Barrow Sub-basin Research Articles

Kinematic reconstruction of the Jurassic intraplate rift deformation in the Northern Carnarvon Basin, Australia

Intraplate rift basins, like the inboard sub-basins of the Northern Carnarvon Basin (NCB), host rich energy resources, but their complex geological histories complicate exploration efforts. The paleo-deformation that formed these intraplate rifts also controlled their resource systems distribution. Hence, understanding their complex kinematic and tectonostratigraphic histories can optimise exploration and targeting. However, without forming oceanic seafloor, these regions lack adjacent magnetic seafloor isochrons to constrain paleo-positions of rift margins, rendering kinematic reconstruction nearly impossible. We present a method that constrains the spatiotemporal paleo-distribution of intraplate rift-related deformation and precisely locates paleo-positions of rift margins using time-dependent backstripped subsidence rasters. This method correlates areas with high subsidence rates with rifted regions within extension settings, and we apply it to reconstruct the kinematic evolution of the NCB sub-basin rift.Reconstruction results indicate that the Late Triassic – Early Jurassic extension initiated rifting in the nearshore parts of the NCB, creating Exmouth and Barrow sub-basin grabens at 8 mm/yr maximum rift widening rates. Rifting shifted northeastwards into the Dampier and Beagle regions from Mid Jurassic to Early Cretaceous. Rifting rates in the nearshore regions slowed at ∼155 Ma, coinciding with the Argoland – Australia separation and seafloor spreading within the outboard Argo region. The rates increased again at ∼145 Ma during the Tithonian extension and then decreased significantly at ∼120 Ma during the seafloor spreading in the Cuvier and Gascoyne regions. The temporal correlation between Gondwana dispersal events and the nearshore sub-basin rift evolution suggests that the sub-basins were part of a broader deformation zone across the margin. However, strain localised and triggered breakup and seafloor spreading within the outboard Argo, Gascoyne, and Cuvier regions. Such breakups released extension forces and caused rift cessation in the nearshore NCB sub-basins.

Concurrent 14. Presentation for: Major geological surfaces of the Exmouth Plateau from the new Broadband PreSDM reprocessed 3D seismic data with full waveform inversion

Presented on Wednesday 18 May: Session 14 The Barrow Sub-basin and Exmouth Plateau, of Australia’s North West Shelf, contain Australia’s largest gas reserves, underpinning the three major LNG facilities, including Gorgon, Wheatstone and Pluto. In addition, there remains significant near-field exploration potential such as the Sasanof prospect. While there is full 3D seismic coverage in the basin, the existing 3D surveys are of different vintages covering only parts of the basin with diverse acquisition and processing parameters. Multi-Client Resources has produced an extensive 3D seismic reprocessing project (BEX-MC3D) incorporating 23 legacy 3D surveys to provide a seamless 25 570 km2 3D dataset. The BEX-MC3D was processed from field tape through DUG Technology’s advanced Broadband PreSDM processing sequence with Full Waveform Inversion (FWI) imaging. The BEX-MC3D provides one continuous superlative 3D dataset covering almost the entire Barrow Sub-basin and the Exmouth Plateau. Major geological surfaces corresponding to key tectonic events from overburden to reservoirs have been interpreted from the BEX-MC3D Priority area in the current study. These high-fidelity imaged surfaces form a basin-wide framework for: (1) rapid exploration lead and prospect identification through the creation of trap and reservoir visualisations; (2) improved reservoir connectivity analysis and modelling of producing and discovered fields to support better reservoir management and field development decisions; and (3) improved understanding of basin-burial history for reservoir quality and geo-mechanical property prediction. This paper will present and discuss major geological surfaces in the context of future exploration lead/prospect identification, reservoir characterisation for field development and management, and improving overall understanding of the basin history. To access the presentation click the link on the right. To read the full paper click here

Major geological surfaces of the Exmouth Plateau from the new Broadband PreSDM reprocessed 3D seismic data with full waveform inversion

The Barrow Sub-basin and Exmouth Plateau, of Australia’s North West Shelf, contain Australia’s largest gas reserves, underpinning the three major LNG facilities, including Gorgon, Wheatstone and Pluto. In addition, there remains significant near-field exploration potential such as the Sasanof prospect. While there is full 3D seismic coverage in the basin, the existing 3D surveys are of different vintages covering only parts of the basin with diverse acquisition and processing parameters. Multi-Client Resources has produced an extensive 3D seismic reprocessing project (BEX-MC3D) incorporating 23 legacy 3D surveys to provide a seamless 25 570 km2 3D dataset. The BEX-MC3D was processed from field tape through DUG Technology’s advanced Broadband PreSDM processing sequence with Full Waveform Inversion (FWI) imaging. The BEX-MC3D provides one continuous superlative 3D dataset covering almost the entire Barrow Sub-basin and the Exmouth Plateau. Major geological surfaces corresponding to key tectonic events from overburden to reservoirs have been interpreted from the BEX-MC3D Priority area in the current study. These high-fidelity imaged surfaces form a basin-wide framework for: (1) rapid exploration lead and prospect identification through the creation of trap and reservoir visualisations; (2) improved reservoir connectivity analysis and modelling of producing and discovered fields to support better reservoir management and field development decisions; and (3) improved understanding of basin-burial history for reservoir quality and geo-mechanical property prediction. This paper will present and discuss major geological surfaces in the context of future exploration lead/prospect identification, reservoir characterisation for field development and management, and improving overall understanding of the basin history.

Tilting of the Australian continent: New evidence from the subsidence and deposition history of the Northern Carnarvon Basin

Studies of global sea-level changes, plate kinematics, marine inundation, and morphology of the continental shelves suggest that the Australian continent has been tilting north eastwards since the Late Cretaceous. Here we investigate the direct impact of this phenomenon and the preceding tectonic events on the evolution of the Northern Carnarvon Basin and discuss their implications for hydrocarbon resources. We use backstripping and decompaction techniques to develop subsidence, sedimentation, and porosity evolution models for the basin, which sits on the axis of the tilt. The goal is to highlight the spatial and temporal variation of subsidence and sedimentation rates and assess their impacts on the porosity of the Early Cretaceous reservoirs within the basin, then give insights into the factors that created accommodation space for sediments. The results reveal a north-eastward shift of subsidence and sedimentation rates within the region. Thus, we observe the highest subsidence rates (∼90 m/Ma) in the southwest (Exmouth and Barrow sub-basins) from Early Jurassic to Early Cretaceous. In the Middle Cretaceous, subsidence and sedimentation moved north-east towards the Dampier (∼40 m/Ma) and some parts of the Barrow sub-basin (∼35 m/Ma). In the Cenozoic era, the highest subsidence rates moved further north-east towards the Beagle sub-basin (∼40 m/Ma) and the North Rankin platform. The results show that the Palaeozoic-Mesozoic rifting events produced higher tectonic subsidence (∼3 km) and higher sediment supply in the southwestern Exmouth and Barrow sub-basins, which reduced towards the north-east in the Dampier and Beagle Sub-basins (∼1.5 km). Subsidence plots along a NE-SW transect and the porosity evolution model results also demonstrate the tilting occurring in these sub-basins. We propose that mantle-driven and subduction-driven tilting of the Australian continent caused the observed local tilting of these sub-basins. Additionally, porosity evolution results provide further information for the definition of periods of hydrocarbon migration in the area.

Developing the world’s largest CO2 Injection System – a history of the Gorgon Carbon Dioxide Injection System

The Gorgon CO2 Injection System is a key element of the Gorgon LNG Project on Barrow Island. Two gas fields currently supply the LNG plant including the Gorgon Field, which contain c. 14% CO2 content. Rather than vent the separated reservoir CO2 into the atmosphere, the Gorgon JVPs undertook to develop the CO2 Injection System, which was designed and constructed to inject around 3.5 million tonnes per annum into the Dupuy Formation, a Jurassic sandstone unit below Barrow Island in the Barrow Sub-basin. Chevron Australia Pty Ltd (Chevron), as operator on behalf of the Gorgon joint venture participants, has been working on the development of the project, through early concept select, appraisal, final concept selection, detailed design, construction, commissioning and now early operations. This work commenced in 2003, with project approvals in 2009. Since then, 17 wells have been drilled, pipelines and compression facilities constructed and installed, baseline monitoring data acquired, and injection operation has commenced. It is expected that the Gorgon CO2 Injection System will have a 40-plus year lifespan. The volume and rate of CO2 injection makes it the largest CO2 injection project for geological storage undertaken to date. Early results indicate that the injectivity is better than originally forecast. Chevron and the Gorgon joint venture participants will continue to monitor performance against expectations and revise assumptions, models and forecasts over time.

Molecular fingerprint from plant biomarkers in Triassic-Jurassic petroleum source rocks from the Dampier sub-Basin, Northwest Shelf of Australia

Abstract Distinctive land plant biomarker distributions have been described for Triassic-Jurassic source rocks in the Dampier sub-Basin, Northwest Shelf of Australia. Proxies like the higher plant parameter [HPP = retene/(cadalene + retene)] cannot be applied to describe palaeoclimate globally; in fact, the HPP showed similar values (∼0.8) for Triassic and Jurassic source rocks despite the difference in sea level. The higher plant fingerprint [HPF or relative distribution of retene, cadalene and 6-isopropyl-1-isohexyl-2-methylnaphthalene (ip-iHMN)], however, represents a potential discrimination tool for source rock intervals. Here, we name this proxy as plant fingerprint (PF) since our investigation supports a non-vascular plant origin for ip-iHMN. The most distinctive patterns in the PF are found in the Early Jurassic with a predominance of cadalene (∼65%) in an arid climate, and the Middle Jurassic with a predominance of retene (∼70%) during a climate recovery under more humid conditions. Petroleum fluids from the Dampier sub-Basin are cadalene-dominated compared to fluids from the Barrow sub-Basin, which are retene-dominated. We emphasise that the present approach has only local implications and the parameters used herein (including the higher plant parameter or HPP) cannot lead to interpretations at a global scale.

Marginal fault systems of the Northern Carnarvon Basin: Evidence for multiple Palaeozoic extension events, North-West Shelf, Australia

Palaeozoic structures along the North-West margin of Australia have long been recognised as fundamental events responsible for the formation of the offshore basins that comprise this prolific hydrocarbon producing region. However, the tectonic setting in which this rifting occurred remains unclear. Detailed mapping of the geometry and tectono-stratigraphy of Permian and Carboniferous structures of the inboard Barrow, Dampier and Beagle sub-basins of the Northern Carnarvon Basin is possible using regional scale interpretation of publicly available 2D and 3D seismic data. Through seismic interpretation and mapping, we show two distinct orientations of structures that provide evidence for a poly-phase rift history of the North-West margin during the Palaeozoic. NNE trending faults of the Candace Terrace (Barrow sub-basin) were initiated in the Carboniferous or Devonian but were underfilled, resulting in erosion of the fault block crest and filling of the remnant rift-related topography by conformable sequences of later Permian and Triassic sediments. By contrast, NE-SW oriented faults of the Mermaid Nose (Dampier sub-basin) experienced a distinct phase of Permian activity and are unconformably overlain by Triassic sediments. In the Beagle sub-basin, both orientations of structures are present. Throughout the marginal fault systems of the Northern Carnarvon Basin, complex fault geometries and significant deformation of hanging wall strata are associated with reactivation of the eroded fault block crests and overprinting of faults during subsequent Mesozoic extension. This has implications for understanding the geodynamic evolution of a poly-phase extensional continental margin.

Stratigraphy of the Birdrong: an integrated approach

A detailed study of the Early Cretaceous Birdrong Sequence (S. areolata - P. burgeri) has been undertaken in the East Spar and Woollybutt fields, which lie in the northern end of the Barrow Delta complex in the Barrow Sub-basin, Northern Carnarvon Basin. This project integrates palynological, sedimentological and seismic stratigraphic interpretations to progress our understanding of the way in which the Barrow Delta evolved. The results will help develop remaining hydrocarbon prospectivity in the northern Barrow area. Palynological analysis within the Helby, Morgan and Partridge (2004) zonation scheme for the North West Shelf has enabled the identification of several significant biostratigraphic events, which have allowed further subdivision of the existing broad palynological zones. These palynological events represent influxes of specific dinoflagellate cyst taxa that may be tied to key stratal surfaces. These surfaces include transgressive ravinement surfaces, sequence boundaries and flooding surfaces. The palynological and sedimentological data, when combined, indicate a strong facies relationship between specific taxa and interpreted depositional environment. Such taxa include Gagiella, freshwater and brackish algae, and fully marine dinoflagellate cysts including Kaiwaradinium scrutillinum, Systematophora areolata, Phoberocysta neocomica and Cribroperidinium muderongense. The integration of sedimentology and palynology provides a powerful tool in interpreting depositional systems in shallow marine palaeoenvironments. Initial results indicate this may be used as a predictive tool for reservoir correlation and facies modelling. Key stratal surfaces identified through palynological and sedimentological study will be tested against 3D seismic to understand fully the stratigraphy of the study interval.

The 2010 Australian offshore release for petroleum exploration

The Australian Government formally releases new offshore exploration areas at the annual APPEA conference. In 2010, thirty-one areas in five offshore basins are being released for work program bidding. Closing dates for bid submissions are either six or twelve months after the release date—i.e. 11 November 2010 and 12 May 2011—depending on the exploration status in these areas and on data availability. The 2010 release areas are located in Commonwealth waters offshore Northern Territory, Western Australia and South Australia, comprising intensively explored areas close to existing production as well as new frontiers. The Westralian Superbasin along the North West Shelf continues to feature prominently, and is complimented by a new frontier area in offshore SW Australia (Mentelle Basin), as well as two areas in the Ceduna/Duntroon sub-basins in the eastern part of the Bight Basin. The Bonaparte Basin is represented by three areas in the Petrel Sub-basin and two areas in the Vulcan Sub-basin. Further southwest, four large areas are being released in the outer Roebuck Basin—a significantly under-explored region. This year, the Carnarvon Basin provides 16 release areas of which three are located in the Beagle Sub-basin, five in the Dampier Sub-basin, five in the Barrow Sub-basin, three on the Exmouth Plateau and three in the Exmouth Sub-basin. The largest singular release area covers much of the Mentelle Basin in offshore SW Australia, and two areas are available in the Ceduna and Duntroon sub-basins as part of South Australia’s easternmost section of the Bight Basin. The 2010 Offshore Acreage Release offers a wide variety of block sizes in shallow as well as deep water environments. Area selection has been undertaken in consultation with industry, the States and the Northern Territory. As part of Geoscience Australia’s Offshore Energy Security Program, new data has been acquired in offshore frontier regions parts of which are being published on the Mentelle Basin (Borissova et al, this volume).

Variation of vertical stress in the Carnarvon Basin, NW Shelf, Australia

Variations in vertical stress magnitudes can be attributed to lateral facies variations, diagenesis, localized uplift and disequilibrium compaction overpressure. Vertical stress magnitudes have been calculated using density and checkshot data from 47 wells in the Carnarvon Basin, on the NW Shelf of Australia. The vertical stress ranges from 20.2 MPa km − 1 to 23.8 MPa km − 1 below seabed; demonstrating a significant variation across the basin. The largest vertical stress magnitudes were calculated for the Dampier Sub-Basin, the eastern Barrow Sub-Basin and on the Peedamullah Shelf. The smallest vertical stress magnitudes were calculated in the Kangaroo Syncline, the western Barrow Sub-Basin and offshore across the Exmouth Plateau. High rock densities, thus, high vertical stress magnitudes, can be due to uplifted rock that is over-compacted relative to its current depth. In the Carnarvon Basin, areas of elevated vertical stress magnitudes correspond to areas of identified uplift. Uplift at the Bambra Anticline has previously been estimated to be approximately 900 m. Calculations within the Bambra-4 well demonstrate that a 900 m increase in burial depth of a regionally consistent lithostratigraphic unit (the Muderong Shale) equates to a 0.22 g cm − 3 increase in rock density. Thus, the difference between uplifted, over-compacted rock and normally-compacted rock (no uplift) is equivalent to a difference in the vertical stress magnitude of 2.1 MPa km − 1 at the Bambra Anticline. This value, totalling the difference between over-compacted (uplifted) and normally-compacted sedimentary rock (2.1 MPa km − 1 ), accounts for some part of the 3.6 MPa km − 1 variation in vertical stress magnitude observed across the Carnarvon Basin. Therefore, recent tectonic uplift has had a significant impact on the present-day magnitude of the vertical stress and is interpreted to be responsible for the majority of observed variation of vertical stress in the Carnarvon Basin.

Review of the 2008 offshore petroleum exploration release areas

Each year the Australian Government releases new offshore opportunities for petroleum exploration. Thirty-five new exploration areas located across five of Australia’s offshore sedimentary basins are offered in the 2008 Release. All the areas are available through a work program bidding system with closing dates for bids at six and 12 months from the date of release. Acreage in the first round closes on 9 October 2008 and includes the more explored areas. The second closing round on 9 April 2009 comprises acreage located in less well explored and frontier regions. The 2008 exploration areas are in Commonwealth waters offshore of Western Australia and the Northern Territory, and in the Territory of the Ashmore and Cartier Islands adjacent area. The 2008 Release focusses on the North West Shelf, as well as offering two new exploration areas in the Vlaming Sub-basin in the offshore Perth Basin. Seven of the new release areas are located in Australia’s major hydrocarbon producing province, the Carnarvon Basin. They include a shallow water area in the western Barrow Sub-basin and another on the Rankin Platform, three areas in deeper water in the Exmouth Sub-basin and two on the deepwater Exmouth Plateau. Six areas are available for bidding in the Browse Basin and another five in the Bedout Sub-basin of the Roebuck Basin. In the Bonaparte Basin, the 15 Release areas are located in shallow water and represent a range of geological settings, including the Vulcan and Petrel sub-basins, Ashmore Platform and Londonderry High. The 2008 Offshore Petroleum Exploration Release of 35 areas in five basins covers a wide range in size, water depth and exploration maturity to provide investment opportunities suited to both small and large explorers. The Release areas are selected from nominations from industry, the States and Territory, and Geoscience Australia. The focus of the 2008 Release is on the North West Shelf where there is strong industry interest in the producing Carnarvon and Bonaparte basins and in the Browse Basin, the home of super-giant gas fields under active consideration for development. Also included in the 2008 Release is the Bedout Sub-basin, in the Roebuck Basin, located on the central North West Shelf, between the hotly contested Carnarvon and Browse basins. In addition, the Release show-cases the southern Vlaming Sub-basin, Perth Basin, where recent studies by Geoscience Australia provide a new understanding of petroleum potential (Nicholson et al, this volume).

Reservoir compartment prediction of the Simpson field from the geostatistical inversion of AVO seismic data

The Simpson field in the Barrow Sub-basin (Carnarvon Basin) is nearing depletion. Most of the producing wells are showing relatively high water cuts. Based on volumetric mapping and the drilling results from nearby analogous fields, some unproduced reserves are potentially remaining in the field within compartments separated by low permeability shale barriers. The challenge is to establish a methodology for identifying these compartments and to quantify unproduced oil. The reservoir of the Simpson field is the Early Cretaceous Flag Sandstone. The reservoir zone has three distinct lithotypes: oil-saturated sandstone, water-saturated sandstone and shale. The shales encountered in the wells have a typical thickness of less than 3 m, significantly below seismic resolution. However, these lithotypes show good statistical separation of elastic properties (e.g. P-impedance and Vp/Vs), so a properly-constrained geostatisitcal inversion can be used to predict the relatively thin shale barriers. The geostatisitcal inversion is based on Bayesian Inference and uses a Markov Chain Monte Carlo method to randomly sample the probabilistic distribution arising from all input beliefs. The end result is multiple elastic property and lithotype realizations. The analysis of the realizations output from the geostatistical inversion led to improved reservoir volumetric calculations and the identification of highly probable shale barriers.

EXPLORATION HIGHLIGHTS FOR 2006

Key business indicators show an upward trend in exploration activity in Australia during 2006. The year was marked by fluctuating high oil prices, a strong uptake of acreage in most basins, and increased levels of drilling activity and seismic acquisition. Market demand for product, production infrastructure and the fruition of several development projects have pushed the level of exploration activity in both offshore and onshore basins. Despite this trend and the spread of tenements, almost all petroleum discoveries made during 2006 were located within 15 km of existing (but often undeveloped) fields.The Carnarvon Basin continued to be the focus of most offshore exploration activity during 2006, with the highest levels of 3D seismic acquisition and exploration/appraisal/development drilling in the country. Discoveries in the Carnarvon Basin also covered the broadest range of water depths—extending from the oil and gas discoveries made by Apache on the inboard margin of the Barrow Subbasin, to the deepwater gas discoveries at Clio–1 and Chandon–1 by Chevron. Several large gas discoveries were made in the Carnarvon and Bonaparte basins and provide significant tie-back opportunities to existing and planned infrastructure. The Bonaparte Basin also saw significantly increased levels of 2D and 3D seismic acquisition during 2006. Onshore, the Cooper/Eromanga basins continued to experience the highest level of drilling activity and seismic acquisition, while maintaining an overall high drilling success rate. For the first time in many years, data acquisition also occurred in frontier basins like the Daly (Northern Territory), Darling (New South Wales), Tasmanian (Tasmania) and Faust/Capel basins (Lord Howe Rise region).Coal seam methane (CSM) exploration maintained a strong performance in 2006, particularly in Queensland, while South Australia, Queensland and Victoria continue to lead the way with large tracts of acreage gazetted for geothermal energy exploration.

An integrated evaluation of hydrocarbon charge and retention at the Griffin, Chinook, and Scindian oil and gas fields, Barrow Subbasin, North West Shelf, Australia

Paleo-oil-water contacts (paleo-OWCs) defined in eight wells from the Griffin, Chinook, and Scindian fields, Barrow Subbasin, Australian North West Shelf, are 47–147 m (154.2–482.3 ft) deeper than the current OWCs. The paleo-OWCs are deeper than the spillpoints separating the fields and are consistent with the existence of a single large paleo-oil accumulation. A plane of best fit projected through these paleo-OWCs describes an inclined surface with a northwesterly dip of approximately 1.5. Assuming that this paleo-OWC was horizontal at the time of charge, three-dimensional structural restoration was used to assess the trap geometry at that time and the impact of subsequent post-charge structuring. The paleo-OWC tilt is reduced to 0.6 by restoration to the middle Miocene, and by the base Tertiary, the paleo-OWC became over-rotated by 0.1. A horizontal paleo-OWC plane occurred some time between these periods and is broadly consistent with oil-charge estimates derived from fluid-inclusion paleotemperature data combined with one-dimensional basin modeling. The restored paleostructure and the approximate position of the paleo-OWC are consistent with the combined trap having initially been filled to spill. The bulk rock volume of the paleo-accumulation is more than 10 times larger than the current accumulation, indicating the loss of significant oil volumes as post-charge westerly tilting progressively reduced the trap capacity. Based on the current oil volumes (about 200 million bbl), nearly 2 billion bbl of oil was spilled from the trap by the relative shallowing of the eastern spillpoint. The region to the east and north of the Griffin area fields is lightly drilled, and remigration of such large volumes of oil to this area provides great incentive for future exploration. New targets are also inferred on the hanging wall of the main Griffin fault, which could represent bypassed pay.

Reservoir characterisation of the Flag Sandstone, Barrow Sub-basin, using an integrated, multi-parameter seismic AVO inversion technique

The Early Cretaceous Flag Sandstone within the Barrow Sub-basin is a proven hydrocarbon reservoir. The main trapping mechanism is four-way dip closed anticlines, formed by drape compaction. An integrated, multi-parameter seismic AVO inversion technique was utilized that improved the mapping of the Flag Sandstone and identified the presence of trapped hydrocarbons. The identification of the Flag Sandstone on seismic sections is complicated due to a low acoustic impedance contrast between the Flag Sandstone and the overlying shales. The same interface gives a good AVO response. Previous interpretation efforts have used the seismic AVO response to map the top of the Flag Sandstone on far-angle stacks. These efforts were very successful for mapping structure but were influenced by wavelet tuning effects and were limited for high-grading the structures based on hydrocarbon potential. To aid in characterizing the fluid distribution in the reservoir rocks a simultaneous AVO inversion algorithm was used based on three partial angle stacks and conditioned well logs, inverting for acoustic and shear impedance. The results of this multi-parameter impedance inversion produced a variety of attributes. The Vp/Vs attribute was aimed at improving the TWT structural pick whereas P-impedance became the basis for discriminating water and oil saturated sands.

Reservoir characterization of the Flag Sandstone, Barrow Sub-basin, using an integrated, multiparameter seismic AVO inversion technique

Editor's note: This material was presented at the 17th ASEG Geophysical Conference and Exhibition. A series of oil and gas fields have been discovered since 1979 in the Early Cretaceous Flag Sandstone in the Barrow Sub-basin of Western Australia's Carnarvon Basin. The Flag Sandstone is a lowstand complex of gravity flow sandstones deposited beyond the shelf edge of the Barrow delta. Figure 1 shows a stratigraphic chart. The permeable Flag Sandstone forms a consistent, high-quality reservoir that is capped by the impermeable Muderong shale. In the area immediately adjacent to and south of Varanus Island, the main trapping mechanism is four-way dip-closed anticlines, formed by drape compaction. Structural closure alone does not appear sufficient for oil emplacement as a limited number of prominent closed structures have been drilled and found water-wet. The known oil fields are nearing depletion and the goal is to properly locate additional wells to ensure complete development of the area. Figure 1. Stratigraphic chart for Carnarvon Basin showing the Early Cretaceous Flag Sandstone and overlying Muderong Shale (Barrow Sub-basin). The identification of the closed anticlinal structures on seismic data is complicated due to a poor P-impedance contrast between the Flag Sandstone and the overlying Muderong Shale. However, a strong V p / V s contrast exists between the sandstone and shale, resulting in reasonably consistent AVO class II effects. A far-angle stack with an angle range of 30–45° has been used successfully to map the structure on the top of the Flag Sandstone. The difficulty with this mapping technique is that it is subject to tuning effects and assumes a consistent AVO response. However, some wells in the area demonstrate an AVO response that does not match a simple model. Thus, a more robust technique was required that could model the true AVO response, provide an accurate pick …

GEOLOGICAL STORAGE OF CARBON DIOXIDE: MODELLING THE EARLY CRETACEOUS SUCCESSION IN THE BARROW SUB-BASIN, NORTHWEST AUSTRALIA

Potential sites for geological storage of CO2 require detailed assessment of storage capacity, containment potential and migration pathways. A possible candidate is the Flag Sandstone of the Barrow Sub-basin, northwest Australia, sealed by the Muderong Shale. The Flag Sandstone consists of a series of stacked, amalgamated, basin floor fan lobes with good lateral interconnectivity. The main reservoir sandstones have high reservoir quality with an average porosity of 21% and an average permeability of about 1,250 mD. The Muderong Shale has excellent seal capacity, with the potential to withhold an average CO2 column height of 750 m. Other containment issues were addressed by in situ stress and fault stability analysis. An average orientation of 095°N for the maximum horizontal stress was estimated. The stress regime is strike-slip at the likely injection depth (below 1,800 m). Most of the major faults in the study area have east-northeast to northeast trends and failure plots indicate that some of these faults may be reactivated if CO2 injection pressures are not monitored closely. Where average fault dips are known, maximum sustainable formation pressures were estimated to be less than 27 MPa at 2 km depth. Hydrodynamic modelling indicated that the pre-production regional formation water flow direction was from the sub-basin margins towards the centre, with an exit point to the southwest. However, this flow direction and rate have been altered by a hydraulic low in the eastern part of the sub-basin due to hydrocarbon production. The integrated site analysis indicates a potential CO2 storage capacity in the order of thousands of Mtonnes. Such capacity for geological storage could provide a technical solution for reducing greenhouse gas emissions.

Hydrodynamics to assess hydrocarbon migrationin faulted strata-methodology and a case study from the North West Shelf of Australia

The North West Shelf hydrodynamics pressure database currently contains about 8000 pressure data points and hundreds of stress, temperature and water salinity data. All data have been ranked using a newly developed quality-control system (Pressure QC ™ ). A hydrodynamic workflow was used to interpret fluid migration pathways in faulted strata and to identify fault seal integrity in the Barrow sub-basin on the North West Shelf. The comprehensive database and methodology investigate hydrocarbon migration from basin-centred source rocks to the eastern and south-eastern edge of the basin across the Flinders Fault zone. The different structural styles and orientations along the basin-edge Flinders fault zone determine hydraulic connection to the basin margin and potential up-dip migration of hydrocarbons. Hydrodynamic data show that north of 21 °S latitude, the fault zone acts as a fluid barrier and hydraulic communication occurs only at specific locations where individual faults lose displacement at their tips and in relay zones. A convoluted migration pathway is required to migrate oil from the mature regions to the basins' edge. South of 21 °S latitude, the Flinders Fault zone changes orientation and the hydrostratigraphic unit is in hydraulic communication with the basin margin, increasing the prospectivity of oil migration into this region, as is documented by oil shows.

FLATTENED TIME SLICES—A STRATIGRAPHIC APPROACH TO 3D SEISMIC INTERPRETATION ON THE NORTH WEST SHELF OF AUSTRALIA

Conventional time slices are a powerful method of integrating horizon picks and fault picks into a unified interpretation and are a handy way of viewing structures, especially in faulted areas. The limitation is that time slices are seldom useful in viewing the morphology of a horizon. A 3D cube is the present day structural volume; it retains any structure imparted on the geology after deposition. When a time slice is defined, the structural dip limits the area of the integral depositional elements that can be imaged. For example, a depositional surface developed as part of a fluvial-deltaic system is seldom one event and it cannot be easily identified and picked in a vertical section. Flattened time slices take out the regional dip and allow a complete depositional surface to be viewed.The North West Shelf of Australia and especially the Barrow Sub-basin is a particularly suitable place to apply this exploration technique. The entire sedimentary package, laid down in a variety of depositional environments, has been tilted to the northwest by an average of 3°. This strong post-depositional tilt limits the uses of conventional time slices to imaging only the diprelated features of an area. Whereas conventional time slices only make apparent the dip of the section, flattened time slices can reveal subtle and intricate stratigraphic architecture.This paper describes the seismic features of a number of depositional systems from the Barrow Sub-basin and outlines how complex channel systems can be determined by the use of the flattened time slice approach. Given the importance of stratigraphic plays in the Barrow Subbasin, the technique outlined in this paper is considered to be an important exploration tool.

MID TO LATE JURASSIC SHALLOW MARINE SEQUENCES OF THE EASTERN BARROW SUB-BASIN: THE ROLE OF LOW-STAND DEPOSITION IN NEW EXPLORATION CONCEPTS

Several wells drilled along the fault-terraced eastern margin of the Barrow Sub-basin of the Australian North West Shelf have shed light on the pattern of Callovian to Tithonian sedimentation in the area. Much of this section has historically been interpreted as a product of deep marine depositional environments.Sandstone reservoirs cored in Linda–1/ST1, Linda–2 (both Wanaea spectabilis b age) and Denver–1/ST1 (Rigaudella aemula age) exhibit coarsening-upward cycles typical of marine parasequences, and possess sharp, erosive lower contacts with underlying claystone. In the case of Denver–1/ST1, the sandstones are heavily bioturbated with a distinct shallow marine trace fossil assemblage. Burrows are less evident in the sandstones from the Linda wells, although several thin bioturbated horizons—also with shallow marine trace fossils—are encountered. Similar patterns of shallow marine deposition are observed in previously drilled wells within the study area, and evidence of pedogenesis is found in core from Georgette–1 (R. aemula age), suggesting that exposure occurred on some of the higher fault terraces during low-stand conditions in the Middle to Late Jurassic.Further to the west, deepwater submarine fan sediments, deposited during low-stands, have been recognised. A range of time equivalent low-stand deposits—which are spatially and genetically exclusive— therefore exists within the sub-basin. Indeed such a spectrum should be expected in complex and tectonically active areas such as the Jurassic Barrow Sub-basin.The recognition of shallow marine deposits in the area has major implications with respect to the location and geometry of reservoir sandstones. The low-stand shoreface model, as opposed to the deep marine turbidite model, leads to the prediction of sandstone deposition aligned roughly parallel—rather than perpendicular— to the palaeo-shoreline and the potential for deeperwater sandstones further downdip.