A full list of abstracts are available on www.pesa.com.au/aapg/aapgconference/abstracts.htm
Stratigraphic Framework of the Cenozoic Carbonates of the Northern Carnarvon Basin, North West Shelf, Western Australia
Kinna, Belinda M.1, Malcolm W. Wallace1, Stephen J. Gallagher1
(1) University of Melbourne, Melbourne 3010, Australia
The North West Shelf extends 2400kms along the Western Australian margin and is divided into the Carnarvon, Canning, Browse, and Bonaparte sedimentary basins. Significant quantities of carbonate were deposited on this shelf during the Cenozoic. These carbonates are the dominant cover sequence to the hydrocarbon-producing Mesozoic successions and cause considerable problems in the seismic interpretation of structural traps due to strong lateral variations in sonic velocity. Despite their large distribution, stratigraphic thickness and interference with seismic interpretation, these carbonates have remained poorly documented. Using seismic properties, geochemical analyses (carbonate and elemental), well log data, petrological data and foraminiferal analyses, this study establishes the stratigraphic framework of Cenozoic carbonates in the Exmouth-Barrow sub-basins, Northern Carnarvon Basin. These carbonates were divided into six lithological facies, from oldest to youngest; basinal facies, slope facies, shelf facies, planktonic ooze/canyon fill facies, sand barrier facies, and ramp facies. The sequence represents a shallowing upwards sequence from Eocene to Early Pliocene age. The base of the sequence is dominated by deep basinal facies, overlain by prograding Oligocene-Miocene shelf and slope sediments. These are inturn overlain by quartz-rich sediments interpreted to represent a sand barrier. A transgression during the Pliocene altered the depositional environment and formed a prograding ramp. This study is one of the first to concentrate on both the stratigraphy and the geological controls on sonic velocity in Cenozoic carbonates of the North West Shelf.
Dryland Sequence Stratigraphy of Fluvial-Lacustrine-Aeolian Depositional Systems – Examples from the Neales River, Western Lake Eyre, Australia
Krapf, Carmen B.E.1, Simon Lang2, Mario Werner1, Mark Reilly3, Victor Waclawik3, Tobias Payenberg3
(1) The University of Adelaide, Adelaide, Australia (2) University of Adelaide, Adelaide, Australia (3) Australian School of Petroleum, University of Adelaide, Adelaide, Australia
Sequence stratigraphy in dryland successions has important implications for exploration and reservoir correlation in continental basins. A useful outcrop analogue is the Neales River, western Lake Eyre, Australia. A high-resolution record of fluvial, aeolian and lacustrine deposits (10 m thick) of Late Pleistocene is exposed along the Neales Cliffs. Five major sedimentary units (equivalent to systems tracts) have been identified, reflecting a variety of changes in sedimentary processes, depositional environment and base level illustrating preservation of a complex stratigraphic architecture.
Following the ~200ka interglacial maximum, a drying-up systems tract is represented by a fluvial fining-upward trend, with palaeosols at the top (Unit 1). A wettening-up systems tract followed when lake level rises to +10m AHD during the last interglacial resulting in a lacustrine succession (Unit 2), but punctuated by regular dessication events. During the following drying-up systems tract, progressive lake level fall resulted in deep incision around 100 Ka, followed by enhanced fluvial deposition of fine-grained sediments (Unit 3). A brief rise in base level resulted in a wettening-up systems tract comprising a thin veneer of fluvial/alluvial sediments (Unit 4). During the last glacial maximum (peaking at 18ka), aridity increased in the tropical belt globally. This was accompanied by increasing strength and activity of the trade winds, and lead to increased dune build up and gibber plain development, stabilised in association with lake level rise around 8 Ka. Subsequent lake level fall to the present lake level of -17 m AHD, resulted in deep incision (~10 m) of the Neales River.
Bayu-Undan – From Stratigraphy to Dynamic Simulation
Krieger, Frank W.1, David R. Mabee2
(1) ConocoPhillips Australia Pty Ltd, West Perth WA, Australia (2) ConocoPhillips Australia Pty ltd, West Perth WA, Australia
The Bayu-Undan Field lies in the Timor Sea to the NW of Australia and is a world scale retrograde gas-condensate accumulation.
The hydrocarbon bearing reservoir section comprises the Bajocian to mid Callovian Plover Fm deposited in a tidally influenced, fluvially dominated delta system. Overlying this is the mid-Callovian to Oxfordian Elang Fm which is made up of five progradational pulses within an overall transgressive system culminating in the drowning of the delta system.
Critical to understanding both GIIP and the dynamic behaviour of the field is the distribution and connectivity of the reservoir and the interplay between erosion and structural position.
Fieldwide correlation in the Elang Fm is relatively straightforward with large shale breaks between progradational pulses when good quality sands were deposited. The Plover Fm is more problematic due to the absence of detailed biostratigraphic markers in a relatively barren fluvial section.
The desire to produce a realistic, flow unit based simulation model for the Plover, where >70% of recoverable resources lie, has resulted in the use of detailed ichnofacies and chemostratigraphy to help constrain a carefully considered sequence stratigraphic approach.
The new stratigraphic framework for the Plover Fm coupled with an accurate erosional model for the Elang Fm allows robust characterization of GIIP. However, more importantly, it allows an assessment of the impact on ultimate recoverable resources, of reinjection of lean gas, and of water production; especially when considered in conjunction with rigorous fault modelling.
Depositional Analogues and Sequence Stratigraphy for Late Triassic Fluvial Reservoir-Prone Successions of the Rankin Trend, Northwest Shelf, Australia
Lang, Simon C.1, R. J. Seggie2, Neil Marshall2, David Alsop2, Chris Cubitt2, Robert Kirk3
(1) Woodside Energy Ltd, Perth, Australia (2) Woodside Energy Ltd, Australia (3) Rob Kirk Consulting
The Late Triassic of the Goodwyn-North Rankin trend on the NW Shelf, Western Australia, consists of a thick non-marine to marginal marine succession. The region contains several large gas fields hosted mainly within the Mungaroo Formation and overlying Brigadier Formation, forming a large scale back-stepping succession (2nd order transgressive sequence set).
The Mungaroo succession comprises numerous stacked fining-upward successions bounded by third order and fourth order sequence boundaries, typically beginning with multistorey high nett-gross, mainly coarse-grained, cross-bedded, bedload-dominated, fluvial channel sandstones. These lie within discrete incised valley fairways based on seismic amplitude horizon slices using 3D seismic. These are overlain by more isolated fluvial channel sandstones (low-sinuosity avulsion belts) and associated crevasse splays, encased within grey to variegated, fine-grained floodplain sediments. Several key fine-grained intervals include carbonaceous paleosols (gleysols) grading to coal, overlain by laminated lacustrine shales that occur throughout the succession marking maximum accommodation intervals that facilitate correlation between wells. In some places more mature variegated and reddened paleosols highlight sequence boundaries developed on interfluves, and are interpreted to correlate laterally to sandstone filled incised valleys.
Analogues used to assist understanding of reservoir geometry and likely connectivity include the fluvial systems of the Gulf of Carpentaria, northern Australia. This region contains low sinuosity sandy rivers that lie within discrete incised valleys and multilateral channel-belts, associated with broad crevasse-splay/channel margin facies that grade into floodplain with increasing paleosol development away from the channel belt. The lower alluvial plain grades into coastal plain where higher sinuosity channels, swamps and shallow lakes predominate.
Clastic Shelf to Deepwater Sediment Delivery Systems – an Analogue from the Eastern Australian Continental Margin
Lang, Simon1, Ross Powell2, Ron Boyd3, Kevin Ruming3, Ian Goodwin3, Tobias H.D. Payenberg1, Marianne Sandstrom4
(1) University of Adelaide, Adelaide, Australia (2) Northern Illinois University, (3) University of Newcastle, Callaghan, Australia (4) Australian School of Petroleum, Adelaide, Australia
The terminus of a 2000km long, clastic littoral drift system at the eastern Australian continental shelf break offshore from Fraser Island, may provide a useful analogue for deepwater exploration offshore from wave-dominated margins lying along strike from major lowstand sediment accumulations (e.g. West Africa, NW Australia, SE Asia).
Using >4000 km2 of multibeam swath mapping and seismic profiling from 20 m to 4300 m collected on the RV Southern Surveyor research cruise in January 2005, sediment pathways were mapped showing highstand shedding of clean sandy clastics directly to deepwater via narrow canyons and gullies incised into a relict (Pleistocene and Miocene) carbonate platform. On the shelf, seismic reveals a small incised valley feeding a lowstand delta wedge covered by a broad sheet of tidal delta sand bodies. On the slope, seismic reveals canyon/gully clastic fills, inter-canyon/gully slope apron drapes, and a giant debrite field (20 km x 15 km). The lower slope shows channels and levees leading to the abyssal plain. Deeply incised, shelf margin gullies funnelling shallow shelf sands directly into canyons cut deeply into interbedded slope sediments and underlying sediments. Grab samples from the canyons reveal clean quartz sands that feed an axial canyon parallel to the toe of the slope (>3900 m) containing a channel and levee system that feeds a frontal splay complex (>4300 m). On the slope, outside the gullies and canyons, is a drape of stratified hemipelagic clays, and very fine-grained quartz-foraminiferal sands, interbedded with pelagic carbonate foraminiferal ooze, glauconitic clays and fine sands. The muddy debrites show a chaotic seismic character. The dataset is a useful analogue for understanding reservoir presence in comparable settings in petroleum basins.
Reverse Structures in Accommodation Zone and Early Compartmentalization of Late Jurassic Extensional System, Laminaria High (NW Shelf, Australia)
Langhi, Laurent1, Gilles D. Borel2
(1) Lausanne University, Lausanne, Switzerland (2) Museum of Geology, Lausanne, Switzerland
The sediments dynamic and structural development associated with the Late Jurassic rifting phase represent the key factor on the accumulation of hydrocarbon in the Timor Sea. On the Laminaria High (Bonaparte Basin) the main Oxfordian-Kimmeridgian E-W fault systems form structural traps where several discoveries have been made.
These E-W fault systems consist of a complex series of sub-parallel faults that connect via relay ramps or accommodation zones. One of these zones is associated with a transverse anticline resulting from the development of a positive flower structure. This secondary reverse structure, associated with significant impedance anomalies, has been revealed by the integration of 3D seismic interpretation, attribute mapping and classification and classic structural analysis.
The formation of such a reverse structure in extensional setting is related to the evolution of the main associated E-W fault plan which grows by addition of secondary, en echelon, tip faults. Isopach analysis and displacement pattern suggest a zone of differential displacement occurring between the parent and a tip segment of the main associated E-W fault plan and inducing a local left-lateral strike-slip movement associated with transpressional uplifts.
This structure compartmentalizes the early development of the adjacent graben and then controls the distribution of the syn-rift Frigate Fm (Oxfordian-Kimmeridgian).
It possibly affects the local migration of fluids as highlighted by amplitude anomalies associated with the domal anticlines and the reverse faults on the top of the Laminaria sandstone (Callovian-Oxfordian).
Reservoir Enhancement Processes for Carbonates of Northern Gondwana
Lapointe, Philippe A.1, Andrew Barnett1, Jacqueline Camy-Peyret1, Georges Nely1
(1) TOTAL E&P, 64018 Pau, France
The Alpha field, in the Timan Pechora Basin (Komi Republic, CIS), is a multihorizon oil-bearing reservoir. The Upper Devonian carbonates of Reservoir A and Permian carbonates of Reservoir B suffered a series of long term subaerial exposure that resulted in reservoir characteristic improvements.
The Interpretation of the 3-D seismic data using the in-house developed Sismage software suggested that karst occurred in the Frasnian / Fammenian section in close relationship with the structural features and that karst generated epikarst and collapse created breccia with impact on the Permian carbonates deposition.
Detailed examination of the Devonian cores supports the karstic nature of the reservoir showing conduits, caves network, fissures enlarged by leaching, karstic breccia, and speleothems. The following karst scenario is proposed: 1) several sub-aerial emersion events occurred during Upper Devonian times triggering coastal karst or epikarst, partly controlled by structural geology (fracture and fault patterns) and partly controlled by sedimentary facies distribution; 2) later hydrothermal endokarstic dissolution occurred prior to oil migration and was controlled by a later, post-compaction tectonic event and the pre-existing heterogeneities.
The Permian carbonates deposition was structurally controlled by high and lows somewhat related to large scale hydrothermal collapse and faulting controlling lower Permian anhydrite dissolution. The carbonate platform suffered probably long term sub aerial exposure which evidences are found in several wells that resulted in calcrete palaeosol development at the top of the Microcodium invaded zone, indicated by rhizocretions.
A Holistic Model to Describe Charge and Retention History of the Northern Bonaparte Basin, Australia
Lisk, Mark1, Anthony Gartrell2, Wayne Bailey3, Mark Brincat4
(1) Woodside Energy Ltd, Perth, WA, Australia (2) CSIRO, Bentley, Australia (3) Woodside Energy Ltd, Perth WA, Australia (4) CSIRO Petroleum, Perth, Australia
The Northern Bonaparte Basin has proved to be a challenging region for exploration offering considerable promise but yielding more modest success. Despite more than two decades of exploration drilling and significant attention by the research community there continues to be contentious debate regarding the charge history and likely controls on hydrocarbon retention during subsequent periods of intense Neogene fault reactivation. Disparities between the predictions derived from basin models and the nature of hydrocarbon fill have led to contrasting charge models that often ignore hard observational data. Similarly, the number of theories put forward to describe the controls on hydrocarbon retention is varied, ranging from fault facilitated leakage controlled by either stress or strain related processes to fault independent controls related to regional water-washing effects. Despite this sustained effort there remains no widely held agreement or demonstrable validation for any of these proposed mechanisms that hold true for the region as a whole. This review seeks to highlight the limitations associated with previous models and to proffer a new unified model that more effectively honours the hard observational data. Key elements of this evaluation include a comprehensive examination of the charge history of drilled traps to provide validation of existing structural models proposed for the Northern Australian Margin and a more holistic approach to integrating the key datasets. The result is a coherent interpretation of the critical observations that produces a plausible exploration model that can be used to more effectively risk the remaining drilling opportunities in this prospective basin.
Ordovician Sedimentation in the Shackleton Range: Post-Orogenic Basin Development in the EastAntarctic Sector of Gondwana
Lomas, Simon A.1
(1) Baker Hughes, Houston, TX
The Blaiklock Glacier Group (BGG) is a relatively undeformed sedimentary succession overlying “Pan-African” age (c. 500 Ma) metamorphic basement in the Shackleton Range, the East Antarctic sector of the early Paleozoic margin of Gondwana. New stratigraphic and sedimentological data presented here enable the reconstruction of depositional environments, evaluation of basin models, and clarification of possible regional correlations.
The BGG is a texturally and compositionally immature siliciclastic succession (“recycled orogen” type provenance), >4 km thick, directly overlying amphibolite facies metamorphic rocks with high-relief (‘landscape’) unconformity. A range of terrestrial and near-shore paleoenvironments is represented, dominated by alluvial fan to braided stream and coastal plain to tidal clastic systems. Depocenters were small, with complex sediment dispersal patterns, but overall vertical trends show upward cleaning, upward fining and inferred upward deepening. Rare rhyolite clasts provide indirect indication of silicic volcanism.
The BGG is a classic ‘molasse’ succession, derived from denudation of a collision mountain belt, and corresponds to a series of remarkably similar depositional systems developed in an array of basins across a vast area of the Pan-African—Antarctic Orogen. Similarities between the BGG and lower levels of the Table Mountain Group (South Africa) and parts of the Neptune Group (Pensacola Mountains, Antarctica) are particularly striking. For the BGG, exposure limitations make determination of basin type and tectonic setting problematic, but basement-cover relationships and subsidence—filling styles are most consistent with a broad, relatively shallow, rift system associated with limited silicic volcanism. Hence we envisage basin development through core-complex style extension of orogenically thickened crust.
Is Repeatable Noise Acceptable in 4D Seismic?
Long, Andrew S.1
(1) PGS Marine Geophysical, Perth, Australia
A reasonable understanding now exists of the quantitative relationship between errors in source and receiver position and the effect of various noise sources at different depths upon repeatability. It is only partially true that coherent noise repeated within reasonable thresholds will effectively cancel during data differencing of baseline and monitor surveys. It is not true that all noise types are acceptable for 4D – even if they are repeatable. Noise that can be accurately modelled from the recorded seismic data can be removed for the stand-alone analysis and interpretation of baseline or monitor surveys, and can be accurately removed during the differencing step. In contrast, noise that cannot be accurately modelled from the recorded seismic data is not acceptable for either stand-alone or differencing purposes – even if it is repeatable. Case examples from the North Sea and Australasia demonstrate how a detailed analysis of the important noise mechanisms in a particular 4D survey location is critical during the feasibility study stages, and how such an understanding is necessary when managing the expectations of data repeatability. Accurate data regularisation and wavefield reconstruction are potentially significant processing tools that must also be factored into any consideration of noise issues when pursuing 4D seismic.
The Late Paleozoic Gondwanan Postglacial Transgressions: Mechanisms and Source Rock Potential
Lopez-Gamundi, Oscar R.1
(1) Chevron International Exploration & Production, Houston, TX
The Gondwanan icehouse period peaked between the Late Carboniferous and Early Permian waning by the early Late Permian, giving way to a period of climatic amelioration. During the postglacial transgression conditions of clastic starvation were established in the shelf, a mechanism also identified in sequences associated with the Late Ordovician - earliest Silurian glaciation - deglaciation. Landward, due to the synchronous rise in the regional water table, optimal conditions for mire formation were created.
The Andean region of southern South America bears the oldest (Middle Carboniferous) record of the Gondwanan glaciation. By the Late Carboniferous glacial conditions ceased in this region. In the rest of southern South America the glacial-postglacial transition is of early Permian age. This transition is present in the Brazilian portion of the Paraná basin, the Sauce-Grande - Colorado basin of eastern Argentina and the Malvinas (Falkland) Islands and also identified in the Karoo and Kalahari basins of South Africa, adjacent to a mid-latitudinal ice sheet (western Gondwanan ice sheet, WGIS) until the earliest Permian. Regionally-extensive coals and carbonaceous shale horizons overlie glacigenic diamictites in many sections present in Gondwana. The postglacial, organic-rich, algal-prone shales of the Iratí Formation in the Paraná basin and Whitehill Formation in the Karoo basin seem to have been deposited in shelfal areas during transgressions and sea level highstands associated with the decoupling of the WGIS and its final disintegration.
Rapid Basin Evaluation Across Large Regions as a Basis for Play Analysis
Loutit, Tom S.1, Jane Blevin1
(1) FrOG Tech Pty Ltd, Canberra, Australia
Play analysis requires a consistent geological interpretation process within and between basins. But large areas of the world are largely unexplored because of poor spatial distribution and quality of traditional exploration data. Even in mature exploration areas the geological framework may be poorly understood particularly in the older and deeper parts of a basin.
The OZ SEEBASE™ project was designed to provide the first consistent structural model for the evolution of Australia’s Phanerozoic sedimentary basins in a single GIS project. The model provides a time-space framework for the evaluation of the petroleum potential of Australia’s basins. It was based on the systematic integration, calibration and interpretation of non-seismic and seismic/well data using a range of new techniques that rely primarily on non-seismic data to improve spatial control and provide geological information in areas not covered by seismic and wells. Product layers include depth to basement images, basement-involved faults, basement geology, tectonic events and responses, sediment thickness and crustal thickness that can be used to provide insights into key play elements or risks such as trap size, distribution, type and timing, crustal heat flow, reservoir and seal quality, volcanics, salt and basin phase morphology.
The OZ SEEBASE™ project has generated a number of new play-based exploration strategies. It has provided the basis for planning new cost-effective data acquisition strategies to systematically reduce exploration risk within families of basins that have been formed by similar geodynamic processes.
The CRAP™ (Confidence, Reliability, Accuracy and Precision) layer is key to assigning risk to each play and play element.
Risking Prospects with a Direct Hydrocarbon Indicator (DHI): An Example from the Otway Basin, Australia
Lowry, David C.1, Andrew Constantine1
(1) Origin Energy Ltd, Brisbane, Australia
The traditional method of prospect risking is to use geological knowledge to assess the chance of success (COS) for the various prospect
risk elements. If the prospect also has an associated Direct Hydrocarbon Indicator (DHI), the estimated COS for source, charge and seal can be increased to some degree, depending on the reliability of the DHI.
Bayes Theorem can be used to update the initial estimates of COS to arrive at a final overall prospect COS if the presence or absence of a DHI is assessed in terms of frequency of false positives and false negatives.
The effect of Bayes Theorem on prospect risking is illustrated by a prospect with a strong amplitude anomaly in the offshore eastern Otway Basin. Initial risking resulted in a fault seal COS of 22% and an overall prospect COS of 10.7%. The history of exploration wells testing the same stratigraphic level in this area shows that examining a prospect for an amplitude anomaly as an indicator of gas will have a 20% chance of a false positive and a 31% chance of a false negative.
Using Bayes Theorem, the COS of the prospect having adequate fault seal rises from 22% to 49%. Source and charge risks are also updated so that the overall COS for the prospect rises to 27.6%
Pitfalls to consider include allowing the strength of the DHI to influence the initial risk assessment; and failing to recognise that most DHIs cannot distinguish a live gas column from a breached one.
Realizing the Potential of Decision-Making Under Uncertainty
Mackie, Steven I.1, Chris Smith1, Matthew Welsh1
(1) University of Adelaide, Adelaide, Australia
Over the past few decades there has been strong uptake, at the exploration end of the oil and gas industry stream, of probabilistic decision-making. This has not, however, been reflected at the more downstream development and production end of the oil and gas decision-making spectrum.
Improving decision-making relies on understanding the types of decisions being made in the oil and gas industry and ensuring that optimal decision processes are implemented in these real world decisions so as to maximise the chances of good outcomes.
There has been much work carried out, within cognitive psychology, in observing how people actually make decisions.
Little work, however, directly relates these findings to the specific decision-making circumstances of the upstream oil and gas industry. Nor has there been work on how the insights stemming from psychological research might be used to improve decision-making in the industry.
This paper documents the theoretical differences between exploration, development and production decision-making and marries this with observations as to how decisions in these fields are currently being made and suggests how decisions of the observed types should be made.
A primary observation is that different types of decisions require different decision-making approaches in order to achieve optimal outcomes. The implications of this conclusion are examined in relation to the question of the application of deterministic versus probabilistic tools, data and processes to a variety of oil and gas decisions including reserves calculations.
Late Triassic-Early Jurassic Non-Marine to Marginal Marine Sequence Stratigraphy and Palaeogeography of the Rankin Trend and Surrounds, Northwest Shelf, Australia
Marshall, Neil G.1, R. Kirk2, S. Lang3, R. J. Seggie4, D. B. Alsop4
(1) Woodside Energy Ltd, Perth, Australia (2) Rob Kirk Consulting, (3) Woodside Energy Ltd, (4) Woodside Energy Ltd, Australia
The Greater Rankin Trend area is unique on the Northwest Shelf in that there appears to be a continuous stratigraphic record from the Upper Triassic I unit to the top of the Lower Jurassic C unit that has been penetrated by the drill bit [upper Mungaroo Fm-North Rankin Fm].
This produces a composite stratigraphic section of over 2000 m of nonmarine–nearshore marine strata of which much of the upper 600 m has been continuously cored. A major problem in trying to reconstruct this stratigraphic section for the Dampier Sub-basin is that when the older part of the section is penetrated, the younger sequences are often truncated by a major Oxfordian unconformity termed the MU event. When the younger sequences are preserved, the older ones are not drilled.
The older Triassic sections that are deeply eroded and capped by the MU event are often difficult to place stratigraphically because of poor biostratigraphic control in the predominantly nonmarine settings. Despite these problems, the extensive drilling in the Greater Rankin Trend provides what appears to be a complete composite stratigraphic section within a confined area.
A revised sequence stratigraphic model is proposed for the region based on detailed well coverage on the Rankin Trend and a regional grid of key wells covering much of the Dampier Sub-basin. This covers events ranging from regional second – third order surfaces to fourth order or higher, reservoir specific cycles on the Rankin Trend. These surfaces are then used to slice the stratigraphy in a time related context to produce a set of semi-regional paleogeographic maps illustrating sediment source direction and potential sand distribution.
Australian Gondwanan Petroleum Systems
Marshall, Elizabeth1, Sarah Haggas1, Paul Rheinberg1
(1) IHS ENERGY, Tetbury, United Kingdom
Using the petroleum system concept of Magoon & Dow (1991), Phanerozoic Australian sedimentary sequences have been grouped into six broad petroleum supersystems termed the Larapintine, Gondwanan, Westralian, Austral, Capricorn, and Murta systems (Bradshaw, 1993). These supersystems link individual petroleum systems that share the same age and facies of source rock across basin boundaries, providing a framework to understanding the occurrence of hydrocarbons in Australia.
The Gondwanan Supersystem includes those sequences influenced by the late Carboniferous / Early Permian Gondwana glaciation and dominated by fluvio-deltaic source rocks. Whilst nowhere near as prolific as the extensive Westralian Supersystem of the North West Shelf, the late Paleozoic Gondwanan Supersystem contains hydrocarbon reserves within the Bonaparte, Perth, Cooper and Bowen basins, accounting for 7% of Australia’s recoverable hydrocarbon reserves.
This study utilises IHS’ global basin database to compare the individual petroleum systems that comprise the Australian Gondwanan Petroleum Supersystem. Whether the presence of a Gondwanan Petroleum System results in a significant hydrocarbon discovery is dependent on a variety of factors, including tectonic history and re-activation of trapping mechanisms, seal integrity and maturity of source, which are shown to vary considerably between studied basins. Placing the components of the petroleum system in a basin-history context enables processes to be analysed and a systematic comparison of mature Australian basins to be made. Hence potential can be assessed at the play and prospect scale in frontier areas e.g. the Houtman and Abrolhos sub-basins (Perth Basin) and the Petrel Sub-basin and Londonderry High (Bonaparte Basin).
Sequence Stratigraphy of the Tithonian Marine Sediments within the Laterally Confined Rift Settings of the Dampier Sub-Basin, Northwest Shelf, Australia
Marshall, Neil G.1, M. Partington2, G. DiToro2, P. Robinson3
(1) Woodside Energy Ltd, Perth, Australia (2) Woodside Energy Ltd, (3) Isis Petroleum Consultants Pty Ltd,
Tithonian marine sediments of the Angel Formation in the Dampier Sub-basin have an extensive aerial distribution and have been penetrated by many exploration and development wells. The Angel system has excellent high resolution biostratigraphic control that enables time constrained correlations of sequences from proximal sand rich environments to distal sand poor settings. The younger part of the sequence associated with hydrocarbon bearing reservoirs has been cored extensively and this provides detailed information on the field scale stratigraphies and prevailing depositional processes. Despite these extensive datasets, the depositional settings and, more importantly, the architecture of the main reservoirs at a regional scale are poorly understood. Interpretations range from shelfal sequences through to either mass [gravity] flows deposited on a tectionically controlled ramp or basin floor. The source direction of the sands in particular are conjectural and the subject of great debate. A variety of mechanisms are postulated ranging from discrete feeder conduits and transfer fans sourced from the tip points of fault relay zones on the western and eastern flanks, through to axial sourcing from the north.
This paper focuses on constructing a depositional model from the sedimentary structures and ichnofossils derived from the core, integrated with the high resolution biostratigraphic data and well log stacking patterns. A sequence stratigraphic model for the sub-basin is proposed that includes a hierarchy of surfaces from regional tectono-eustatic 2nd - 3rd order events through to 4th order and higher cycles Examples of gross depositional environment maps ranging from semi-regional to field scale are used to highlight some of the proposed sediment source directions and depositional architecture.
Ice-sheet Dynamics of the Late Palaeozoic Glaciation in WA and Oman; Constraining Palaeogeographic and Sedimentological Models with Provenance Analysis
Martin, Joe R.1, Jonathan Redfern1, Brian P. J. Williams2
(1) University of Manchester, Manchester, United Kingdom (2) University of Aberdeen, Aberdeen, United Kingdom
Sediments deposited during the Late Palaeozoic in Western Australia and Oman provide a record of the glaciation of Gondwana. They are important hydrocarbon exploration targets, containing over 3.5 billion barrels of oil in place in Oman. Discoveries have also been made in glacial facies in the Canning Basin, although as yet not economically significant. Glacial environments are characterised by high erosion rates and complex sedimentation patterns, making prospects with glacial reservoirs challenging exploration targets and often difficult to develop effectively.
Previously, work in both areas has documented the local sedimentology and depositional history, yet the regional setting and basin-fill evolution is still poorly constrained. There are a number of conflicting models for glaciation in both areas, based solely on field observations that, taken alone, provide insufficient evidence for interpreting the evolution of ice-sheet dynamics. This study investigates the provenance of both successions aiming to provide a better regional framework to refine current sedimentological and depositional models. An integrated approach has been adopted, examining field (e.g. subglacial striation and palaeocurrent information), petrographic (conventional heavy mineral analysis) and isotopic (U-Pb and Lu-Hf LA-ICPMS analysis of detrital zircons) data to determine Late Palaeozoic ice-sheet dynamics and the involvement of neighbouring cratonic blocks as source terranes. Results provide a valuable constraint on the palaeogeography and allow the development of better depositional models.
Unlocking the Potential of the Grant Group (Canning Basin, WA), Part of the Gondwanan Glaciogenic Hydrocarbon Province
Martin, Joe R.1, Jonathan Redfern1, Brian P. J. Williams2
(1) University of Manchester, Manchester, United Kingdom (2) University of Aberdeen, Aberdeen, United Kingdom
The Grant Group of the Canning Basin, despite numerous exploration campaigns over many decades, has failed to deliver significant hydrocarbons, with only limited production to date from the Lennard Shelf area. Although a complex suite of sediments, the Grant Group has excellent reservoir properties and oil and gas discoveries, although small, attest to an active petroleum system. Several key risks, notably presence of seal, hydrocarbon charge, timing of migration, and reservoir distribution and quality, have contributed to a largely unsuccessful exploration history. Exploration often suffers from permit specific studies that neglect the regional perspective, and the Canning Basin is no exception. Outstanding regional questions include Grant Group nomenclature, age, sedimentology and depositional setting.
This study has adopted an integrated approach in an attempt to address the regional scale evolution of the Grant Group. Detailed core logging from the extensive subsurface database, integrated with outcrop descriptions, provides the basis to understanding the Grant Group’s depositional setting. Reinterpretation of 2D seismic provides an insight into the controls on deposition, whether primarily by climatic (glacial) or tectonic processes, and also allows interpretation of the large scale depositional architecture. Provenance techniques (heavy mineral petrography and LA-ICPMS U-Pb and Lu-Hf isotopic analysis of detrital zircons) in conjunction with field data (e.g. palaeocurrent and subglacial striation measurements) have been utilised to determine source terranes and sediment transportation routes. To provide the regional perspective for future hydrocarbon exploration in the Canning Basin, comparison is made with prolific coeval reservoir analogues from the Al Khlata Formation (Oman).
Distribution and Hydrocarbon Prospectivity of Gondwana Basin in India
Mathuria, TARUN KUMAR1
(1) ONGC , NAZIRA ASSAM, nazira, India
ABSRACT: Hydrocarbon occurrence and commercial production from worldwide Gondwana basins have emboldened its exploration in geologically analogous sedimentary basin of India in order to probe their hydrocarbon prospectivity. Preliminary exploration efforts carried out in these basins viz. South Rewa, Satpura and Jharia basins have yielded valuable exploration leads for pursuing the yet to find hydrocarbon resources.
The Gondwana distribution in India falls in three categories.1) the E-W Narmada,Satpura,South Rewa and Damodar valley, the NW-SE trending Son—Mahanadi and Pranita Godavari basin. 2) Extra- Peninsular area of Purea –Malda and partly Upper Assam. 3)East Coast basins of Cauvery ,Palar , Krishna Godavari and Bengal basin. Triggered by discoveries in the North Sea, China and Australia, the Gondwana basin received continued attention for hydrocarbon exploration. Huge Natural gas occurrences are envisaged in Gondwana basin. In this context detailed evaluation of major coal bearing strata of these basins have attained priority and emerged as potential source rock for hydrocarbon generation and act as a prime exploration target in view of their closed proximity with global basins. Occurrence of oil and gas in analogous basins in the world has further strengthened the possibility of existence of rich petroleum systems in similar stratigraphic arena within the Indian Gondwana basins. In addition, the contributions of coal as major source for coal bed methane exploration / exploitation is also an aided feather in cap to widen the scope of exploration.
Continental Gondwana Reunited
(1) Terrella Consultants, Perth, Australia
Global tectonic reconstructions of the entire 4,600 million years of our Earths’ geological history are presented. In these reconstructions modern geological, geophysical, and geographical evidence demonstrates that the formation and break-up of each of the continents, as well as a sympathetic opening of the oceans is simple, progressive and evolutionary. The ancient magnetic poles and equators are precisely located and are shown to coincide with observed climate zones and biotic evidence. Similarly, faunal and floral species evolution is shown to be intimately related to this progressive continental break-up and oceanic crustal development. Global extinction events coincide with wholesale climate and sea-level changes, and the distribution of metallic ores and petroleum occurrences are readily comprehended. Geographical and biogeographical data quantify the location of all palaeopoles and palaeoequators determined from unconstrained palaeomagnetic data.
The distribution of latitude dependent lithofacies, including glacials, carbonates, and coal, as well as faunal and floral species, is shown to coincide precisely with the established palaeopoles and palaeoequators. Published coastal geography shows that large, inferred, Panthallassa, Tethys and Iapetus Oceans are not required during reconstruction.
Instead, these oceans are replaced by
epi-continental Panthallassa, Iapetus, and Tethys Seas, which represent precursors to the modern Pacific and Atlantic Oceans and present Eurasian continent. Emergent land surfaces during the Precambrian and Phanerozoic equate precisely with the conventional Rodinian, Gondwanan, and Pangaean supercontinents and smaller sub-continents, and demonstrate an evolving continental development throughout Earth history. Supercontinent configuration is then defined by progressive crustal extension within epi-continental sedimentary basins and rift zones, by pulsed orogenesis, eustatic and transgressive-regressive changes to sea levels, and continental break-up and opening of the modern oceans during the Mesozoic to Recent.
Rigorous Approach to Geological Analysis of Petroleum Potential in Frontier Basins: Dealing with Risk in Regions of Great Uncertainty
McCabe, Peter J.1, Donald L. Gautier2 (1) U.S. Geological Survey, Denver, CO (2) U. S. Geological Survey, Menlo Park, CA
Despite conventional wisdom, there are many sedimentary basins in the world where there has been little or no petroleum exploration. Geologically-based assessment of such basins requires risking the probability of viable petroleum systems and identifying appropriate analogs for the size and number of undiscovered accumulations. In order to do this in a rigorous, transparent manner, a ‘basin evolution chart’ has been constructed, in which a variety of basin characteristics (tectonic setting, structural style, paleolatitude, etc.) are interpreted through time. The resulting geological interpretation is then confronted with analog suites of subsidence, heat flow, and rates of clastic input from well known basins. The chart forces integration of diverse data and provides a cross-check that ensures compatibility of information from various sources. In addition, the basin evolution chart provides a consistent framework for determining the critical elements of possible petroleum systems and for directly generating quantitative input data for basin modeling programs. The basin evolution chart has been applied to analysis of the Upper Jurassic Total Petroleum System of Danmarkshavn Basin, offshore Northeast Greenland, an area of extreme uncertainty and great upside potential. The exacting approach maximizes understanding of petroleum potential from limited data.
Residual Oil Analysis Reveals Complex Filling History of Multi-Reservoir Fields in the Southwestern Cooper Basin, South Australia
McKirdy, D.M.1, K.R. Arouri2, L. Schwark3, P.J. Boult4
(1) University of Adelaide, Adelaide SA, Australia (2) Saudi Aramco, Dhahran, Saudi Arabia (3) University of Cologne, 50674 Cologne, Germany (4) PIRSA, Adelaide SA, Australia
We have analysed a suite of produced and residual oils from stacked Cambrian, Carboniferous, Permian and Jurassic reservoirs in eight fields along the southwestern flank of the Cooper Basin. Here hydrocarbons expelled from Permian coal measures in adjacent troughs can migrate up section past the erosional edge of the Triassic seal and into Jurassic and Cretaceous non-marine sandstones of the overlying Eromanga Basin. In addition, several fields appear to have received charges from marine Cambrian source beds in the underlying Warburton Basin. Residual oils were recovered sequentially from the intact pore system of sandstone core plugs by high-pressure solvent flow-through extraction (SFTE). This analytical approach is based on the ‘first in, last out principle’ which assumes that the last oil to enter the reservoir (free oil) is the first to be extracted, whereas the initial charge (adsorbed oil) is recovered last. Molecular distributions of saturated and aromatic hydrocarbons in the residual oil fractions (n = 2-4) recovered from each core plug were compared with those of DST oils from the host and adjacent reservoirs. Differences in maturity (0.6-1.1% equivalent vitrinite reflectance) and source affinity (30-100% Permian) help constrain the charge histories of the fields in question. The same oscillating balance between Jurassic and Permian charge previously reported for Cretaceous reservoirs along the Murteree Ridge, 50-75 km to the southeast of the study area, is evident in Jurassic reservoirs of the Muteroo, Spencer and Taloola fields.
Multiple Provenances: The Role of the Hinterland Sediment Composition on Predicting Reservoir Quality – an Example from the Western Lake Eyre Basin, Central Australia
Menacherry, Saju1, Tobias H. D. Payenberg1, Simon. C Lang1
(1) University of Adelaide, Adelaide, Australia
Reservoir quality depends on sand composition, itself a function of hinterland processes: provenance, tectonic setting, sand evolution and transportation, climate, and the depositional environment. Knowing the percentage of mineral composition such as quartz, feldspar and lithics in the subsurface, one may be able to predict porosity and permeability of reservoir units as they undergoes diagenesis.
Sediments in the modern dryland Umbum Creek, western Lake Eyre Basin, Central Australia reflects the nature of the source region.
Six petrographic provenances were identified and established in the Umbum Creek drainage basin, according to the six principal geological units drained: (1) the Palaeoproterozoic-Peake and Denison inliers; (2) the Neoproterozoic; (3) the Palaeozoic Arckaringa basin; (4) the Mesozoic Eromanga basin; (5) the Tertiary Formations; and (6) the Quarternary Formations.
Source to sink samples from the Umbum Creek catchment were used to assess the provenance through time as well as finger printed each grain to its provenance lithotype. Climate has a strong influence on the petrogenesis of the Umbum Creek drainage basin sand, but mixing with tributaries is the main process that modifies composition of the Umbum Creek sand.
The modern sand is not only directly proportional to the hinterland bedrock lithology, but also cannibalizes all outcropping bedrock along the transport path. This leads to an ultimate sand composition that is not only the result of the hinterland processes but also of the entire drainage basin. Therefore, the whole drainage basin configuration needs to be considered when attempting to predict sediment composition in the subsurface.
Source Rock Studies of the Pedirka Basin, Australia
Middleton, Mike F.1, Charles E. Barker2, John Heugh3
(1) Murdoch University, N/A, Australia (2) U.S. Geological Survey, Denver, CO (3) Central Petroleum, N/A,
The Pedirka Basin is an under-explored Permian-aged basin, located in central Australia.
After deposition of the Permian succession, the basin was covered by a thickness of between one to two kilometers of Mesozoic sediments of the Eromanga Basin. During its burial history, the basin has undergone several periods of relatively intense tectonic deformation along specific structural trends. Petroleum is known to occur in the basin from shows, and subsequent analyses, in many of the 14 exploration wells drilled in the basin from 1965 to 1990.
The source-rock analysis of 24 samples obtained from exploration wells are consistent with a previous source-rock maceral study, and support the strong possibility of a good liquid hydrocarbon generative potential. This study shows the HI-OI and S1+S2 plots of the data are supportive of a higher than normal (for central Australia) type I kerogen content in the basin’s Permian and Triassic source rocks.
Vitrinite reflectance data for the basin indicates that the deepest drilled sediments to date have a maturity in the middle of the Oil Window (0.85-0.90% maximum vitrinite reflectance). Burial history modeling of potential new well locations support maturity levels in this order. Calculations of possible volumes of hydrocarbons that could be generated indicate that volumes of the order of 108 m3
(c. 600 MMbbls)of oil equivalent could potentially be generated in the deepest trough of the basin, which is the Madigan Trough.
It is concluded that a good petroleum discovery potential remains within the deeper parts of the basin.
Glacial Play Types in the Pedirka Basin, Australia
Middleton, Mike F.1, John Heugh2
(1) Murdoch University, N/A, Australia (2) Central Petroleum, N/A,
The Pedirka Basin is an under-explored Permian-aged basin, located in central Australia.
The Permian succession is covered by a thickness of over a kilometer of Mesozoic sediments of the Eromanga Basin. It is understood that the Amadeus Basin, which is immediately to the west of the Pedirka Basin, underwent up to 2 km of uplift during the Carboniferous, and probably sourced sedimentation into the Pedirka Basin. Further, it is proposed from a number of lines of evidence, including paleomagnetics, that an ice sheet covered much of central Australia, during the Early Permian. These considerations are the basis of our premise for the existence of glacial sedimentary features that may form petroleum traps in the basal Permian sequence of the Pedirka Basin.
Features with strong characteristics of complex braided stream systems, glacial moraines and drumlin system are proposed, based on the seismic interpretation of data from the western part of the Pedirka Basin.
Giving consideration to the known sedimentary deposits, within the western part of the Pedirka Basin, it is not unreasonable to propose a glacial moraine or mound play-type.
Such features are clearly mappable on the seismic data. This play-type model for the basal Permian sequence entails linear mounds (up to 10 m in height and several kilometers long) of mixed and largely unsorted sediments, which have been gradually buried (encased) in a dominantly lacustrine and swamp environment. The lacustrine environment can provide source. and the shale encased mounds can provide the reservoir. Such a play will be drilled in 2006.
From Play to Prospect: Petrobras Exploratory Effort in a Huge and Complex Gondwanan Province, the Paraná Basin of Southern Brazil
Milani, E.J.1, A. B. França1 (1) Petrobras, Rio de Janeiro, Brazil
The Paraná basin is a vast geological domain in South America, with an area of about 1,600,000 sq km, mostly in Brazil but also encompassing parts of neighbor countries. It holds an up to 7,000 m-thick package of intermixed sedimentary-magmatic rocks included in six major sequences, ranging in age from Late Ordovician to Late Cretaceous.
The basin has been intermittently explored for oil and gas since the last decade of XIX century. From 1986 to 1996, a comprehensive review and integration of the available data led to a better understanding of petroleum habitat in that province. Due to a pervasive magmatic event during the Early Cretaceous, the Paraná basin is characterized by a non-conventional petroleum system where source rocks maturation is fully dependent on the heat of the igneous bodies.
The play concept was applied to selecting the most promising areas for exploration, regarding the occurrence and interplay between source beds, reservoir rocks and seals. By the same time regional seismic structural mapping, field observation and geochemical modeling revealed the styles of deformation and the timing of petroleum generation and expulsion, thus providing the geological framework that drove exploration towards the first gas discovery in the basin.
Structural Style of the Lower Cretaceous in the Woolsthorpe-Cobden Region, Western Victoria, Australia, and Its Implications for Hydrocarbon Exploration in the Central Onshore Otway Basin
Minarwan, -1, Michael Hall1
(1) Monash University, Clayton, Australia
Seismic and well data from the Woolsthorpe-Cobden region of the Central Onshore Otway Basin in Western Victoria, Australia, have been used to document the style and geometry of Early Cretaceous structures. Half grabens bounded by large Tithonian-Barremian extensional faults developed within Palaeozoic Basement and were filled with syn-rift fluvio-lacustrine sediments of Crayfish Supersequence. A Barremian unconformity, which is one of the regionally recognised seismic horizons, bounds the top of the Crayfish Supersequence and underlies Aptian-Albian fluvio-lacustrine sediments of the Eumeralla Supersequence. The unconformity is clearly angular in the west and centre of the area but becomes less obvious in the east. Faulting activity decreased significantly in the Aptian-Albian allowing basinwide deposition of the Eumeralla Supersequence over the Crayfish half grabens. New extensional faults formed during the Late Cretaceous cut a major unconformity above Eumeralla Supersequence and syn-Upper Cretaceous sediments. Subsurface mapping shows that trapping mechanism will be one of the major risks for hydrocarbon exploration because no significant closures have been recognised at Lower Cretaceous level. Tilted fault blocks structures are capped by only thin Crayfish sediments. For future exploration strategy of Lower Cretaceous targets, we suggest possible stratigraphic traps, such as sandstone pinch-outs, may be more prospective.
New Biostratigraphic and Seismic Correlations for the Vlaming Sub-basin, Offshore Perth Basin, Western Australia
Monteil, Eric DFA1, Andrew A. Krassay1, Irina Borissova1, Chris Nicholson1, Mike MacPhail2, Chris J. Boreham1
(1) Geoscience Australia, Canberra ACT, Australia (2) Consultant Palynological Services, Aranda ACT, Australia
The Vlaming Sub-basin, which forms part of the Perth Basin on the south-western margin of Australia, is under-explored. However, with a petroleum system demonstrated by oil recovered at Gage Roads 1 and gas at Marri 1, and oil shows at Araucaria 1 and Gage Roads 2, the Vlaming Sub-basin may have significant petroleum potential. Key exploration risks in the Vlaming Sub-basin result from poor seismic data quality and the vintage and inconsistency of biostratigraphy, and hampers well correlations and prediction and mapping of seals and reservoirs.
To address these issues, Geoscience Australia has acquired, re-processed, and analysed 2,300 line kilometres of 2D seismic data and reviewed comprehensively existing biostratigraphic data. In addition, over 200 samples from cores and cuttings, from 11 wells have been analysed for palynology and organic geochemistry. Results of sampling addressed potential source rocks of the Middle to Late Jurassic Yarragadee Formation, and biostratigraphy of reservoir and seal intervals of the Late Jurassic to Early Cretaceous Parmelia and Warnbro Groups. The new study also considered the younger Cretaceous post break-up section that includes a significant unconformity, encompassing five dinoflagellate cyst zones and spans the earliest Cenomanian and Early Campanian.
New key markers and bioevent identification has resulted in more detailed and confident biostratigraphic correlations, and improved well-seismic ties through the sub-basin and across the Perth Basin. This work allows correlation with the well-established local North West Shelf biozonation and provides supplementary biostratigraphic tie points with the international Standard Stages.
Geologic Modelling of the Gorgon Gas Field using a Multi-Point Statistics and Facies Distribution Models: Investigating the Impact of Seismically Unresolvable Sandy Bodies
Montgomery, P.1, N. Miller1, A. C. Villella1, R. Root1, T. Munckton1, M. Whelan1, J. Roche1
(1) Chevron Australia Pty Ltd, Perth, Australia
The Gorgon gas field is owned by a joint venture operated by Chevron (50%), in partnership with Shell (25%) and ExxonMobil (25%).
A sequence stratigraphic model has been used to divide the reservoir into a series of 12 zones and a detailed seismic interpretation of the zone boundaries and individual channels and channel belts has been completed. However, well penetrations indicate the presence of sand bodies that are beyond the resolution capabilities of seismic data.
The two main geologic modelling challenges face the Gorgon Asset Team: 1) What are reasonable Net-to-Gross (NTG) values outside the main mapped low-stand channel systems (off-fairway) and high-stand sequences? 2) How connected are seismically un-mappable off-fairway and high-standard sand bodies likely to be? To address these questions multiple Gorgon Zone 50 geologic models, based on a Boolean approach and constrained by soft seismic data, and an alternative approach based on deterministic sand mapping, Multi-Point-Statistics and Facies Distribution Models in conjunction with analogue data, have been built to investigate the impact of uncertainty in the off-fairway reservoir component on the Gorgon development.
Model grids that incorporate structural and thickness uncertainty of the main seismically interpretable fluvial sand belts have been generated. Stochastic modelling of off-fairway bodies has being carried out using appropriate binary facies and depositional models that depend on the zone’s position within the Gorgon sequence stratigraphic framework. Results of these studies indicate high levels of connectivity in off-fairway and high-stand sand bodies.
Late Triassic Pre-Rift Stratigraphy of the Gorgon Gas Field: Establishing Appropriate Depositional Analogues as Constraints for Geologic Modelling
Montgomery, P.1, N. Miller1, A.C. Villella1, R. Root1, J. Roche1, T. Munckton1
(1) Chevron Australia Pty Ltd, Perth, Australia
Gorgon is a giant gas field owned by a joint venture operated by Chevron (50%), in partnership with Shell (25%) and ExxonMobil (25%). Gorgon will be a subsea development in 200-300m of water which, in conjunction with the neighbouring Jansz gas field, will feed a two train LNG facility 70km distant on Barrow Island.
Gorgon was discovered in 1980 with the Gorgon-1 well, which encountered a 500m gross gas column in Triassic sandstones.
The reservoir comprises a thick stack of Triassic fluvial channel units varying from high net-to-gross intervals containing coalescing channel belts to lower net-to-gross intervals with more isolated channels. The reservoir has been penetrated by eight wells and over 500m of core has been recovered. A sequence stratigraphic model has been used to subdivide the reservoir into twelve zones within an overall transgressive sequence. Each zone is a division within a series of sequences comprised of a basal erosion surface overlain by amalgamated fluvial sheets followed by a heterolithic interval containing isolated fluvial sand and terminated by an erosion surface. Each sequence can be interpreted as a fluvial system’s response to a base-level fall and erosion, followed by increasing then decreasing rates of base-level rise, eventually terminating in base-level fall and erosion surface. A high resolution base-level curve for the Gorgon field based on gamma-ray logs from the eight Gorgon delineation wells has been proposed and used to determine the appropriate depositional analogues employed during Gorgon field geologic modelling.
Constraining Eustatic Sealevel Variations and Palaeoclimate through Reconstructions of Palaeobathymetry and Continental Topography
Muller, Dietmar1, Maria Sdrolias2, John You2
(1) Sydney University, Sydney, Australia (2) The University of Sydney, Sydney, Australia
We use a combined relative and absolute plate motion model, based on a moving hotspot reference frame, with a global data set of plate tectonic data to reconstruct the ocean floor through time, including the main ocean basins, back-arc basins, and now subducted ocean crust. We reconstruct paleo-oceans by creating “synthetic plates”, the locations and geometry of which is established on the basis of preserved ocean crust (magnetic lineations and fracture zones), geological data, paleogeography, and the rules of plate tectonics. Based on this approach we have created a set of global oceanic palaeo-isochrons and palaeo-oceanic age grids. The paleo-age grids illustrate where subduction zones were located, and provide the age of subducting oceanic lithosphere as well as convergence rates and directions along active margins through time, providing constraints for geodynamic models. The grids also provide the first complete global set of paleo-bathymetry maps, including estimates of paleo-sediment thickness as a function of latitude and plate age, and now subducted ocean floor, for the last 130 million years. We show that the mid-Cretaceous sealevel highstand was primarily caused by two main factors: (1) the “supercontinent breakup effect”, which resulted in the creation of the mid-Atlantic and Indian Ocean ridges at the expense of subducting old ocean floor in the Tethys and (2) by a changing age-area distribution of Pacific ocean floor through time, resulting from the subduction of the Pacific-Izanagi, Pacific-Phoenix and Pacific-Farallon ridges. We have merged our paleo-bathymetry with reconstructed paleo-topography for key times in the Cenozoic and used these data as improved input for NCAR’s CCM3 (Community Climate System Model) models for more realistic simulation of both surface and deep water circulation.
In Situ Stress Determination and Related Wellbore Features from Image Logs of the Carnarvon Basin, North West Shelf
Neubauer, Marie1, Richard Hillis1, Scott Reynolds1
(1) The University of Adelaide, Adelaide, SA, Australia
Knowledge of the in situ stress field is vital to the petroleum industry for assessing trap integrity and maximising wellbore stability and recovery rates. The Carnarvon Basin Stress Map Project (CBSMP) aims to determine the regional in situ stress tensor of the offshore Carnarvon Basin as well as identify any local stress perturbations. Stress-related wellbore features such as borehole breakout and drilling-induced tensile fractures observed from image log data were used to define the in situ stress orientation. Previous work done in the Carnarvon Basin using poorer quality caliper data implied scattered maximum horizontal stress orientations with a mean orientation of approximately east-west. A total of 60 high resolution image logs have been interpreted to obtain stress and structural information for the CBSMP. A regional maximum horizontal stress orientation of approximately 105°N was determined with the stress orientation being relatively consistent across the basin. However, some regions show some local stress perturbations where the maximum horizontal stress orientation rotates parallel to the structural grain in the region. Stress magnitudes derived from density logs and leak off test data yield a stress regime on the border of strike-slip and normal. The CBSMP has improved the density and quality of in situ stress data throughout the region. This poster illustrates the maximum horizontal stress orientation of the Carnarvon Basin and its variation over the basin.
This poster will also illustrate structurally-related, stress-related and geological features on image logs from the area.
The 2004 Sumatra Earthquake and Tsunami: Understanding a Unique Geohazard
Norton, Ian O.1, Leonard P. McDonnell2
(1) ExxonMobil Upstream Research Company, Houston, TX (2) The Edge Media Pty Ltd, Kyneton, Australia
The destructive Indian Ocean tsunamis of December 26, 2004 were produced by a huge magnitude 9.3 earthquake offshore northern Sumatra. This megathrust earthquake was located in the collision zone where Indian oceanic crust is subducting beneath Asia. Several aspects of this earthquake make it unique. The magnitude, 9.3, was the largest recorded since 1964 and in terms of seismic energy release represents almost ten years worth of normal global seismicity. It generated destructive tsunamis that appear to be unique in recorded history of countries bordering the Indian Ocean. In addition, examination of the tectonic setting of this earthquake suggests that it was in a unique tectonic position. Initial rupture was close to the northern end of Simeulue Island. From here, rupture propagated rapidly northward, ultimately traveling nearly 1500 km to the plate boundary offshore Myanmar. This represents rupture of almost the entire boundary of a small plate, the Burma plate, that is accommodating some of the rapid plate motion between India and Asia. Aftershocks of the main event show faulting within Asia, in the Burma plate and also within the subducting India plate. Some seismicity indicates that the boundary between the Indian and Australian plates may run through this area as well.
This would mean that the epicenter is at a very unusual location, at the junction between four plates. This location may have implications for recurrence time of such an event.
In addition to its unique tectonic character, this earthquake revealed faults in how scientific knowledge is communicated to the general public. Although seismic risk was well-known locally, contributing to the low casualty rate on, for example, Simeulue Island, tsunami risk was underappreciated in other locations such as mainland Thailand. This event presents a challenge for the future in how we disseminate complex information.
Permian to Cretaceous Palaeogeographic Evolution and Petroleum Systems of the Northern Margins of the Australian Plate
Norvick, Martin S.1
(1) University of Melbourne, Melbourne, Vic, Australia
In northern Australia, the southern margin of Tethys evolved by successive shedding of microcontinents, which subsequently drifted and accreted to SE Asia. Uplift of central Australia in the Middle Carboniferous was followed by initiation of the Westralian Superbasin during Late Carboniferous-earliest Permian extension. The Sibumasu microcontinent then broke away in the Sakmarian. Simultaneously, the Greater Bird’s Head rotated clockwise, opening the proto-Banda Sea. A Middle Triassic magmatic arc formed along northeastern Australia from NSW to the Greater Bird’s Head. Large deltas formed on northwestern Australian margins from the Middle Triassic to Middle Jurassic. Outboard of these deltas, carbonate build-ups developed from the Wombat Plateau to PNG, while deepwater marls accumulated between them. Argoland/West Burma broke up in the Oxfordian after widespread basaltic magmatism. Breakup was followed by a long period of localised extension in northwestern Australia, forming discontinuous grabens from the Exmouth Subbasin to the Aru Trough. The Berriasian Barrow and Toro deltas were followed by Valanginian breakup between Greater India and Australia. The northwestern graben system was then abandoned and the whole plate margin subsided into deep water until after the Aptian. Prolific petroleum source systems include wet gas-prone deltaic source rocks in the Upper Triassic-Lower Jurassic (North West Shelf) and Upper Permian (Bird’s Head, Bonaparte), and oil-prone source rocks in the Upper Jurassic marine rifts (Carnarvon, Bonaparte, PNG). However, another source system occurs in Upper Triassic marine carbonates, responsible for high-sulphur oils in Seram, which may be represented in other areas of the former outer continental margin.
The Donkey Bore Syncline, South Australia – an Outcrop Analogue of a Deepwater Sediment-Filled Salt-Withdraw Mini-Basin
Payenberg, Tobias H.D.1, Simon C. Lang1, Mark, R.W. Reilly1, Blaise Fernandes1, Carmen Krapf1, Nathan Ceglar1
(1) University of Adelaide, Adelaide, Australia
Mini-basins filled with deepwater sediments are significant exploration targets around the world. Reservoir and seal facies distribution within such mini-basins are highly variable and often difficult to predict. As a result, many development programs face a higher degree of compartmentalization than originally anticipated, which often leads to higher development costs, and lowered reserves. Outcrop analogues are one way of gaining a better generic understanding of compartmentalization commonly encountered within sedimentary successions.
The Cambrian Donkey Bore Syncline, Flinders Ranges, South Australia is an outcropping analogue of a complete mini-basin fill. Next to the Wirrealpa Diapir over 400m of section are exposed in a doubly-folded syncline.
The gently-dipping sediments within the syncline cover an area of approximately
20 km2. The mini-basin fill comprises basal shallow marine, cross-stratified carbonates including Archaeocyatha reef complexes. Towards the top of this limestone slumping occurs frequently, and reef complexes are found as allochthonous blocks. This mass wasting shows the re-initiation of the mini-basin.
Overlying the carbonates are massive densite and debrite beds separated by mudstone. These rocks form the initial clastic fill of the basin. Up section the densites and debrites decrease in thickness and frequency, and turbidite beds start occurring. This is interpreted as the result of a decreasing slope through filling of the mini-basin. The overall transgressive deepwater succession ends with thin turbidite and thick mudstone packages overlain by chloritic siltstones. Sandbody continuity within the basin is mainly dependent on the type of flow mechanism and the input location relative to the diapir.
Strike Variability and Cyclicity of Upper Devonian (Famennian) Foreslopes, Canning Basin, Northwest Australia
Playton, Ted E.1, Charles Kerans2
(1) The Univeristy of Texas at Austin, Austin, TX (2) The University of Texas at Austin,
Carbonate foreslope systems are primarily constructed by sediment gravity flow architectural elements that have distinct angles of repose and compositions. Among these are coarse debris deposits (megabreccias) that result from gravitational collapse of early-lithified, high-angle carbonate reef margins. Strike variability and cyclic vertical successions of foreslope elements are observed from Upper Devonian (Famennian) outcrops of the Canning Basin, northwest Australia.
Thirty measured sections tied to detailed photomosaics were collected for over
5 km2 and 200 m of seismic-scale early to mid Famennian foreselope strata (374.5 to ~ 365 mybp). The outcrops highlight the strike variability associated with collapse events, such as platform margin rugosity (depositional promontories and collapse-related reentrants) and differential topography on the slope produced by mounded megabreccia complexes. Foreslope elements are arranged in correlative, predictable vertical successions, consisting of 1) reef collapse megabreccias, 2) condensed intervals indicating slope starvation, and
3) platform-derived breccias and grainstones.
Famennian foreslope outcrops in the Canning Basin emphasize the importance of recognizing the component architectural elements of carbonate slopes and appreciating their strike variability. Megabreccia deposits on the slope indicate updip margin collapse, and their occurrence within cyclic vertical successions offers constraints for collapse timing.
The strike-discontinuous products of collapse (reentrants and mounded megabreccias) provide sediment focal points that promote slope channelization, and subsequently affect slope-to-basin reservoir development.
Thus, megabreccia presence, their occurrence within vertical successions, and their strike relationships with other foreslope deposits can offer predictive capability for deep-water carbonate systems and potential channelized reservoir accumulations.
Will Stratigraphic Traps Rejuvenate an Aging Cooper Basin in Central Australia?
Plummer, Phillip S.1, Irwan Djamaludin2
(1) Santos Ltd, Adelaide, SA, Australia (2) Santos Ltd,
Will Stratigraphic Traps Rejuvenate an Aging Cooper Basin in Central Australia?
Gas was first discovered in the Cooper Basin in 1963. Over the next 30 years, drilling structural traps mapped on 2D seismic, the rate and size of gas discoveries defined a classic creaming curve. Initial discoveries were large and frequent with 5 Tcf booked in the first 14 years (Youth). Discovery rate and size then fell with only 1.5 Tcf booked during the following 6 years (Adolescence), then a mere 0.5 Tcf in 5 years (Early Maturity) before discoveries virtually dried up and the basin profile flattened for the 5 years to end 1992 (Late Maturity).
Two events then changed the impetus of gas exploration within the basin. Firstly, PASA secured all uncontracted gas reserves in southwest Queensland, thereby stimulating an aggressive new exploration phase in the border region and, secondly, 3D seismic was introduced. Although 3Ds improved coverage and quality were ideally suited to define stratigraphic traps, it was initially applied to oil exploration while gas exploration remained focussed on the hitherto successful structural play. Thus, despite the aggressive exploration effort, the basin’s gas discovery gradient achieved only a moderate upturn. Only 1 Tcf was booked over 8 years before the gradient once again flattened to where it has remained for the last 4 years.
Recent applications of AVO, seismic inversion and pattern recognition on 3D seismic are being applied, with limited success, to bring stratigraphic traps to light, but a predictive tool has yet to emerge. Principal challenges are the depth and thin nature of the reservoir sands coupled with a lack of contrast in seismic velocity/impedance between reservoir and seal facies plus the number and proximity of intervening coal beds within the swampy fluvial deposits that constitute the Cooper Basin succession.
Basement Control on Basin Evolution in Northwestern Australia
Pryer, Lynn L.1, Karen Romine2
(1) FrOGTech, Canberra, Australia (2) FrOG Tech Pty Ltd, Deakin West, Australia
The basement of any basin provides the foundation onto which the sediments are deposited. The rheology, or mechanical behaviour, of the basement controls the rate of subsidence and geometry of each phase of the evolving basin. The composition of the basement determines its strength or stiffness. The age and early history of each basement terrane dictates the intensity and character of the structural fabric. This inherent fabric plays a major role in the manner in which the crust deforms during major periods of extension or compression.
Basement Terranes of NW Australia, interpreted from gravity, magnetic and geological data, include at least 4 major Archean to Early Proterozoic cratonic blocks separated by younger mobile belts. The cratons tend to resist deformation causing extensional strain and associated accommodation space to preferentially partition into surrounding mobile belts. Thus the thickest sediment accumulation tends to develop over mobile basement. The orientation and effective length of internal mobile belt fabric controls the direction and amount of extension that can be accommodated for a particular tectonic event. For example, NE-SW directed extension during the Devonian focused in the Canning and Petrel basins with minor, if any, extension of the intervening Kimberly block. Compressional strain is also preferentially partitioned into mobile belts such that basin cores tend to be inverted. In major compression events mobile belts are exhumed with foreland sedimentation and older basin preservation localised over adjacent cratonic basement.
In this paper we present an overview of the basement terranes of Northwestern Australia from the OZ SEEBASETM project demonstrating the difference in rheological behaviour of cratonic blocks and mobile belts, and their predicted control on basin evolution through time.
Structure and Hydrocarbon Prospectivity of the Waukarlycarly Graben, West Australia
Purcell, Peter1, Clive Foss2
(1) P & R Geological Consultants Pty Ltd, Perth, Australia (2) Encom Technology, Sydney, Australia
The Waukarlycarly Graben on the southern edge of the Canning Basin in Western Australia was first recognised in 1993 on the basis of regional gravity and magnetic data, and confirmed by seismic profiles in 1995. Underlying an inlier of Pleistocene sand dunes in the Pilbara Craton and previously considered a shallow trough of Permian glacial sediment, the basin contains over 3000 m of sediments of undetermined age of either Palaeozoic or Proterozoic age. Both sequences have potential for source and reservoir development.
The three isolated seismic lines provide good strike and dip profiles of the basin and can be integrated with the gravity and magnetic data to define the basin framework. The basin was mapped initially using gravity data with
11 km station spacing and aeromagnetic surveys at 1600 metre line spacing. Gravity stations at 2.5 km spacing and aeromagnetic lines at 400 metre spacing have recently become available from Australian government surveys. The more detailed interpretation possible from these new data, integrated with the seismic data, provide better definition of this unexplored basin.
The Seismic Image of Devonian Reefs in the Canning Basin, Australia - An Historical Review
Purcell, Peter G.1
(1) P&R Geological Consultants Pty Ltd, Perth, Australia
The Devonian reefs of Australia’s Canning Basin have been a source of inspiration and frustration for petroleum explorers for nearly half a century. The analogy to major oil and gas fields in similar reef complexes, especially Alberta, has underwritten several cycles of exploration, largely unsuccessful.
The form of the reef, as envisaged in the subsurface has evolved over time, in terms of both geological model and seismic ‘image’. The geological model has been based on the world-famous outcrops along the basin margin. On seismic data, a wide variety of features have been interpreted as reef margin or atoll complexes, based on analogy to either those outcrops or to seismic features proven to be reefs in other basins. Some interpretations, such as the Blina and Needle Eye Rocks reefs, proved remarkably accurate, but many seismically defined ‘reefs’ proved unrelated to reefing and were commonly not of Devonian age. For instance, wells drilled for Devonian objectives in the Fitzroy Trough invariably encountered only Permo-Carboniferous sediments. Early efforts to interpret porosity trends in, for example, the
fore-reef zone were unsuccessful and wells invariably encountered tight platform carbonates. A large number of seismic ‘moundform’ anomalies drilled as reefs proved to be processing artefacts, erosional and glacial features, and velocity anomalies.
The potential remains unrealised.
Facies, Outcrop Gamma Ray and Isotopic Signature of Exposed Miocene Subtropical Continental Shelf Carbonates, North West Cape, Western Australia
Read, J. Frederick1, L.B. Collins2, J.W. Hogarth3, B.P. Coffey4
(1) Virginia Polytechnic Institute and State University, Blacksburg, VA (2) Curtin University of Technology, Bentley, Western Australia, Australia (3) Curtin University, Bentley, Western Australia, Australia (4) University of North Carolina, Chapel Hill, NC
Exposed, uplifted Miocene carbonate sequences of the Cape Range, North West Cape, Western Australia, provide outcrop analogues of seismic sequences from offshore parts of the shelf. Facies include deep shelf marls (very fine and fine packstone), larger foram wackestone, floatstone and muddy rudstone, foram-coralline algal skeletal fragment packstone-wackestone (shallow seagrass facies), lagoonal wackestone/mudstone with scattered corals, and tidal flat laminites. The exposed Early Miocene units include the Mandu highstand, a sequence in the Tulki and one in the Middle Miocene Trealla Limestone. Sequences contain decameter scale (5 to
20 m thick), 4th-order parasequences evident on gamma ray logs and by facies stacking, that shallow and coarsen up; they appear to be due to eccentricity driven sea-level changes which may have been up to 50 m. Higher frequency meter-scale parasequences of deep water marl up into larger foram rudstone/floatstone (perhaps obliquity/eccentricity) are evident at the base of the exposed Mandu section.
These parasequences are not merely random storm deposits. This is indicated by the covariance of C and O isotopes, with the lighter values associated with deepening and deposition of deep shelf marls, and the heavier values being associated with shallowing and deposition of larger foram facies.
The uplifted Miocene continental shelf sediments of the North West Cape preserve a record of eustasy, paleoclimate and paleoceanography and thus provide a window into factors affecting the shelf, that can be compared with coeval, better studied deep sea cores.
The Perseus Field, North West Shelf - a Sleeping Beauty Awakes
Reding, Etienne1, Steve Abernethy1, Dave Boardman1, Peter Carter1
(1) Woodside Energy Limited, N/A, Australia
The Giant Perseus field is operated by Woodside on behalf of the North West Shelf venture partners and it is the largest single gas accumulation supplying the LNG plant in Karratha, Western Australia.
The first penetration in the Perseus accumulation in 1972 was the North Rankin-4 well, but the full size and potential of the field was only recognised after the start of production of the NRA22 deviated well, drilled in 1991 from the North Rankin facility and after drilling of 6 appraisal wells in 1995-1996. Two more production wells were added in 2001, increasing production four-fold and confirming the huge potential of the Perseus reservoir. The new high quality Demeter seismic survey acquired in 2003 has resulted in a new seismic interpretation that reveals the structural and stratigraphic complexity of the fluvio-deltaic reservoir and helping to improve mapping of the drainage pattern. The interpretation was integrated into static and dynamic models, which were calibrated with historical production and pressure data. The models have highlighted the need to drill wells across all compartments to achieve an optimal and uniform drainage across the whole field.
In order to access poorly drained compartments, 6 additional wells will be drilled in 2006, 3 wells from the North Rankin platform and 3 subsea wells tied back to the Goodwyn production facility. This latest phase of development and later compression over the North Rankin B facility (NRB) will allow the Perseus Field to produce the majority of the North West Shelf Venture gas post-2007.
Canyon Formation on Clinoform Foresets of a Prograding Eocene-Miocene Carbonate Shelf, Offshore Northwest Australia
Reuning, Lars1, Peter Kukla1, Stefan Back2
(1) RWTH Aachen University, Aachen, Germany (2) RWTH Aachen, Aachen,
Seismic data from the western part of the Browse Basin, North West Shelf, Australia, reveal the internal geometry and depositional history of a progradational Eocene-Miocene carbonate shelf. The prograding slope system is superbly imaged by two adjacent, three-dimensional multichannel seismic volumes embedded in a two-dimensional multichannel seismic grid. Based on this data, the 3-D stratal architecture of prograding clinoforms can be mapped throughout an area of ~ 1000 km2. The Eocene-Miocene slope system can be divided into an Eocene clinoform succession strongly prograding towards the northwest, and an Oligocene to Late Miocene progradational to aggradational clinoform sequence.
The prograding clinoforms of the Eocene succession progressively develop highly dissected, gullied foresets. In contrast, the Oligocene to Late Miocene system is characterized by relatively smooth foresets that lack major incisions. This change in downslope erosion is accompanied by a transition in platform morphology from an unrimmed heterozoan carbonate shelf in the Eocene to a carbonate platform dominated by coral buildups in the Oligocene and Miocene. The spatial control provided by the 3-D seismic volume supports a detailed analysis of the relationship between the overall morphology of carbonate systems and the erosion mechanisms on their foresets. A better knowledge of the Tertiary succession will further help to optimize seismic velocity models for the study area.
Australia’s Southern Margin: A Significant Deepwater Exploration Frontier
Rigby, Stephen M.1, Mark L. Taylor1
(1) Woodside Energy Ltd, Perth, Australia
Australia’s southern margin basins developed during the Jurassic and Cretaceous in response to rifting and break-up between Australia and Antarctica. Rift-induced depocentres include (from west to east) the Bremer, Eyre, Ceduna and Duntroon Sub-basins of the Bight Basin and the Otway and Sorell Basins further east. Sedimentary wedges composed mainly of Tertiary cold-water carbonates form the present-day continental shelf, while present-day deep water basins have thin Tertiary sedimentary cover.
The deepwater basins of Australia’s southern margin remain sparsely explored, with only 3 wells drilled in water depths greater than 500m. Woodside-led joint ventures are actively exploring the vast deepwater frontier province of the Ceduna and Duntroon Sub-basins, where a Late Cretaceous delta system extends over more than 100,000 km2. As part of a systematic exploration program an extensive regional 2D seismic grid has been acquired and one exploration well (Gnarlyknots-1A) has been drilled. Activity has continued with the recent acquisition of 3D seismic data.
The Otway Basin has been the focus of exploration activity for many years. During the past decade several significant gas discoveries have been made in the offshore shelfal part of the basin and developments such as the Woodside-operated Thylacine gas field are now supplying gas into the eastern Australian domestic market. Exploration is now moving into deep water, where a Woodside-led joint venture has acquired a substantial 3D seismic survey and intends to drill what will be only the second deep water Otway Basin exploration well during the coming year.
Australia’s deep water southern margin is still largely unexplored and remains one of Australia’s most significant exploration frontiers in an increasingly opportunity-constrained global E&P business.
The Geology and Petroleum Potential of the Bremer Sub-Basin – A Potential Deep-water Petroleum Province on Australia’s Southwest Margin
Ryan, Damien J.1, Robin P.D. O’Leary1, Chris J. Nicholson1, Barry E. Bradshaw1, Chris J. Boreham1
(1) Geoscience Australia, Canberra, Australia
The Bremer Sub-basin is a Middle Jurassic – Late Cretaceous half-graben complex that forms the western-most depocentre of the Bight Basin. It is located across the continental slope off the southern coast of Western Australia in water depths of 100 – 4000 m. The sub-basin is a rank frontier area for petroleum exploration with no wells previously drilled. Through integrating dredge sample data with regional seismic interpretations, it has been possible to develop a structural and stratigraphic framework for the sub-basin, and assess the petroleum exploration potential using conventional basin analysis techniques. Structurally, the sub-basin comprises a series of en-echelon SW-NE trending fault-bounded half graben, and a significant intra-basin fault system that developed during rifting between Australia and Antarctica. Of particular importance to petroleum exploration are three major cycles of lacustrine and fluvial sedimentation in Late Jurassic – Early Cretaceous strata, which provide key petroleum system elements of both organic-rich source rocks to generate hydrocarbons, and sandstones overlain by thick mudstones that could potentially reservoir hydrocarbons. Exploration opportunities and play types vary across the sub-basin. A large potential source kitchen area occurs in the central part of the sub-basin, where sediments are 4 to
9.5 km thick. Here, the main exploration play is fault block traps in water depths of 1000 – >
2500 m. Smaller depocentres with up to 5 km of sediment fill occur in the western and eastern parts of the basin and host large anticlinal structures in water depths of 500 – 800 m.
Evolution of Structural Traps within the Left-lateral, Obliquely Extending Shipwreck Trough, Otway Basin, SE Australia
Schneider, Craig L.1, Kevin C. Hill1
(1) The University of Melbourne, Melbourne, Australia
The north-trending Shipwreck Trough contains the Thylacine, Geographe and Minerva gasfields. Although formed coevally, each exhibits a unique structural style reflecting the complex interplay between reactivation of basement structural fabrics, the syn-rift mechanical stratigraphy, and the obliquity of rifting. Late Jurassic-Barremian rifting formed north- and northeast-trending horst and graben parallel to basement structural fabrics.
In contrast, Cenomanian-Late Paleocene rifting created west-northwest trending normal faults including the Tartwaup-Mussel Fault Zone (TMFZ) to the southwest. Within the central portions of the trough, normal faults are largely detached from the underlying horst and graben. A striking exception is the north-northwest trending, left-lateral oblique Shipwreck Fault Zone (SFZ) which overlies the eastern margin of an Early Cretaceous graben and bounds the Shipwreck Trough to the east. The SFZ shows both positive and negative flower structure morphology. Within this oblique structural environment, the Minerva Anticline formed by Late Cretaceous inversion of the Jurassic–Barremian Minerva Graben at a right-hand kink in the SFZ.
Above the northeast-trending, Jurassic-Barremian Geographe Horst, the Geographe Anticline formed as an accommodation, or transverse fold, between faults and fault tips of the TMFZ and eastward directed folding into the Investigator Graben pull-apart basin along the SFZ to the east. Thylacine formed as a horst between the TMFZ to the southwest and the Investigator Graben to the northeast. These gas-bearing structural traps within the Shipwreck Trough all formed synchronously with reservoir and seal deposition, so each structure has a unique uplift-subsidence history and has its own local stratigraphy and complex reservoir architecture.
Enhancing Risk Management Using AS/NZS 4360:2004 Risk Management Standard
(1) SAI Global Limited, East Perth, Australia
Good outcomes in Risk Management can only happen if two key elements are present – sound interdisciplinary processes and the right information.
It is important to focus on comprehensive review processes that involve broad interdisciplinary participation and improve communication.
The use of a Risk Management process facilitates these objectives.
Risk Management is flexible in its application, and can deliver a range of benefits depending on the nature of the system and business concerned. These can include:
• Effective Risk management
• Public Confirmation
• Commitment to Shareholders
• Market Recognition
• Reduced Expenses Market Entry
• Enhanced Corporate Knowledge
• Improve Employee Commitment
This presentation is designed to assist participants in understanding the purpose of Risk Management and applying the AS/NZS 4360:2004 Risk Management Standard.
Underlying frameworks and related tools will be discussed including :
• Risk Identification,
• Risk Analysis,
• Risk Evaluation, and
• Risk treatment.
The Risk Management processes are illustrated using relevant examples.
Participants will be able to engage in integrated risk management activities in their organisation, outline the high level goals and framework of risk management, define roles and responsibilities for risk management and use effective tools of risk management.
Managing Environmental Risks through the Application of ISO 14001: Environmental Management System Standards
(1) SAI Global Limited, East Perth, Australia
While Environmental Management is applicable across all sectors of industry and Government, it is of particular importance for the petroleum industry, as the environmental risk faced could have particularly severe consequences.
ISO 14001 specifies the requirements for an Environmental Management System, providing a framework for an organisation to identify and manage the environmental impact of its activities, products and services, and to improve its environmental performance continually.
Environmental Management Systems enable organisations to improve environmental, social and economic performance, thereby contributing to global sustainability.
Businesses are provided with an opportunity to benchmark against emerging trends in regulatory, community, stakeholder and trade requirements.
The benefits of Certified Environmental Management Systems include:
• Improved environmental risk
• Enhanced public image,
• Enhanced community acceptance,
• Enhanced environmental stewardship,
• Improved sustainable decision-making,
• Lower insurance costs.
Examples as to how Environmental Management Systems enable organisations to improve performance and mitigate risks will be given.
The revised international standards on Environmental Management Systems (ISO 14001:2004) are illustrated.
This paper further discusses sustainability reporting and verification of sustainability reports.
Self-Organized Breakup of Gondwana
Sears, James W.1
(1) University of Montana, Missoula, MT
Gondwana broke apart along a geometrically-regular fracture system that minimized total crack length and therefore required the least work to nucleate and propagate fractures across the supercontinent. Fracture spacing was a function of the strength of the Gondwana lithosphere, and fracture arrangement met conditions imposed by Euler’s rule for ordering convex polyhedrons on a spherical shell.
The tensile stress field that initiated the fractures appears to have been self-organized by the pre-existing geometry of Gondwana. Tensile hoop stress followed the Gondwana periphery. Regularly-spaced radial fractures abutted the periphery at T intersections, showing that it acted as a free surface; these defined the lateral edges of Australia, India, Arabia, Libya, and northwest Africa. Approximately 1000-1500 km inward from the periphery, each of these radial fractures branched into two fractures at approximately 120 degrees.
The branches linked into a surprisingly regular polygonal network that was congruent with a truncated icosahedron and symmetrical about the center of Gondwana. The fracture system may have formed in response to uplift and stretching of Gondwana above upper mantle that was thermally expanding because it was insulated by the slow-moving supercontinent (see Anderson, 1982, Nature). The uplift and fracturing may have culminated during the Triassic sea-level lowstand. The fragments later separated diachronously as demanded by plate tectonics, leading to outbreaks of large igneous provinces along fracture intersections. Many of the fractures evolved into hydrocarbon-rich passive continental margins, others formed productive failed rifts in continental interiors. This study argues against the deep mantle plume paradigm for breakup of Gondwana.
Integrated Multidisciplinary Analysis of the Rankin Trend Gas Reserviors North West Shelf, Australia
Seggie, R. J.1, David. B Alsop2, Chris Cubitt3, Robert Kirk4, S. Lang5, Neil Marshall3, Steve Twartz1
(1) Woodside Energy Ltd, Perth, Australia (2) Woodside Energy Ltd, Perth, WA, Australia (3) Woodside Energy Ltd, Australia (4) Rob Kirk Consulting, (5) Woodside Energy Ltd,
An integrated geological study of the Rankin Trend of the North West Shelf, Australia, was completed to underpin the development of giant gas fields. The study applied an improved understanding of the regional stratigraphy in conjunction with interpretation of the regional scale Demeter 3D seismic survey, focussed on existing fields, un-developed discoveries, and exploration prospects. The study included a redescription of 1500 metres of core, a new facies based petrological analysis, a revision of the biostratigraphic framework and a seismic stratigraphic analysis. It also included the integration of reservoir production and hydrodynamic data. Improvements in the stratigraphic framework were supported by a broad range of depositional and facies analogues and a system-wide sequence stratigraphic approach to understanding lateral and vertical stacking patterns of the reservoir succession. The latest visualisation and modelling technology were also employed to more adequately describe genetic reservoir packages.
Specific outcomes include, improved correlation techniques, recognition of palaeosols as key stratigraphic marker horizons and application of appropriate subsurface depositional analogues to field descriptions, resulting in a more consistent regional interpretation framework. This forms the basis for seismic stratigraphic interpretation away from well control.
The regional geological model has enabled the linkage of exploration, development and production understanding across the North West Shelf assets as well as management of geological uncertainties.
Breakup of Eastern Gondwanaland: Genesis of Bangladesh’s Petroleum System
Shamsuddin, Abulhasant M.1, John Coleman1
(1) Chevron Internatial Exploration & Production, Unocal Bangladesh, Dhaka, Bangladesh
The geological evolution of Bangladesh is related to the breakup of eastern Gondwanaland, the associated northward movement of the Indian Plate and its ultimate collision with the Asian Plate. The movement and interaction of these plates has defined the pattern of basin formation, structure, and the development of petroleum systems within Bangladesh.
The palaeogeographic reconstructions of the region suggest three post rift tectonic stages in the sedimentary section of the Bengal Basin, Bangladesh: the drift stage (Late Cretaceous to Eocene), an early collision stage (Oligocene to Middle Miocene) and a late collision stage (Late Miocene to Recent). The sedimentary units comprising coal, coaly shale and sandstones that exist within the pre-rift and rift stage are confined in the Platform Shelf of the basin. This coal-bearing interval can be considered as a potential source within the Permo-Carboniferous Gondwana section. During the drift stage, shallow marine conditions prevailed in the western and northern parts of the basin while the rest of the area was under deep marine conditions. An associated stratigraphic play is developed along the Eocene shelf edge with the deposition of potential oil prone source rocks within the Paleocene-Eocene Cherra and Kopili Formations and defined as the Bogra Petroleum System of western Bangladesh. The collision stage is represented by voluminous (>10km) clastic sedimentation contemporaneous with the uplift of the Himalayan and Indo-Burma ranges during Oligocene-Recent time. The Oligocene Jenam Formation, the major source component of the current proven petroleum system of the Surma Basin in northeast Bangladesh, and the Miocene Bhuban Formation, the possible source for the Hatia Petroleum System of southern Bangladesh, were deposited during this major influx of sediments. Although the Surma Petroleum System has been the historic focus of exploration, significant wildcat opportunities may exist in the underexplored Hatia and in the largely unexplored Bogra Petroleum Systems.