3D seismic volume reveals a number of untested features in formations that have already encountered hydrocarbons (e.g. the Permian Nookanbah, Poole, Grant & Betty formations, the Carboniferous Anderson, Laurel & Yellowdrum formations and the Devonian Gumhole and Nullara formations). Although the leads and prospects revealed from the automated methodology have yet to be tested, the workflow has clearly demonstrated significant advantages. Namely, the objective assessment of the entire 3D volume enables the interpreter more time to focus on the meaning of the results rather than the mechanics of the process. The integration of the 3D seismic coverage with well control and automated surface and object extraction highlights significant stratigraphic variability of both reservoir and seal. Consequently, reservoir/seal pair geometries as well as structure become key criteria for the assessment of new drilling prospects.

12

Identification of fluid flow features in the seafloor and subsurface and their Implications for prospect and geohazard assessment: examples from the

Australian Northwest Shelf

J.K. DIRSTEIN1, J.V. HENGESH2 & A.J. STANLEY1 1TotalDepth, Pty Ltd, 21 Churchill Ave, Subiaco, WA, 6008, Australia,

jim@td.iinet.net.au 2Centre for Offshore Foundation Systems, The University of Western Australia M053, 35 Stirling Highway, Automated data extraction and analysis techniques were applied to open-file 3D seismic volumes from the North West Shelf creating visual databases of virtually all peak and trough surfaces. Examples from the Gorgon, Glencoe and Bonaventure 3D seismic datasets reveal compelling evidence of upward fluid flow from the Triassic through the shallow subsurface to the seafloor. Further analysis of surfaces using new differential geometry techniques, provides quantitative object detection and insights into fluid flow related geomorphological processes. A variety of fluid flow features are shown throughout the subsurface, including conical-shaped depressions (e.g. pockmarks), polygonal faulting and sediment remobilization features (e.g. injectite/intrusions), which form along fluid migration pathways. The creation of a model for fluid flow allows informed assessments of whether potential prospects received charge and if later stages of upward fluid flow are evidence of charge breach and/or present potential geohazards for drilling and field operations. However, modeling the process is an extremely complex problem requiring many simplifying assumptions with respect to variations in fluid density, temperatures, and pressures all of which dramatically impact upon the properties of the rock and the behaviour of the fluids within them. The complexity of this process in turn complicates estimations of velocities and directions of fluid movement. Therefore, any insights or guidance gleaned from morphometric features observed in the seismic data volume undoubtedly help validate or improve existing fluid flow models. The use of global algorithms to automatically and simultaneously examine entire 3D data volumes in a timely and objective manner provides an effective platform for mining objects embedded in extracted surfaces for inclusion in the model of the subsurface.

13

Have we deciphered the Canning? Discovery of the Ungani Oil Field.

P.B. EDWARDS & E. STREITBERG Buru Energy, Perth, Australia

peteredwards@buruenergy.com

The 2011 discovery of the Ungani oil field by Buru Energy has driven a far-reaching change in perceptions of the prospectivity of the Canning Basin of Western Australia. Previously the basin had been portrayed as ‘difficult’, with a number of potential and even promising petroleum systems that had not lived up to expectations. Ungani 1 was intended as a follow-up to the 1967 Yulleroo gas discovery, 30 km to the west, which tested gas from the lowermost Carboniferous Laurel Formation. That discovery was ignored at the time, in part because there was no market for gas in Western Australia. Although located within the same fault terrace on the southern margin of the Fitzroy Trough, the targeted tight sands of the Laurel Formation were absent at Ungani 1. Instead, the well intersected a Lower Carboniferous or latest Devonian pervasively dolomitised limestone over 140 m thick, of which the upper 57 m is oil bearing. The oil has an API gravity of approximately 37°API, with DST tests yielding up to 1,647 bpd on a 12.7 mm (32/64 inch) choke with a flowing well head pressure of 124 kPa (18 psi). Quantifying the extent and production parameters of the reservoir and even understanding its geologic setting remain problematic with the current dataset, thereby placing large uncertainties on estimations of recoverable oil reserves. Consequently it is unclear what the long-term implications of Ungani might be for the basin. Nevertheless the discovery seems likely to revitalise exploration in the basin, and in particular the search for the next field on the trend.

14

Stable carbon and hydrogen isotopic compositions of Paleozoic marine crude oils from the Canning Basin: comparison with other west Australian

crude oils

D.S. EDWARDS1, C.J. BOREHAM1, J. CHEN1, E. GROSJEAN1, A.J. MORY2, J. SOHN1 & J.E. ZUMBERGE3

1Geoscience Australia, GPO Box 378, Canberra, ACT, 2601, dianne.edwards@ga.gov.au

2Geological Survey of Western Australia, 3GeoMark Research Ltd,

Abstract: This study focuses on the stable carbon (d13C) and hydrogen (dD) isotopic compositions of bulk, saturated and aromatic hydrocarbons in 19 Paleozoic marine crude oils from the Canning Basin, Western Australia. The stable carbon isotopic composition of crude oils is primarily dependent upon the source of the organic matter. Comparisons to other Australian and global marine oils and source rocks demonstrate systematic changes in the bulk stable carbon isotopic composition throughout the Paleozoic. From the Early to the Late Paleozoic, Australian oils have become isotopically more enriched in 13C; however, no such comparable trend is observed in deuterium. The most depleted d13Csat value (-32.4‰) is from the saturated hydrocarbon fraction of Middle Cambrian-derived oil-stains in the Arafura Basin, whereas in the Canning Basin the oldest oils are Ordovician with d13Csat values of about -31.5‰. Devonian-sourced marine oils from this basin exhibit slightly more enriched values (mean d13Csat = -29.3‰), and Mississippian-sourced marine oils from both the Canning and Bonaparte basins have mean d13Csat values in the order of -28.2‰.

Carbon and hydrogen isotopic compositions of individual C7+ n-alkanes obtained for the three major oil families from the Canning Basin, as determined by combined carbon isotopes and biomarker analyses, corroborate previous findings and emphasise both facies variations and differences in the level of thermal maturation attained by their source rocks. The n-alkane-specific d13C isotopic profiles of the Paleozoic marine oils from the Canning and Bonaparte basins characteristically follow the same trend as the bulk d13C isotopic values. The n-alkane-specific dD isotopic profiles of the oils typically complement those of the carbon isotopic profiles; however, they show a greater range of values than the carbon isotopic data. The isotopic data have been used to refine the characterisation of oil families and petroleum systems in the Canning Basin. The similarities of the n-alkane-specific dD isotopic profiles of some Ordovician-sourced Canning Basin oils with those of Early Triassic-sourced oils of the Perth Basin demonstrates that the typing of oil families should not be undertaken exclusively on a single parameter.

15

Late authigenic pyrite - an indicator of oil migration and entrapment in the Bonaparte Basin, Timor Sea, Australia.

G. K. ELLIS

Eni Australia Limited, 226 Adelaide Terrace, Perth, 6000, Western Australia, grant.ellis@eniaustralia.com.au

Late authigenic pyrite cementation is common to abundant in the Middle

Jurassic Laminaria and Plover Formation sandstone in numerous wells on the Laminaria High and in the Vulcan Sub-basin of the northern Bonaparte Basin. Pyrite cementation developed in these reservoirs by reduction of formation water sulphate in the presence of migrating and/or entrapped oil followed by the reaction of iron with the resultant hydrogen sulphide. Sulphate reduction is considered to be most likely by sulphate-reducing microorganisms, which utilise hydrocarbons for their metabolism.

Development of pyrite cementation in the sandstone is therefore dependent on the presence of sulphate- and iron-rich formation water. An initial phase of oil entrapment in the Bonaparte Basin, indicated by oil-filled fluid inclusions, was not accompanied by pyrite cementation suggesting that the original formation water was sulphate-poor. However, the large volume of late authigenic pyrite cementation associated with a later phase of oil entrapment, as particularly evident in the Skua oil field in the Vulcan Sub-basin and the Jahal oil field on the Laminaria High, indicates that sulphate- and iron-rich formation water has been input into the reservoir at a later stage. This hydrocarbon-charged fluid is inferred to have migrated vertically via reactivated and dilated faults and fractures into the reservoir from below.

This late authigenic pyrite is disseminated, in fractures and in solution fronts and provides a fingerprint of the mechanisms involved in oil-charged and sulphate- and iron-rich fluid migration into and through the reservoirs. Therefore late authigenic pyrite is considered to provide not only evidence of oil entrapment but a new methodology to understand and identify one mechanism of oil charged fluid flow into a structure.

16

Late Devonian–Early Carboniferous tectonostratigraphic framework for northern Canning Basin carbonate platform evolution

A.D. GEORGE1, Z. SEYEDMEHDI1 & N. CHOW2

1School of Earth & Environment, University of Western Australia, Crawley WA 6009, Australia. annette.george@uwa.edu.au

2Department of Geological Sciences, University of Manitoba, Mixed siliciclastic–carbonate depositional systems of the northern Canning Basin record platform development on syn-rift fault blocks related to opening and extension of the Fitzroy Sub-basin and subsequent thermal subsidence. The Lennard Shelf platforms are important analogues for the buried shelves of the Canning Basin, coeval platforms of the Bonaparte Basin, and rift-related carbonate reservoirs elsewhere. Integration of field- and core-based sedimentology, biostratigraphy, and wireline log and seismic data, within a sequence-stratigraphic framework, has been used to revise and refine the 2nd and 3rd order relative sea-level history through late Mid-Devonian to Early Carboniferous ramp-to-reef-to-ramp platform evolution.

Active faulting during the Frasnian resulted in at least eight backstepping sequences typically of ~1 myr duration bounded by flooding surfaces, with a few discrete pulses of siliciclastic influx associated with major relative sea-level falls. Progradational reef complexes (latest Frasnian to mid-Famennian) and the overlying ramp complex (mid-late Famennian to Tournaisian) are characterised by fewer sequences of longer duration (typically ~3 myrs) with common subaerial exposure features and siliciclastic lowstand wedges. Major flooding events are associated with significant backstepping of platforms (Middle Frasnian and Late Famennian) with marked changes in biota and likely platform morphology. Progradational (highstand) phases and sea-level falls were most important for controlling the distribution of early-formed dolomite in carbonate platform and slope strata.

17

Petroleum systems of the Canning Basin, Western Australia

K.A.R. GHORI Geological Survey of Western Australia, Department of Mines and Petroleum,

Mineral House, 100 Plain Street, East Perth, Western Australia 6004, ameed.ghori@dmp.wa.gov.au

The recent discovery of oil at Ungani, gas at Valhalla, and emerging shale plays have revived exploration in the Canning Basin. A compilation and review of various data from the onshore Canning Basin including petroleum geochemistry, organic petrology, apatite fission track analysis, heat flow and subsurface temperatures, as well as inferences from 1D burial history modelling indicate the following:

• the Ordovician Goldwyer and Bongabinni formations locally contain rich oil-prone source-beds, with up to 60% TOC within the Bongabinni Formation adjacent to the Admiral Bay Fault Zone, and up to 5% TOC within the Goldwyer Formation on the Barbwire Terrace;

• the Late Devonian Gogo Formation and Early Carboniferous Laurel Formation contain oil-prone source-beds with up to 4% TOC, but data from these units are limited;

• oil from the Pictor 1 well correlates with Ordovician source-beds from the Goldwyer Formation; oil from the Blina 1 well correlates with Devonian source-beds from the Gogo Formation, and oil from the Boundary, Lloyd, Sundown, West Kora, and West Terrace wells correlates with Early Carboniferous source-beds from the Laurel Formation;

• a working Permian petroleum system has yet to be identified within the onshore Canning Basin. However, Permian gas- and oil-prone source beds can contain up to 8% TOC, especially in the Noonkanbah Formation, but thermal maturity is low;

• the estimated maximum kerogen to petroleum transformation rate for the Goldwyer Formation was during the Permian in the Kidson 1 well, during the Triassic in the Acacia 2 well, during the Permian-Triassic in the Blackstone 1 well, during the Early Cretaceous in the Willara 1 well; for the Laurel Formation during the Carboniferous-Permian in the Yulleroo 1 well, and during the Permian in the Lake Betty 1 well.

18

The seismic stratigraphy of the Kimmeridgian-Tithonian Dupuy Formation in the Barrow Island area

DAN GILLAM 1, KENNETH D. EHMAN 2, HENRY POSAMENTIER3, MARK

TRUPP4

1Chevron Australia Pty Ltd, Perth, Australia, dan.gillam@chevron.com.au 2 Chevron Energy Technology Company, Perth, Australia

3Chevron Energy Technology Company, Houston, USA 4Chevron Australia Pty Ltd, Perth, Australia

The Kimmeridgian−Tithonian Dupuy Formation forms the injection reservoir for the Gorgon Carbon Dioxide (CO2) Injection Project. Understanding the reservoir architecture of the Dupuy Formation is a key aspect to ensuring the success of the injection program. The Gorgon CO2 Baseline Survey (BWI3D) was acquired in 2009 to provide a baseline for ongoing seismic monitoring and to improve reservoir characterisation. The BWI3D interpretation has been integrated with neighbouring seismic surveys and offset wells to characterise the depositional environment and reservoir architecture. The Dupuy Formation in the Barrow Island area is a locally thick (~500m), sand-prone system deposited in a variety of deep-water environments at the base of an active, steep slope. The Dupuy Formation has been sourced from the southeast, via a Late Jurassic submarine canyon. Basinward of Barrow Island the Dupuy Formation displays a classical lobate geometry consistent with the size, age and orientation of the canyon. Some stratigraphic intervals have been heavily modified via Mass Transport Complexes (MTC) that have degraded reservoir quality and imparted irregular bathymetry that has influenced subsequent deposition. The injection project is situated outboard of the canyon mouth in the transition from a weakly confined to unconfined distributary system. Intra-reservoir baffles appear limited in extent and the absence of confined channels is anticipated to promote an even CO2 migration front. The prevalence of slumping and disturbed bedding is anticipated to assist CO2 containment by increasing flow path tortuosity and formation exposure. The work presented here is broadly consistent with previously published models for the Kimmeridgian−Tithonian of the Carnarvon Basin and confirms the Dupuy Formation beneath Barrow Island is a good target for the disposal of reservoir carbon dioxide from the Gorgon Project.

19

Beyond the deltas: Late Triassic isolated carbonate build-ups on the Exmouth Plateau, Carnarvon Basin, Western Australia

S.L. GRAIN, W.M. PEACE, E.C.D. HOOPER, E. MCCARTAIN, P.J. MASSARA, N.G. MARSHALL & S.C. LANG1

Woodside Energy Ltd., 240 St Georges Tce, Perth, WA 6000, Australia. sarah.grain@woodside.com.au

1 Present Address: Chevron Energy Technology Company, 1500 Louisiana St, Houston, Texas, 77002. USA.

Late Triassic isolated carbonate build-ups have emerged as a new exploration play on the outer Exmouth Plateau. The presence of Late Triassic carbonates in the Northern Carnarvon Basin has been known for many years from Exmouth Plateau well-based stratigraphy, seismic surveys and Ocean Drilling Programme wells on the Wombat Plateau. The seismic identification of numerous dome-shaped features in the outermost Exmouth Plateau and subsequent confirmation of these domes as Late Triassic reefs with the drilling of Tiberius 1 in WA-434-P has advanced our understanding of this carbonate system.

Tiberius 1 intersected over 330 m of carbonate strata with coralline and other skeletal material consistent with an isolated reef carbonate. Wireline evaluation demonstrated an average porosity of 13% with high porosity zones and a net-to-gross of 45%. The side wall core samples record a multistage diagenetic history with well developed cements and secondary porosity.

These isolated reefs developed on a carbonate shelf that was located beyond the coeval inboard fluvio-deltaic Brigadier system over much of the northern Carnarvon Basin. This carbonate system is interpreted as being deposited during a second order transgressive cycle driven by accelerating accommodation space during the Rhaetian. Late Triassic carbonate systems are known from other outboard north-eastern Gondwanan localities.

Tiberius 1 proves the potential for reservoir development in these isolated carbonate reef build-ups. This opens a new exploration play on the outboard Exmouth Plateau where carbonate reservoirs overlie proven source rocks of the Mungaroo deltaic system and are sealed by Early Cretaceous shales. The play covers an area of over 800 km2 with 69 reef structures identified so far on 3D seismic data. The play can also be extended to an inboard trend containing more than 250 reef structures sealed by lower Jurassic shales.

20

The influence of exhumation on petroleum prospectivity in the sedimentary basins of WA

P.F. GREEN AND I.R. DUDDY

Geotrack International Pty Ltd, West Brunswick, Victoria, AUSTRALIA

Exhumation tends to be viewed by many as highly negative for hydrocarbon prospectivity, leading to basin models and regional assessments which downplay the possibility that preserved basin sequences have been more deeply buried by section that has subsequently been eroded away. However, major hydrocarbon accumulations are present in many exhumed basins, e.g. Reconcavo Basin, Barents Sea, East Irish Sea Basin, Southern North Sea and many North African basins, and exhumation need not necessarily rule out the presence of hydrocarbon reserves. Apatite fission track analysis (AFTA®) data show that the Proterozoic and Paleozoic basins of Western Australia, including the Officer, Canning and Perth Basins, have all been more deeply buried prior to regional km-scale Mesozoic and Cenozoic exhumation, but this is often overlooked in assessing hydrocarbon prospectivity. Yet the influence of exhumation on petroleum systems in these basins is clear, as evidenced by e.g. the presence of paleo-oil columns in many of the wells in the northern Perth Basin. The processes responsible for exhumation are not well understood, partly because many geologists deny the reality of such processes in the absence of a recognised mechanism. But evidence for exhumation is overwhelming, and major investigation of the underlying processes is required. Exploration success in these basins requires recognition of exhumation as a major influence on prospectivity and quantification of its effects, e.g. in determining the timing of generation in relation to trap formation, defining remigration pathways and predicting phase changes associated with exhumation. In this way, more efficient exploration strategies can be designed which take the effects of exhumation into account.

21

Early Carboniferous petroleum source rocks of the southeastern Bonaparte Basin, Australia

J.D. GORTER1 & D.M. MCKIRDY2

1ENCAA – Unconventional Exploration, eni spa exploration & production division, Via Emilia, 1, 20097 San Donato Milanese (Milan) Italy,

john.gorter@eni.com 2Centre for Tectonics, Resources & Exploration (TRaX), School of Earth & Environmental Sciences, University of Adelaide Palaeontological and geochemical resampling of cores from mineral exploration hole NBF 1002 in the southeastern Bonaparte Basin of northern Australia has led to the re-evaluation of previously published source rock identifications and the Early Carboniferous stratigraphy of that corehole, and a rethinking of the basin’s oil-source rock correlations.

All source rock samples from NBF 1002, previously thought to be from the Milligans Formation, are shown to belong to an older sequence called the Langfield Group that is separated from the Tanmurra Formation by a major erosional unconformity and therefore cannot be used to infer that the Milligans Formation contains the source rocks of the Turtle, Barnett and Waggon Creek oils. Organic-rich rocks are documented for the first time within the Tanmurra Formation in NBF 1002. The apparent correlation of the Barnett 2 DST 3 crude with shales of the Langfield Group and the indication of a genetic relationship between the Tanmurra Formation and the Turtle and several other Barnett crudes clarifies the source rock characteristics of the Early Carboniferous succession in this part of the southeastern Bonaparte Basin.

22

Detrital zircon U–Pb ages from the Paleozoic of the Canning and Officer Basins, Western Australia: implications for provenance and interbasin

connections

P.W. HAINES1, M.T.D. WINGATE1 & C.L. KIRKLAND1 1Geological Survey of Western Australia, 100 Plain Street, East Perth, Western

Australia, 6004; peter.haines@dmp.wa.gov.au Abstract: The U–Pb age spectra of detrital zircons separated from sandstone were determined for twelve Canning Basin samples, two western Officer Basin samples, and one basement sample from the centre of the Canning Basin. The basement sample has an early Neoproterozoic maximum depositional age and its detrital zircon age spectrum is similar to that of the Neoproterozoic Murraba Basin to the east. Ordovician samples from the northern Canning Basin yield zircon age spectra implying first or multicycle derivation from proximal Paleoproterozoic and Mesoproterozoic magmatic sources in the North Australian Craton (Halls Creek and King Leopold Orogens, Arunta Region) and Musgrave Province, with a minor exotic late Neoproterozoic component in some samples. An Ordovician sample from the far western Canning Basin appears to be mainly derived from Neoproterozoic Miles Orogeny granites of the nearby, and probably underlying, Paterson Orogen. Two Ordovician samples from the southeastern Canning Basin show detrital zircon age spectra similar to those of two samples of inferred Ordovician age from the western Officer Basin. These samples are dominated by late Neoproterozoic to early Cambrian and lesser mid- to late Mesoproterozoic zircons. Such a detrital zircon age fingerprint closely resembles a “pan-Gondwana” zircon signature previously identified in the Ordovician of the Amadeus Basin and widely recognised in eastern Australia. Although this could indicate a direct connection between the Canning and Amadeus Basins at this time, a more likely explanation is that sediment was transported via the Officer Basin into the southeast Canning Basin from its inferred ultimate source in central Antarctica. Post-Ordovician sandstones in the Canning Basin show mixed zircon age spectra consistent with reworking of multiple central Australian sources and “pan-Gondwana” zircons during and after the Alice Springs Orogeny.

23

Structural Architecture of Australia’s Southwest Continental Margin and Implications for Early Cretaceous Basin Evolution

L.S. HALL1, A.D. GIBBONS2, G. BERNARDEL1, J.M. WHITTAKER3, C.

NICHOLSON1, N. ROLLET1 & R.D. MÜLLER2 1Energy Division, Geoscience Australia, ACT 2601, Australia,

lisa.hall@ga.gov.au 2EarthByte Group, School of Geosciences, University of Sydney

3Institute for Marine and Antarctic Studies, University of Tasmania The southwest margin of Australia is a complex and relatively poorly studied offshore continental region that includes the Perth and Mentelle basins. A new, regional plate reconstruction model, developed for the whole of western Australia, is used in conjunction with regional seismic and potential field data to better characterise the along-strike variability of the southwest margin architecture. Results highlight how the structural architecture of the margin varies significantly along strike, as the relative orientation of the margin changes with respect to the Early Cretaceous extension direction. Margin segmentation is directly linked to the location of major oceanic fracture zones, as well as to the location and geometry of the major Palaeozoic to Mesozoic basins. Furthermore, correlation between margin segmentation and structural trends of the underlying Proterozoic Pinjarra Orogen suggests some level of basement control on margin evolution. Linking plate reconstructions and seismic studies provides new insights into Early Cretaceous basin evolution, including the relative timing of breakup within each sub-basin, the timing of accommodation generation and the distribution of break-up related igneous activity.

24

Analysis of Geobody Geometries within the Fluvio-Deltaic Mungaroo Formation, NW Australia

G. HELDREICH1, J. REDFERN1, B. LEGLER1, S. TAYLOR2, D. HODGETTS1, B. WILLIAMS1, & K. GERDES3

1 School of Earth, Atmospheric and Environmental Science, The University of Manchester, UK

georgina.heldreich@postgrad.manchester.ac.uk; 2 Shell Development (Australia) Pty Ltd, Perth

3 Shell International Ltd The Triassic fluvio-deltaic Mungaroo Formation is the main reservoir in the multi-TCF gas play offshore Northern Carnarvon Basin, NW Shelf, Western Australia. The study area is located NW of the Exmouth and Barrow sub-basins and lies within the Kangaroo Syncline and part of the Exmouth Plateau. This paper analyses geobody geometries extracted using amplitude analysis and blended frequency decomposition, from a high quality 3D seismic dataset covering approximately 560 km2. Within this stratigraphically complex succession, the sedimentary facies and seismic facies have been characterised by integrating well log, core data and seismic analysis, revealing a range of channel morphologies and dimensions. The dominant facies identified from core and well log analysis include; fluvial channel sandstones, overbank and floodplain / lake mudstones, coal intervals and intercalated, bioturbated mudstones and very fine grained sandstones indicative of lagoonal/ restricted embayment and periodic marginal marine depositional settings. Seismic attribute analysis, of a series of conformant horizon slices, image a range of geobody morphologies and dimensions. Dominantly straight to low sinuosity, large (approx. 1 - 2 km wide and 15 km long) and smaller scale (200–750 m wide and 5–10 km long) geobodies are interpreted to be channel belts / complexes. They can be clearly identified and cross-cut fault traces, indicating a pre-rift depositional setting for the Mungaroo Fm. High resolution imaging of this evolving fluvial succession has enabled better understanding of reservoir architecture and stacking pattern and is yielding valuable information on reservoir quality, distribution and connectivity, with significant implications for exploration and production.

25

Impacts of igneous intrusions on source and reservoir potential in prospective sedimentary basins along the western Australian continental

margin

S.P. HOLFORD1, N. SCHOFIELD2, C. A.-L. JACKSON3, C. MAGEE3, P.F. GREEN4 & I.R. DUDDY4

1Australian School of Petroleum, University of Adelaide, SA 5005, Australia 2School of Geography, Earth & Environmental Sciences, University of

Birmingham 3Department of Earth Science and Engineering, Imperial College, London,

4Geotrack International Pty Ltd,

Many prospective basins in rifted continental margins, including those located along the western Australian continental margin, contain extrusive and intrusive rocks generated during rifting and particularly during continental breakup. Intrusive igneous systems in rifted margin basins are typically characterized by networks of interconnected, laterally and vertically extensive sheet complexes (e.g. sills and dykes) that transgress basin stratigraphy. The presence of igneous rocks thus represents an important geological risk in hydrocarbon exploration. Constraining the distribution, timing and intrusive mechanisms of the igneous rocks is essential to reducing exploration risk. This paper focuses on two key sources of risk associated with the intrusion of igneous rocks into prospective sedimentary basins: (1) interconnected, low-permeability sheet intrusions (e.g. sills and dykes) that can compartmentalise significant volumes of source and reservoir rock, thereby reducing migration efficiencies; and (2) igneous-related hydrothermal circulation systems that can be highly mineralising and thus detrimental to reservoir quality. It is also important to highlight that igneous rocks may also be beneficial to petroleum systems. For example, the thermal effects of igneous intrusions may in some cases be sufficient to place immature source rocks within the oil window. The impacts of igneous intrusion on the prospectivity of rift basins along the western Australian continental margin are examined, with particular focus on frontier exploration areas such as the Exmouth Plateau and Browse Basin.

26

Detailed stratigraphic architecture of the Macedon Member turbidite reservoirs of the Stybarrow Field, NW Australia: an integration of

well, production and 3D/4D seismic data

C. HURREN1, G. O’HALLORAN1, G. DUNCAN1 & R. HILL1 1BHPBilliton Petroleum, Perth, Australia, chris.hurren@bhpbilliton.com;

The Late Jurassic-Early Cretaceous Macedon Member turbidite sandstones of the lower Barrow Group form the reservoir intervals of the Stybarrow Oil Field in the Southern Exmouth Sub-basin. Individual sand units range from a few metres up to 20 m in gross thickness. The distribution and shape of these sand bodies and interbedded shales fundamentally control the connectivity and flow characteristics (producibility) of the reservoir. This paper outlines how, through the integration of seismic, well and production data, and through the use of outcrop analogues, insights can be gained into detailed reservoir-scale stratigraphic relationships. The Stybarrow Oil Field benefits from the acquisition of three, high quality 3D/4D seismic datasets. The baseline data provides detailed imaging of fine-scaled stratigraphic relationships within the field. Two subsequent monitor surveys reveal changes in pressure and the movement of fluids since production began in 2007, which add further stratigraphic detail. An integrated depositional model for the Macedon Member of the Stybarrow Field has been derived. Three phases of deposition are evident and represent the initiation, aggradation and abandonment of a turbidite lobe complex. Compensational depositional processes between individual turbidite lobes and late stage erosion play an important role in controlling sand connectivity within the field.

27

Unlocking the origin of hydrocarbons in the central part of the Rankin Trend, Northern Carnarvon Basin, Australia.

D. JABLONSKI1, J. PRESTON2, S. WESTLAKE1 & C.M. GUMLEY1

1Finder Exploration Pty Ltd, PO Box 681, West Perth, WA, 6872 info@finderexp.com

23D Geo Pty Ltd The Rankin Trend has proven to be one of the most prospective areas within the Westralian Superbasin. It has a wide variety of hydrocarbon trap types, varying from simple structural with a single hydrocarbon-water contact to complex reservoir-trapping morphologies. These complex hydrocarbon fields exhibit a range of different pressure gradients, hydrocarbon properties and numerous vertical, lateral and horizontal seals within a single structural container. The recent major oil discoveries in Lady Nora 2 and Balnaves 1 have also challenged the pre-existing idea of the Rankin Trend as being exclusively a gas province. Interspersed between these major hydrocarbon discoveries are valid structures devoid of any hydrocarbons, suggesting a complicated migration charge history, which if not fully understood may lead to poor exploration decisions. Despite the resources discovered to-date and the remaining exploration opportunities, no published model exists to explain the observed differences in trap styles and contacts seen on the Rankin Trend. The conventional wisdom of local hydrocarbon charge generated “in-situ” within a single fault block is not sufficient to explain the variety of trap styles and column heights. A model is presented in this paper that incorporates well observations, pressure measurements, source rock characteristics and hydrocarbon properties. The model is placed in the context of seismic evidence including seismic direct hydrocarbon indicators (DHIs) to explain the variety of trap styles, hydrocarbon origin and charge history of the central Rankin Trend using a unified approach. The model proposes that both “in-situ” and “non in-situ” hydrocarbon charge and migration has occurred and is responsible for the nature and geometry of the present day discoveries. This model identifies the Victoria Syncline as the likely provenance for a significant proportion of the hydrocarbon resources discovered on the Rankin Trend (Goodwyn and Persephone). This hydrocarbon charge is inferred to come from the north/south-oriented Late Triassic to Early Jurassic grabens that have only recently become thermally mature. Hydrocarbon migration from the Victoria Syncline is unobstructed by any faulting with direct migration pathways into several of the Rankin Trend fields to the south. However north of the Victoria Syncline tortuous and fault-interrupted hydrocarbon migration pathways are observed which have no apparent connection with the generative Victoria Syncline, providing an explanation for the dry wells of the Brigadier Trend. As with any model, the concepts presented in this paper will need to be tested and re-fined as the complex origins of Northern Carnarvon fields are investigated further via exploration drilling.

28

Late Triassic–Mid-Jurassic to Neogene extensional fault systems in the Exmouth Sub-basin, North Carnarvon Basin,

North West Shelf, Western Australia

SUKONMETH JITMAHANTAKUL* AND KEN MCCLAY Fault Dynamics Research Group, Department of Earth Sciences, Royal

Holloway, University of London, Surrey, UK This paper documents a detailed tectono-stratigraphic analysis of five merged 3D seismic surveys that cover the greater part of the Exmouth sub-basin in the Northern Carnarvon Basin on the North West Shelf of Australia. The Exmouth sub-basin is a major, NE to NNE trending Mesozoic to Cenozoic depocentre within the intra-passive margin Northern Carnarvon Basin on the North West Shelf of Australia. Late Triassic (Rhaetian) to Middle Jurassic (Callovian), largely west-directed extension, produced N-S to NE-SW striking planar domino-style extensional fault systems that formed a NNE to NE trending rift basin, offset and segmented into 4 discrete depocentres by E-W striking accommodation zones. Three discrete and tectonically distinct systems of extensional faults have been identified within the Exmouth sub-basin - a) Rhaetian – Callovian planar fault systems of the major rift phase; b) Late Berriasian – Early Valanginian post-rift, strata-bound, planar domino fault arrays; and - c) Late Cretaceous – Neogene polygonal fault arrays formed during passive margin subsidence and sedimentation. The tectono-stratigraphic evolution of the Exmouth sub-basin is discussed and a revised model for the basin evolution and for the development of the fault systems is presented.

29

Analysis of seabed features and shallow stratigraphy for indications of fault reactivation and seepage: results from the 2012 marine surveys in the

southern Perth and Bonaparte basins

D. JORGENSEN1, I. BORISSOVA1, G. BERNARDEL1, A. CARROLL1, C. CONSOLI1, H. DULFER1, K. HIGGINS1, T. NICHOLAS1 & K. PICARD1

1Geoscience Australia, Canberra, Australia, diane.jorgensen@ga.gov.au;

In 2012, Geoscience Australia carried out marine surveys in the Vlaming Sub-basin (Perth Basin; GA0334) and Petrel Sub-basin (Bonaparte Basin; SOL5463). The purpose of these surveys was to gather pre-competitive geophysical and biophysical data on the seabed environments within targeted areas to evaluate the seal quality for CO2 storage studies in these sub-basins. Over the duration of the Vlaming Sub-basin survey, approximately 418 km2 of multibeam sonar data, 2370 line km of sub-bottom profiler (SBP) data, 6.65 km2 of sidescan sonar imagery, 4.25 km of video footage and 89 grab samples were acquired. The Petrel Sub-basin survey acquired more than 650 km2 of multibeam sonar data and 650 line km of multi-channel SBP data. A total of 114 sampling operations recovered shallow samples or video footage for sedimentological, biological and chemical analysis. These datasets have been used to investigate possible fluid migration pathways in the shallow subsurface geology. In the Petrel Sub-basin, the new data revealed the presence of banks, channels, plains, ridges and pockmark fields. In the Vlaming Sub-basin, the newly acquired data showed a Holocene sediment-starved system characterised by shallow valleys, shallow terraces, sediment mega-ripples and prominent ridges on the seafloor. The complexity of both these environments and the observed correlations between seabed features and the subsurface geology, suggest that a large number of processes interacted to produce the present geomorphology of the continental shelves. These new datasets will be used to support the regional assessment of CO2 storage prospectivity in the Vlaming and Petrel sub-basins.

30

Present-day seismicity and potential strike-slip reactivation in northwest WA

M. KEEP School of Earth and Environment, The University of Western Australia, Perth.

myra.keep@uwa.edu.au A number of sub-parallel, rhomboidal basinal features identified along the northwestern coastline of Western Australia occur in areas where present-day seismicity indicates strike-slip failure mechanisms dominate. This paper examines the rhomboidal features, documenting their orientation, scale, geomorphic and topographic expressions, elevation changes and slope gradients. Occurring at scales ranging from a few hundred metres to tens of kilometres in width, these angular-sided features have a narrow range of orientations between NW- and NE-trending. Topographic gradients up to 18.9% accompany sudden elevation changes that vary from 9 m to 125 m along the bounding lineaments. This paper explores geometric similarities between these rhomboidal features and known geometric relationships that occur in strike-slip environments, and proposes that in the present-day right-lateral strike-slip deformation mechanisms dominate the northwestern part of Western Australia.

31

The Exploration History of the Laurel Basin-Centred Gas System Canning Basin, Western Australia

DARRYL KINGSLEY & ERIC STREITBERG

Buru Energy Limited, Perth, Western Australia, darrylkingsley@buruenergy.com

Although evidence for a major gas resource in the onshore Canning Basin was present in wells drilled as early as the 1960s, the opportunity to develop these resources was not recognised until increasing oil and domestic gas prices stimulated a resurgence in Canning Basin exploration in 2006. Since then exploration has been focussed on the Early Carboniferous Laurel Formation within the Fitzroy Trough, with the initial four wells encountering up to 1500 m of continuous mud gas shows. However the significance of these shows was not recognised until 2011 when Basin-Centred Gas System (BCGS) concepts were introduced to the basin in response to the ‘shale gas revolution’ that had occurred in North America over the previous decade. Since 2011 seven strategically located wells have been drilled in the Fitzroy Trough targeting Laurel Formation gas. In addition to serendipitously discovering a significant new oil field (Ungani), these wells have confirmed the presence of a giant BCGS covering an area of approximately 38,000 km2 with elements typical of productive basins in North America. These are 1) low permeability 2) abnormal pressure 3) continuous gas saturation and 4) no down-dip water leg. The Laurel BCGS had been penetrated in eighteen wells prior to its ‘discovery’ in 2011. The fact that a gas resource possibly larger than the combined fields of the North West Shelf went unnoticed can be attributed to the absence of a cohesive geological model, combined with low commodity prices and immaturity of (and access to) reservoir stimulation technologies. This serves as a reminder that ‘you don’t know what you don’t know’, and provides a demonstration of the value of a clear vision coupled with a systematic, basin-wide evaluation in the context of evolving technology.

32

Northern Carnarvon Basin Hydrocarbon Recoveries using WAPIMS

E. KOPSEN Aardvark Exploration Consultants Pty Ltd

8/59 Dalkeith Rd, Nedlands, WA 6009 aardvark@space.net.au

The production history of producing and abandoned hydrocarbon fields in the Northern Carnarvon Basin has been used to derive the likely Technical Ultimate Recoveries from all field developments to a reference date of 30 November 2011. Many oil fields in the Barrow and Dampier sub-basins have demonstrated substantial reserves growth over time and have achieved better recoveries than originally anticipated, mainly resulting from the excellent reservoir quality preserved at the sub-Muderong Shale play level, where most of the Northern Carnarvon Basin hydrocarbon pools are trapped. The production histories and reserves growth of the Legendre, Harriet, Saladin and Griffin fields are reviewed. These field examples have proximal (layered) and fan sand (more homogeneous) reservoir facies in Barrow Group and stratigraphically equivalent reservoirs. Other than the Mardie Greensand reservoir at Saladin, the oil recovery factors in these fields all exceed 50%and may exceed 80% for the Saladin Barrow Group reservoir segment. The final production volumes from a number of oil fields will be double or threefold higher than their pre-production most likely recovery (P50) estimates. The anticipated aggregate Technical Ultimate Recovery for all 55 oil fields in the basin represents a growth of exceeding 27% above the collective expected pre-development/early production (mainly P50) volume. Gas field reserve growth is less demonstrable than for the oil fields, largely due to type of information that is publicly released. Several smaller gas fields have not achieved their published P90 gas reserves volume. The reason for the under-performance of these gas fields is uncertain but may relate to gross rock volume uncertainties and reservoir connectivity.

33

Acme Field Discovery, Carnarvon Basin WA

R. LAWRENCE Chevron Australia Pty Ltd, 250 St Georges Terrace Perth, WA 6000

RobertLawrence@chevron.com

The Acme Field was discovered in July 2010 by the Acme 1 well in permit WA-42-R in the North Carnarvon Basin by Chevron and its partner at the time, Shell. The discovery well was drilled in 878 m of water, and targeted a 27 km2 horst block located 5 km down-dip from the Chrysaor gas discovery and 6 km east of the Clio gas discovery. The well intersected 273 m of net gas pay across a 1057 m gross section of Triassic Mungaroo Formation before reaching TD at 4715 mMDRT. Each of the 7 reservoir zones penetrated by Acme 1 are in pressure isolation from one other. The main gas-bearing sand is the the AA Zone. Although the field area is relatively small, the significant vertical relief of the Acme structure (over 200 m) and surrounding lobes makes Acme a significant discovery. The Acme prospect was generated from detailed mapping of faults and stratigraphy and the evaluation of reservoir properties from seismic. The Acme 3D seismic survey, acquired in 2002, was the primary data source. Regional interpretations and analogues from surrounding 3D surveys were also incorporated into the pre-drill evaluation. During the drilling of Acme 1, a 108 m core was recovered from the Mungaroo Formation and a comprehensive wire-line program including MDT samples was conducted. Following the drilling of the well, a full petrophysical analysis confirmed the resource. The Acme Field forms an addition to Chevron’s plans to develop (these resources are not subject to FID yet) significant volumes of conventional gas resources (reserves are commercial) along the northwest continental shelf of Australia.

34

New observations of the post-Triassic succession in the central Beagle Sub-basin, Northern Carnarvon Basin, North West Shelf, Australia

M.E. LECH

Geoscience Australia, GPO Box 378, Canberra, ACT, 2601, Australia, megan.lech@ga.gov.au

In this study detailed mapping of seismic data from the 1529 km2 Beagle multi-client 3D seismic survey was undertaken to provide a better understanding of the geological history of the central Beagle Sub-basin. Situated in the Northern Carnarvon Basin, oil discovered at Nebo 1 in 1993 indicated the presence of at least one active petroleum system. The central part of the sub-basin has a N-trending horst-graben architecture. Two rifting events from the Hettangian to Sinemurian and the Callovian to Oxfordian were identified. A series of tilted fault blocks formed by the rifting events were locally eroded and progressively draped and buried by post-rift thermal subsidence sedimentation. Mapping indicated the Post-rift I Lower Cretaceous Muderong Shale regional seal is anomalously thin or absent in the intra-horst graben area. Burial history 1D modelling indicates that at Nebo 1, the most prospective potential source rocks within the Middle-Upper Jurassic section where in the early oil window; however, if present within the Beagle and Cossigny trough depocentres, these sediments would have entered the oil window prior to the deposition of the Muderong Shale regional seal. Upper Jurassic shales provide seal for the oil pool intersected in Nebo 1. The Tertiary section is dominated by a prograding carbonate wedge which has driven a second phase of thermal maturation observed in the Paleogene (Nebo 1) and Miocene (Manaslu 1). Potential source rocks are currently at their maximum depth of burial and maximum thermal maturity. Modest inversion on some faults prior to the Early Cretaceous has created traps and if source rocks retain generative potential, favourable traps could be now actively receiving hydrocarbon charge. Potential plays include compaction folds over tilted horst blocks, drape and small inversion induced anticlines, basin-floor fans and intra-formational traps. Deep faults may act as conduits for hydrocarbons migrating from mature potential source rocks into Jurassic to Cretaceous plays. Younger sediments appear to lack access to migration pathways provided by deeper faults.

35

Use of U-Pb geochronology to delineate provenance of North West Shelf sediments, Australia

C.J. LEWIS & K.N. SIRCOMBE

Geoscience Australia, GPO Box 378 Canberra ACT 2601 Australia, chris.lewis@ga.gov.au

Australia’s North West Shelf (NWS) has been the premier hydrocarbon exploration and production province for over 30 years. Despite the large number of geological studies completed in this region, numerous geological questions remain to be answered such as the provenance of reservoir units and how this relates to reservoir quality, extent and correlation. Industry involvement with sampling from wells has allowed detrital zircons to be dated using U-Pb geochronology to provide insights into the potential provenance and sedimentary transport pathways of reservoir facies of Triassic to Cretaceous age. Initial results reveal that the proximal Pilbara, Yilgarn and Kimberley cratons were not major protosources during the Middle to Upper Triassic. The prospective Mungaroo Formation contains a Triassic age population with an enigmatic source, but numerous grain characteristics suggest a volcanic source proximal to the Exmouth Plateau. Large proportions of data show a Neoproterozoic ‘Gondwana’ age distribution typically seen in sedimentary sequences elsewhere in Australia. Known igneous or metamorphic sources of this age are not abundant on the Australian continent suggesting some sediments on the NWS were derived from the Antarctic and Indian continents.

36

The Gorgon Field: An Overview A. MAFTEI, E.J. KING & M.C. FLORES

Chevron Australia Pty Ltd, 250 St Georges Terrace, Perth Western Australia 6000, alex.maftei@chevron.com.au

The Gorgon Field, a giant gas accumulation discovered in 1980, remained undeveloped for over three decades due to challenging subsurface and commercial factors. Situated in the Northern Carnarvon basin in 200-300 m of water, the Gorgon Field lies 130 km from the Australian coast. After discovery in 1980 (Gorgon 1) the field was subsequently appraised through seven additional wells. The Gorgon structure is a NNE-oriented Triassic horst block, 40 km long and with a width that ranges from 4 km in the south to 8 km in the north. The top of the structure is defined by the Intra-Jurassic Unconformity (IJU). Major bounding faults provide lateral closure for the Mungaroo Formation gas sands of the horst by juxtaposing them against shales with ages ranging from Berriasian to Early Jurassic. The Gorgon reservoirs contain dry gas with approximately 17% of non-combustible components (mainly CO2 and N2). The Gorgon Field comprises multiple sandstone reservoirs of the Late Triassic Mungaroo Formation, deposited within a fluvial environment. The reservoirs were deposited by amalgamated braided and low sinuosity channels. Lithologically the reservoirs are represented by quartz arenites and sublitharenites and have a low feldspars content. Kaolinite is present in most reservoirs, being the result of feldspar dissolution. The main factor influencing reservoir quality is grain size. The reservoirs are grouped into sandstone-rich intervals separated by claystone-siltstone dominated packages. The older sandstone-rich intervals constitute distinct hydrodynamic units with different pressure trends and fluid contacts. They also hold the majority of the gas within the field. Intra-horst post-depositional faults separate the field into segments, although the throws of these faults are generally insufficient to completely offset the older and thicker high net-to-gross packages, and this ensures their static lateral connectivity across the main part of the field. The field has more than 30 reservoir units with a complex pressure distribution due to intricate fault juxtaposition and uncertainties in the areal distribution and vertical stacking of the sandstone units, compounded by variations in data quality. The acquisition of higher quality wireline pressure testing data in the late 1990s together with the interpretation of 3D seismic data and the use of high-resolution stratigraphic techniques allowed the operator to more confidently correlate the reservoir units across the fault blocks, to predict the large scale static connectivity within the field and explain anomalous fluid or pressure occurrences due to presence of perched water compartments. Additionally, the extensive use of the 3D seismic inversion in mapping of the reservoir units allowed the evaluation of reservoir thickness away from well control. The mitigation of these uncertainties facilitated the decision to proceed to development. The development of the field was sanctioned in 2009 with development drilling commencing in 2011 and completed by August 2012. A total of 17 well penetrations now exist within the Gorgon Field, as well as a comprehensive set of modern subsurface data. The results of the drilling phase support the assumed large-scale static connectivity between the major reservoir units of the field and confirm the predicted thickness, structure and reservoir properties.

37

A new sequence stratigraphic framework for the North West Shelf, Australia.

N.G. MARSHALL1 & S.C. LANG1, 2

1. Woodside Energy Ltd. 240 St Georges Terrace, Perth, W.A., 6000, Australia. neil.marshall@woodside.com.au.

2. Present Address: Chevron Energy Technology Company, 1500 Louisiana St, Houston, Texas, 77002. USA.  simon.lang@chevron.com,  

The Mesozoic and Cenozoic of the North West Shelf can be subdivided into 18 broad stratigraphic intervals that show a remarkable degree of geological similarity from basin to basin. These intervals are termed "regional play intervals" and are related to the tectonic evolution and progressive breakup of Gondwanaland   along Australia's northwestern margin, initially as an intra-continental basin in the Triassic, and subsequent fragmentation through rifting and seafloor spreading during the Jurassic and Early Cretaceous. The stratigraphic architecture appears intimately linked to changes in accommodation space through time, where the key controls are the interplay between tectonics, eustasy, and sedimentation rates. The associated depositional settings range from fluvio-deltaic and mixed shelfal marine systems inboard to deep marine settings outboard and within the Jurassic rift systems. Over the last two decades, detailed sequence stratigraphic analysis of these regional play intervals and the finer-scale cycles within them has had a considerable impact on geological modelling at both the regional and reservoir scales. However, the challenge has always been to capture this detailed knowledge in an easily understandable system of nomenclature. The approach to this issue is to use a first and second stage subdivision of the numeric regional play intervals (e.g. TR20) to define regional to reservoir scale sets of stratigraphic surfaces. Of the 23 regional play intervals identified from the start of the Permian to the present day, 18 of the surfaces defining these units are sequence boundaries (SB), three are transgressive surfaces (TS), and two are maximum flooding surfaces (MFS). Further subdivisions within these intervals are defined by additional third order systems tracts and sets of reservoir scale surfaces named as erosive surfaces (ES) and flooding surfaces (FS). The benefits of adopting this new stratigraphic nomenclature have been more efficient data management, clearer and more consistent regional to reservoir scale geological modelling within specific basins, greater ease in being able to compare the models from different basins, and more transparent cross discipline knowledge transfer. By publishing this framework it is hoped that other operators will adopt and embrace the new nomenclature and thereby facilitate knowledge transfer across the industry.

38

Igneous intrusions in the Carnarvon Basin, NW Shelf, Australia.

K. McClay, N. Scarselli & S. Jitmahantakul

Fault Dynamics Research Group, Department of Earth Sciences, Royal Holloway University of London,

Egham, Surrey TW 20 0EX, UK

Many rifts and passive margin basins are characterised by dykes and sills that intrude the both pre-rift and syn-rift strata. In the southern part of the northern Carnarvon Basin sills and dykes are well imaged in a number of 3D seismic surveys. This paper focuses on the igneous features in the Coverack 3D seismic survey in the southern part of the Exmouth Sub-basin of the Northern Carnarvon Basin, North West Shelf of Australia. The sills typically occur at present day depths of 2–3 km in the domino-style faulted Upper Jurassic and Lower Cretaceous strata beneath the prominent Valanginian and Aptian unconformities. The sills are commonly 2–10 km across with wing-like apotheses at their edges. Many sills link to dykes that have intruded pre-existing Jurassic to Early Cretaceous age extensional faults. The sills and dykes do not occur above the Aptian unconformity and in several places extrusive flows were found at the Aptian unconformity indicating a Valanginian to Aptian age for the intrusions in this area. The emplacement of sills and dykes was strongly controlled by the pre-existing extensional faults as well as the stratal dips in the rift half-graben systems. The structural geometries of these NW shelf sill complexes are analysed and evolutionary models for sill and dyke emplacement are proposed.

39

Structural architecture of the Gorgon Platform, North West Shelf, Australia

K.D. MCCORMACK1,2 & K. MCCLAY1

1Fault Dynamics Research Group, Geology Department, Royal Holloway, University of London, Egham, Surrey TW2- 0EX, UK

2 now at Woodside Energy Ltd, kenneth.mccormack@hotmail.com The paper summarises a structural analysis of the NNE-trending Gorgon Platform, which hosts the Gorgon Gas Field, using the Triton 3D seismic survey. Located approximately 130 km offshore in water depths of 100-200 m the Gorgon Platform forms the southern termination of the Rankin Trend in the Northern Carnarvon Basin, North West Shelf Australia. Structural analysis identified four populations of extensional faults that constrain the evolution of the Gorgon Platform; (1) uppermost Triassic–Cretaceous NNE-trending extensional syn-rift faults, (2) Upper Jurassic–lowermost-Cretaceous WNW-trending extensional syn-rift faults, (3) Cretaceous polygonal post-rift fault tiers, and (4) Neogene faults attributed to gravity driven scarp collapse and mass-transport complexes. Seismic attribute and fault displacement/orientation analyses showed that initially segmented fault systems formed and were subsequently connected laterally and vertically by both soft- and hard-linkage relay structures. Changes in the orientations of principle stresses and/or reactivation of an antecedent structural fabric may account for the uppermost Triassic to Cretaceous NNE-trending faults and perpendicular Upper Jurassic to lowermost Cretaceous WNW-trending faults. This Triassic to Cretaceous syn-rift fault system influences the location and orientation of overlying Upper Cretaceous to Neogene post-rift polygonal faults and mass-transport-related deformation. This study illustrates the progressive evolution of the Gorgon Platform with implications for understanding the distribution, segmentation, linkages and ages of extensional faults within the Northern Carnarvon Basin. Fault analyses demonstrate that extension oblique to pre-existing uppermost Triassic to Cretaceous NNE-trending faults was partitioned into optimally oriented extensional fault populations and that a soft vertical linkage exists between syn-rift extensional fault systems and the overlying post-rift polygonal faults as well as to faults attributed to mass-transport processes.

40

Neotectonic evidence for a crustal strain gradient on the central-west Western Australian margin

A. MCPHERSON1, D. CLARK1 & B. WHITNEY2

1Earthquake Hazard Section, Geoscience Australia, GPO Box 378 Canberra

ACT 2601 Australia Email: andrew.mcpherson@ga.gov.au 2Centre for Offshore Foundation Systems, The University of Western Australia Compressional deformation is a common phase in the post-rift evolution of passive margins and rift systems. The central-west Western Australian margin, between Geraldton and Karratha, provides an example of a strain gradient between inverting passive margin crust and adjacent cratonic crust. The distribution of contemporary seismicity in the region indicates a concentration of strain release within the Phanerozoic basins that diminishes eastward into the cratons. While few data exist to quantify uplift or slip rates, this gradient can be qualitatively demonstrated by tectonic landforms which indicate that the last century or so of seismicity is representative of patterns of Neogene and younger deformation. Pleistocene marine terraces on the western side of Cape Range indicate uplift rates of several tens of metres per million years, with similar deformation resulting in sub-aerial emergence of Miocene strata on Barrow Island and elsewhere. Northeast of Kalbarri near the eastern margin of the southern Carnarvon Basin, marine strandlines are vertically displaced by a few tens of metres. A possible Pliocene age would indicate that uplift rates an order of magnitude lower than relief production rates in the northwestern margin of the Yilgarn Craton, where numerous scarps (e.g. Mount Narryer) appear to relate individually to <10 m of displacement across Neogene strata. Quantitative analysis of time-averaged deformation preserved in the aforementioned landforms, and in particular using fault scarp length as a proxy for earthquake magnitude, has the potential to provide useful constraints on seismic hazard assessments in a region containing major population centres and nationally significant infrastructure.

41

A Paleozoic perspective of Western Australia

A.J. Mory1,2 and P.W. Haines1 1Geological Survey of Western Australia, 100 Plain St, East Perth, Western

Australia 6004, arthur.mory@dmp.wa.gov.au; 2University of Western Australia

Inter-basinal correlations for the Cambrian to Carboniferous successions of Western Australia are mostly poorly constrained, largely due to unfavourable biogeographic factors, but also because biostratigraphic studies have been skewed to certain basins and intervals. By comparison, Permian inter-basinal correlations have benefited from numerous, mostly unpublished, spore-pollen studies, but correlations to the international timescale are poorly constrained because calibration of the latter is based largely on marine species that are rare in Australia. Nevertheless, a moderately robust correlation is possible for intervals of 10–30 m.y. in the Paleozoic, and reveals broad similarities between basins implying overriding far-field tectonic influences across west Australia. Devonian–Carboniferous events in central Australia—grouped together as the Alice Springs Orogeny—have the most obvious control, at least on the northern basins, but the underlying mechanisms, especially for the initiation of the intracratonic basins, remain obscure. The juxtaposition of west Australia against Greater India and other continental blocks, now dispersed throughout southeastern Asia, and the enormous thickness of Mesozoic successions along the North West Shelf, make unravelling Paleozoic structural history especially difficult. Isopach images reveal repeated reactivation of the major basin elements throughout the Paleozoic, implying continued propagation of Precambrian basement structures. Even so, the orientations of the mostly intracratonic northern and central basins (west-northwest) appear to have been the product of significantly different stress regimes than the basins on the western margin of the West Australian Craton (north to north-northwest). Westerly extension along the western margin of this craton appears to have commenced in the Devonian, whereas roughly northeasterly extension associated with events in central Australia controlled the development of the central and northern basins throughout the Paleozoic.

42

Reservoir Fluid Property Variation at the metre-scale: Origin, Impact and

Mapping in the Vincent Oil Field, Exmouth Sub-basin

A.P. MURRAY1, D.A. DAWSON1, D. CARRUTHERS2 & S. LARTER FRS3 1Woodside Energy Ltd., 240 St. Georges Tce., Perth, WA 6000.

andrew.murray@woodside.com.au 2The Permedia Research Group, Halliburton Corp

3University of Calgary Oil in the Vincent Field is uniformly derived from gas and light-oil prone Jurassic source rocks. However, fluid samples from different parts of the reservoir show highly variable solution GOR and in-situ viscosity. The excellent reservoir quality and lack of significant faulting means that conventional compartmentalisation is unlikely to be the cause of this variation. A geochemical study of oil and gas samples together with numerical mixing modelling has explained the origin and persistence of the observed fluid property variability.

Solution gas compositions and isotope signatures show that almost all of the gas in Vincent is secondary biogenic. At least part of this gas has migrated into the reservoir after the oil leg and is still in the process of mixing into it. The low buoyancy pressure has allowed even minor discontinuities in the reservoir to impede fluid homogenisation. Thus, fluid property variability has been able to persist over geological time and over very short distances despite the high average permeability and well connected reservoir.

Because the main source of gas is secondary biogenic there is a correlation between the isotope signature of methane and solution GOR. This allowed mapping of GOR and hence in-situ oil viscosity at high resolution, using the methane isotopes as a proxy. Over 500 mud gas samples were collected and the fluid property heterogeneity revealed by these measurements was far greater than anticipated, prompting re-evaluation of production behaviour. Mud gas isotope signature was also used to infer GOR and oil viscosity for a part of the field from which no fluid samples had been recovered.

43

Seismic stratigraphic relationships within a lowstand reservoir system: examples from the Barrow Group, Southern Exmouth Sub-Basin, NW

Australia

G. O’HALLORAN1, C. HURREN1 & T. O’HARA1 1BHPBilliton Petroleum, Perth, Australia, gerard.ohalloran@bhpbilliton.com

ABSTRACT: The Late Jurassic-Early Cretaceous Eskdale and Macedon members of the lower Barrow Group comprise some of the main oil-bearing reservoirs in the Exmouth Sub-basin. These high quality sandstones form the reservoirs in the Stybarrow and Eskdale oil fields. Understanding the architecture of these deepwater successions is important in both exploration and development projects. This paper documents detailed stratigraphic relationships and depositional geometries as defined on high quality seismic data sets and associated well data. An initial phase of lowstand deposition (Eskdale Member) is recorded by the development of two main canyon systems; the Eskdale and slightly younger Laverda canyons. These systems are remarkably well imaged on 3D seismic data, allowing for detailed definition of channel morphology and associated fill and spill facies. Channel complexes are up to 1 km-wide and 100 m-deep, and display evidence for multiple phases of erosion and in-channel aggradation. Overbank/spill facies are also identifiable, including crevasse lateral lobes and ‘chute’ channels. These canyon systems fed contemporaneous downdip basin floor fans that display a variety of classical fan morphologies and depositional elements including terminal lobes, fan pinchout edges, distributary channel systems and localised outflow facies. The distribution and morphology of the Eskdale and Laverda canyons and associated fan intervals can be related to topographic gradient changes within the basin (i.e. from shelf to slope to basin floor). These topographic changes are in turn a response to regional tectonism, in particular active rifting along basin margins. An ensuing phase of less confined, shelf-slope turbidite deposition (Macedon Member) records late-stage lowstand processes. Detailed well and seismic control from the Stybarrow Field and surrounding areas has identified multi-cyclic sands recording deposition of stacked turbidite lobes. These lobe complexes are more laterally continuous than the canyon facies and are comprised of amalgamated sheet sands and lower-relief channel sands, and are generally between 15–25m thick. In the greater Stybarrow area the original lobate geometries have been subsequently modified by a phase of late-stage erosion. Outcrop analogues for the Macedon Member can be seen in the lobe complexes from the Tanqua Fan intervals of the Karoo Basin, which are similar in both scale and morphology. These lobe complexes extend laterally for tens of kilometres with constituent individual lobes often displaying evidence for compensational depositional processes.

44

An integrated Regional Triassic Stratigraphic Framework for the Carnarvon Basin, NWS, Australia

T.H.D. PAYENBERG1, H. HOWE1, T. MARSH2, P. SIXSMITH1, W.S.

KOWALIK1, A. POWELL2, K. RATCLIFFE3, V. IASKY2, A. ALLGOEWER1, R.W. HOWE1, P. MONTGOMERY2, A. VONK2 & M. CROFT2

1Chevron Energy Technology Pty. Ltd., 250 St Georges Tce., Perth, WA 6000, Australia, tobi.payenberg@chevron.com

2Chevron Australia Ltd 3Chemostrat Australia

Stratigraphic correlation in kilometres-thick Triassic fluvial successions of the Carnarvon Basin, Northwest Shelf (NWS), Australia, has traditionally been hindered by a lack of continuous seismic events, low biostratigraphic resolution and the practice of lithostratigraphically correlating sandstone in well logs in the subsurface that are commonly discontinuous. To overcome these challenges, Chevron Australia tested and integrated multiple stratigraphic techniques to create a unified, Triassic regional stratigraphic framework across the entire Carnarvon Basin. This was achieved by integrating environment of deposition interpretations from core with high resolution biostratigraphy, chemostratigraphy, magnetostratigraphy, sequence stratigraphy, seismic stratigraphy and seismic geomorphology across the basin. Although core data provide the best basis for regional depositional environment mapping, their availability across the basin is sparse. Biostratigraphy and chemostratigraphy data, both of which can be collected on core and cuttings samples, show both chronostratigraphic and facies variability, which only become apparent when mapped regionally within a sequence stratigraphic framework. There are now 10 recognised biozones and 18 subzones within the Mungaroo Formation, and two biozones and five subzones within the Brigadier Formation. This data is complimented by 14 regionally recognised Chemostratigraphy packages. Seismic interpretation of higher confidence regional chronostratigraphic surfaces provides a three dimensional framework to constrain well based correlations that forms the basis for detailed field and prospect scale interpretation and reservoir analysis.

45

Development of a Regional Stratigraphic Framework for Upper Devonian Reef Complexes Using Integrated Chronostratigraphy: Lennard Shelf,

Canning Basin, Western Australia T.E. Playton1, R. Hocking2, P. Montgomery3, E. Tohver4, K. Hillbun5, D. Katz6, P. Haines2, K. Trinajstic7, M. Yan8, J. Hansma4, S. Pisarevsky4, J. Kirschvink9,

P. Cawood10, K. Grice7, S. Tulipani7, K. Ratcliffe11, D. Wray12, S. Caulfield-Kerney12, P. Ward5, P. Playford2

1Chevron Energy Technology Company, 1500 Louisiana St. Houston, Texas, 77002, USA

tedplay@chevron.com Questions regarding heterogeneity and architecture of reefal carbonate platform systems may be resolved by well-constrained chronostratigraphic frameworks, developed from the integration of multiple independent signals in the rock record. This makes possible a meaningful comparison of coeval stratigraphy and facies in different settings. For the Canning Basin Chronostratigraphy Project (CBCP), key outcrop transects and shallow cores were logged for lithofacies and sampled at sub-meter scale for magnetostratigraphy, stable isotope chemostratigraphy, conodont-fish biostratigraphy, biomarker geochemistry, and elemental chemostratigraphy. The dataset entails nearly 4 km of measured stratigraphy and 6800 samples of Middle and Upper Devonian (Givetian, Frasnian and Famennian) carbonate platform-top, reef, foreslope, and basinal deposits along the Lennard Shelf, Canning Basin, Western Australia. The extracted rock signals were integrated in conjunction with sequence stratigraphic concepts to generate a multi-facetted, regional chronostratigraphy and predictive lithofacies model across 250 km of the exposed Devonian reef complexes. Final results from the ongoing project will include: • high-resolution, high-confidence correlations across different carbonate

settings that were not achievable before using traditional biostratigraphy or sequence stratigraphic concepts;

• unprecedented examination of Lennard Shelf carbonate heterogeneity and architecture within the constrained framework;

• an integrated workflow for establishing robust chronostratigraphic frameworks that can be tailored for the subsurface;

• a magnetostratigraphic framework for parts of the Late Devonian (a period of uncertainty in the polarity reversal record), calibrated to biostratigraphic zones; and

• geochemical and elemental profiles that reflect sea level fluctuations, water column stratification/circulation, and biotic crises during deposition of the reef complexes.

The integrated framework and predictive depositional model for the Devonian reef complexes will be a comprehensive product that serves as an analogue for carbonate researchers and petroleum geoscientists worldwide.

46

Sedimentary and structural features of the Plio-Pleistocene Timor Accretionary Wedge, Timor-Leste

S. POYNTER, A. GOLDBERG & D. HEARTY

Eni Australia, 226 Adelaide Terrace, Perth, Western Australia, sarah.poynter@eniaustralia.com.au

The Timor accretionary wedge developed in response to the Neogene collision of the Australian Plate with the Banda Arc. New 2D and 3D seismic data acquired offshore Timor-Leste have been used to investigate the sedimentary and structural features of the synorogenic section. The Plio-Pleistocene Viqueque Group crops out along the southern coast of Timor, and is a regressive predominantly clastic bathyal to neritic succession. In the offshore area the section thickens considerably to more than five km and has been deposited in normal fault-controlled mini-basins above the thrusted and highly imbricated Cretaceous–Miocene Kolbano Group.

The Plio-Pleistocene section exhibits rotated fault block geometries generated by numerous SE-dipping listric faults. The listric fault geometry is interpreted to be related to gravitationally driven collapse of the rapidly deposited synorogenic sediments late in the development of the accretionary wedge. The shallow Pleistocene offshore synorogenic section has a broad open-folded layer-cake structural style. Slumps, turbidites, debris flows, channels and outer shelf deltas are imaged within this section. A bottom-simulating reflector (BSR) indicates the presence of gas hydrates, and amplitude brightening below the BSR signifies the presence of shallow gas sealed by the overlying hydrates.

47

Northern extension of active petroleum systems in the offshore Perth Basin—an integrated stratigraphic, geochemical, geomechanical and

seepage study

N. ROLLET1, M. PFAHL2, A. JONES1, J. KENNARD1, C. NICHOLSON1, E. GROSJEAN1, D. MANTLE3, D. JORGENSEN1, G. BERNARDEL1, R. KEMPTON4, L. LANGHI4, Y. ZHANG4, L. HALL1, R. HACKNEY1, S.

JOHNSTON1, C. BOREHAM1, D. ROBERTSON5, P. PETKOVIC1 & M. LECH1

1Geoscience Australia, Canberra, Australia, Nadege.Rollet@ga.gov.au; 2Santos Limited, Adelaide, Australia

3Morgan Goodall Palaeo Associates, Maitland, South Australia 4CSIRO Earth Science & Resource Engineering, Perth, Western Australia

5Woodside, Perth, Western Australia

A prospectivity assessment of the offshore northern Perth Basin was undertaken, as part of the Australian Government’s Offshore Energy Security Program, to provide new insights into the petroleum prospectivity of the basin and to reduce exploration risk. A sequence stratigraphic framework based on results from new biostratigraphic sampling and interpretation was developed. The existing tectonostratigraphic model was revised using 1D tectonic subsidence modelling constrained by stratigraphic and thermal data from well intersections for Permian to Cenozoic sequences. Geochemical studies of key offshore wells and results from a hydrocarbon seepage survey provided new findings on prospectivity of the Perth Basin. To mitigate exploration risks associated with trap breach during Early Cretaceous breakup, a trap integrity analysis was undertaken. The studies demonstrated that the late Permian–Lower Triassic Hovea Member (Kockatea Shale) oil-prone source interval is regionally extensive offshore in the outer Houtman and Abrolhos sub-basins. This is supported by fluid inclusion data that provide evidence for palaeo-oil columns within Permian reservoirs in wells from the Abrolhos Sub-basin. Oil shows in the offshore part of the basin can be linked to potential Early Permian and Jurassic potential source rocks. A number of potential plays were identified by the study. Geomechanical analyses proposed a predictive approach to prospect assessment. This analysis showed that faults oriented within the quadrant NNW to ESE have a high risk of reactivation and that high permeability zones at fault intersections are prone to leakage. Optimally-oriented large faults preferentially accommodate strain and shield nearby structures from reactivation. Hydroacoustic flares, pockmarks and a dark coloured viscous fluid observed during the marine survey over potential seepage sites on the seafloor may indicate an active modern-day petroleum system in the Houtman Sub-basin.

48

Depositional Analogues & Subsurface Uncertainty Management: Implications for Reservoir Characterisation & Modelling

S.P. Sadler, S.C. Lang, R.J. Seggie, K. Adamson, N.G. Marshall, D.P. Harris

& J.A. Spilsbury-Schakel. Woodside Energy Ltd., Woodside Plaza, 240 St Georges Terrace, Perth, WA

6000, Australia; shaun.sadler@woodside.com.au Understanding and managing subsurface uncertainty is one of the key elements in project maturation and delivery for both exploration and field development. A variety of geostatistical processes and methodologies are employed to address this issue, commonly via the construction and flow simulation of geocellular models. Capturing the range of potential subsurface outcomes is dependent on characterisation of reservoir in terms of depositional processes and environments, sequence stratigraphic context, flow unit architecture and connectivity. This characterisation is often based on very limited and/or low resolution subsurface datasets. Over-simplified geological models based on such data fail to effectively predict reservoir performance through time. Subsurface datasets are placed in context by regional stratigraphic and depositional models, but can only be used to effectively frame the range of uncertainty through integration with appropriate depositional analogues. Typically this requires access to focussed leading-edge research programmes. Analogues support the definition of alternative scenarios and realisations for integrated reservoir modelling workflows. They are thereby translated into a tangible impact on the risk profile and value proposition for exploration and development activities. Their influence can extend to supporting major investment decisions associated with the design of wells and production systems. The value associated with investment in analogue research is realised through the effective delivery of data and concepts in a format that can be readily incorporated into subsurface workflows.

49

Submarine slide and slump complexes, Exmouth Plateau, NW Shelf of Australia

N. Scarselli1*, K. McClay1 & C. Elders1

1Department of Earth Science, Royal Holloway University of London, Surrey, UK, n.scarselli@es.rhul.ac.uk

Analysis of 3D seismic data shows that the Neogene to near seabed section along the NW flank of the Exmouth Plateau Arch has been affected by numerous slope failures. Seabed collapses originated at water depths of ~1000 m and extend down dip to depths well in excess of 1500 m. A wide spectrum of slope failures have been identified, from coherent slides, incoherent slumps to mass flow deposits the product of debris-flows and turbidity currents. The slides in the study area are characterized by proximal slide fault block systems that are expressed at the seafloor as extensional ridges up to 500 m wide and 1 km long. The up-dip extension is matched by down-dip toe thrusts. The downslope toe is characterized by imbricate thrusts with fault-related folds that form a prominent fold belt at the seabed. The over-thickened leading edge of the toe-thrust systems commonly has undergone gravitational collapse resulting in second-order toe slides detached at shallower stratigraphic levels. Slump systems are characterized by contorted seismic facies that rest on top of erosive basal shear surfaces that are typically strongly striated. These striations are commonly arranged in multiple crosscutting sets. Detailed analysis of the orientation and crosscutting relationships of these sets suggests a complex multi-stage evolution of slumps. Progressive down slope disaggregation at the leading edge of slumps promoted the development of mass flows. These are characterised by strongly erosive canyons that link slumps to down dip debris flow and turbidite fans. The results of this work broaden our knowledge of the distribution and characteristic of slope failure in the Exmouth Plateau and shows that multiple slope processes can develop and coexist within a single event and hence produce a final composite failure.

50

Depositional and volcanic history of the Early to Middle Jurassic deltaic reservoirs in Calliance and Brecknock fields (Plover Formation), Browse

Basin, North West Shelf, Australia

F. TOVAGLIERI1,*, A.D. GEORGE1, T. JONES1, H.ZWINGMANN1,2

1School of Earth & Environment, University of Western Australia, Crawley, WA 6009, Australia

2CSIRO ESRE, P.O. Box 1130, Bentley, WA 6102, Australia *Corresponding author: tovagf01@student.uwa.edu.au

The Early to Middle Jurassic Plover Formation in the Browse Basin hosts reservoirs currently targeted for gas exploration and development. Integration of core-based sedimentology, igneous petrology, borehole image and wireline log analysis, with biostratigraphic and seismic data has been used to establish the deposition history and paleogeographic evolution of the Plover Formation in the Calliance and Brecknock fields within a sequence-stratigraphic framework. Seven siliciclastic facies associations have been interpreted as fluvial channel-fill (FA0), tidally influenced channel- and tidal channel-fill complexes (FA1-FA2), crevasse-splay and interchannel marsh (FA3), heterolithic mouthbars (FA4), sandy mouthbars (FA5) and offshore-transition to offshore (FA6) depositional settings. These associations record deposition on a tidally influenced delta plain to delta front. Six coherent igneous units in cored intervals are interpreted mostly as flow units with alkali basalt–trachybasalt (Calliance) to basaltic trachyandesite (Brecknock) compositions. A distinct compositional change to tholeiitic basalt is recorded above the Plover Formation in Brecknock 4. Volcaniclastic units comprising autobreccias and sediment gravity- flow deposits are associated with the coherent units. Five third-order stratigraphic sequences (S1 to S5) of ~1.5-9 myr duration are recognised. A major event interpreted at the base of S4 is associated with a significant time gap. S4 and S5 were deposited during a period of higher subsidence rates which allowed the accumulation of anomalously thick sandstone packages that constitute the main gas reservoirs in the area.

51

Discovery to Development: A Subsurface Case History of the Kitan Oil Field, Timor Sea.

D. WHELLER1, G. ELLIS1 Y. SUHARDIMAN1, R. YOKOTE1, D. SELVAGGI2,

J. DERRIJ1, G. MANISCALCO1 1Eni Australia Ltd, Eni House, 226 Adelaide Terrace, Perth, Australia,

David.Wheller@eniaustralia.com.au 2Eni Indonesia, Plaza Kuningan South Tower, Jakarta, 12940 Indonesia

The Kitan Oil Field is located in the northern Bonaparte Basin within the Joint Petroleum Development Area (JPDA), an area jointly administered by Timor-Leste and Australia. The Kitan structure is a Jurassic E-W trending tilted fault block. The Kitan 1 exploration well was drilled and successfully tested in early 2008. Kitan 2 appraisal well was drilled immediately after Kitan 1 and intersected the reservoir up-dip from Kitan 1 and confirmed the extension of the oil accumulation. The main oil-bearing section is within the shallow marine sandstone of the Middle Jurassic Laminaria Formation. It is divided into two reservoir units; a blocky channelized sandstone (Unit 2) overlain by a dominantly finer-grained succession composed of coarsening-upwards para-sequences (Unit 1). The Kitan Oil Field was declared a commercial discovery in April 2008 and a Field Development Plan was submitted in May 2009 and approved in April 2010. Four development wells were drilled of which three were completed as producers, each employing an intelligent completion design, to enable independent control and monitoring of the two reservoir units. The three wells were tied back subsea via flexible flowlines and risers to the Glas Dowr FPSO. Oil production from Kitan commenced in October 2011, some 3.5 years after the discovery of the field. The fast-track development of the Kitan Oil Field was achieved due to accelerated appraisal, prompt completion of studies, early commitment to long lead items and support from Joint Venture partners and the Autoridade Nacional do Petróleo (ANP) in Timor-Leste. Early production results indicate that the field performance is better than pre-development base case expectation. A review of the geological model was performed and the seismic depth conversion updated in order to obtain a reasonable dynamic simulation history match and revised production forecast.

52

Tectonic evolution and continental fragmentation of the southern West Australian margin

J.M. WHITTAKER1, J.A. HALPIN2, S.E. WILLIAMS3, L.S. HALL4, R.

GARDNER5, M.E. KOBLER5, N.R. DACZKO5 & R.D. MÜLLER3 1The Institute for Marine and Antarctic Studies, University of Tasmania,

Hobart, Australia, Jo.Whittaker@utas.edu.au 2ARC Centre of Excellence in Ore Deposits, University of Tasmania

3EarthByte Group, School of Geosciences, University of Sydney 4Geoscience Australia

5Department of Earth and Planetary Sciences, Macquarie University

Continental rocks dredged in 2011 show that the Batavia Knoll and Gulden Draak Knoll, two prominent bathymetric features located ~1600 km offshore Perth, are micro-continents. Plate tectonic modeling reconstructs the pre-rift position of these knolls to the north and south of the Naturaliste Plateau, respectively. The Batavia Knoll was conjugate to part of the northern Naturaliste Plateau, while the Gulden Draak Knoll was conjugate to the western Bruce Rise, Antarctica. Here, we compare basement rocks, patterns of sedimentation, volcanism and structure on the better studied Naturaliste Plateau, Mentelle Basin and Bruce Rise with newly collected data from the knolls. Significant volumes of metamorphic and granitic basement rocks were dredged from both the Batavia and Gulden Draak knolls. Preliminary geochronological and geochemical analyses show that these rocks are continental in nature and include protolith granitoids that were emplaced during the Archaean (~2850 Ma) and the Mesoproterozoic (~1290-1200 Ma) (Gulden Draak Knoll), and during the Early Palaeozoic (~540-530 Ma) (Batavia Knoll). All metamorphic rocks were invariably reworked during the Kuunga Orogeny (~550-500 Ma) during the final assembly of Gondwana. Sediment accumulations are generally relatively thin (up to a few hundred meters) on all the continental fragments, with the exception of NNE to NE oriented rift basins with up to ~2 km of sediments. Sedimentary rocks, predominantly sandstones were dredged from adjacent to the interpreted rift basin locations on both the Batavia and Gulden Draak knolls. Volcanic/intrusive material has been interpreted on the northern flank of the Naturaliste Plateau from seismic profiles, but no basalts were found in either of the Batavia Knoll dredges. Extensive volcanism has also been interpreted on both the Naturaliste Plateau and Bruce Rise. Volcanic material was dredged in one of two sites on the Gulden Draak Knoll, and geophysical data may support the presence of an igneous domain. The structural, volcanic and sedimentary nature of the knolls will be tested in late-2014 with the collection of new magnetic, gravity, seismic reflection and dredge data.

53

Newly-recognised continental fragments rifted from the West Australian margin

S.E. WILLIAMS, J.M. WHITTAKER* & R. D. MÜLLER

EarthByte Group, School of Geosciences, University of Sydney, Sydney, Australia, Simon.Williams@sydney.edu.au

*Now at: the Institute for Marine and Antarctic Studies, University of Tasmania, Hobart, Australia.

The southwest Australian margin formed at the nexus of rifting and breakup between India, Australia and Antarctica in the Early Cretaceous. Studying the basin evolution along this margin has been hampered by a lack of data from the offshore Perth Abyssal Plain (PAP), and from the conjugate Greater Indian margin, which was highly deformed during collision with Eurasia. Here, we present new data (magnetic anomaly profile data, swath bathymetry, and dredge samples) constraining the evolution of the PAP, collected during voyage ss2011/v06 of the RV Southern Surveyor in late 2011. The Batavia Knoll (BK) and Gulden Draak Knoll (GDK) are two prominent, previously unsampled bathymetric features located >1600 km offshore Australia that have been assumed to be igneous features. Successful dredges on the western flanks of both knolls recovered continental basement rocks, revealing that both knolls are microcontinents. We use quantitative analysis of shiptrack magnetic profiles combined with satellite gravity anomalies to estimate the extent and spatial variation in thickness of the continental crust. Sediment thickness estimates are made using depths to magnetic sources for shiptrack profiles. The geophysical data provide evidence for basin structures within the knolls of a similar scale to those imaged within other fragments of stretched continental crust such as the Naturaliste Plateau. Interpretation of previously unidentified M-series anomalies in the Perth Abyssal Plain, combined with dredge data, support a reconstruction model where the BK and GDKs are microcontinents that initially rifted with Greater India during breakup with Australia at ~130 Ma. As seafloor spreading ceased in the PAP at about 105-100 Ma, a westward ridge jump led to the rifting of the BK and GDK from Greater India.

54

The Stratigraphy of the Pyrenees Member of the Ravensworth, Crosby and Stickle Fields, Exmouth Sub-basin, Northwest Australia: A wave-

and storm-dominated shelf-margin delta.

M. WOODALL1 & C. STARK2 1BHPBilliton Petroleum, Perth, Australia, mark.a.woodall@bhpbilliton.com

2Firmground Pty Ltd, Nelson, New Zealand

The Pyrenees Member of the Lower Barrow Group within the Exmouth Sub-basin, offshore Western Australia, forms part of the Pyrenees Shelf Margin Delta which constitutes the highly productive reservoirs of the Ravensworth, Crosby and Stickle oil and gas fields. Previous work grouped the Pyrenees Member into the highstand depositional phase of a 3rd order sequence. This study provides a high-resolution, 4th and 5th order sequence-stratigraphic framework used in the development of the Ravensworth, Crosby and Stickle hydrocarbon accumulations. A facies classification scheme was defined from petrology and detailed core-calibrated high-resolution resistivity image-log analysis, with eleven discrete depositional sub-environments recognised. Regional correlations through the Pyrenees Fields resulted in the identification of three discrete 4th order sequences. Sequence 1 is dominated by highstand, shelf to shoreface deposits, marking the onset of the shelf margin delta. Sequence 2 is dominated by a transgressive phase of deposition, with a reduction in the available accommodation space and a switch to more tidally-influenced lower delta plain deposition. The onset of Sequence 3 is characterised by a sharp base-level shift and the development of a thick lowstand succession. A subsequent transgression is associated with regionally extensive flooding leading to the development of a significant intra-formational seal. A maximum flooding surface signifies the onset of the last stage of deposition which consists of prograding highstand shoreface deposits dominated by wave processes.

55

Structural interpretation of the northern Canning Basin, Western Australia

Y. Zhan & A.J. Mory

Geological Survey of Western Australia, Department of Mines and Petroleum, 100 Plain St, East Perth, Western Australia 6004; yijie.zhan@dmp.wa.gov.au

Seismic profiles in the northern Canning Basin reveal a major WNW-oriented strike-slip fault zone in the Fitzroy Trough. The zone bisects the trough and was generated during the Triassic–Jurassic Fitzroy Transpression. It contains likely flower structures north of Yulleroo 1, whereas to the east it is dominated by folds and westward-dipping normal faults. A relay ramp encompassing Grant Range shows a series of NW-oriented fault splays indicative of right-lateral slip during the Fitzroy Transpression. Deformation at this time produced N-S compression as well as E-W extension, evident as a series of E-W trending folds and N-S faults mostly stepping down to the west. Reactivation of the Fenton and Pinnacle fault systems during the Fitzroy Transpression is characterised by structural inversion, with extension to the northwest. Intrusions, mostly doleritic, near Fraser River 1 and East Yeeda 1, are probably associated with this wrenching. During the Carboniferous maximum crustal extension was about 14 km in the middle of the Fitzroy Trough, and is associated with an offset on the Pinnacle Fault along the northeast margin of the trough near Meda 1. The amount of shortening is consistent within the trough during the Fitzroy Transpression. As most of the large structures in the trough were breached at this time or by subsequent erosion, small fault blocks and stratigraphic traps are the most likely targets for petroleum exploration.