As part of the National CO2 Infrastructure Plan (NCIP) Geoscience Australia is undertaking evaluation of the Gage Sandstone and the overlying South Perth Shale for the long-term storage of CO2. Initial assessment of the seismic data identified widespread fault reactivation and seismic anomalies potentially indicating hydrocarbon seepage. Some of the seismic anomalies clearly correlate with reactivated faults, but not all of them. The study highlights the importance of developing a detailed understanding of spatial variability in seal quality and history of fault reactivation both for petroleum exploration and CO2 storage assessments.

This GHGT-12 conference paper hightlights some results of GA's work on "Regional assessment of the CO2 storage potential of the Mesozoic sucession in the Petrel Sub-basin, Northern Territory, Australia. Record 2014/11".

Within the GEODISC program of the Australian Petroleum Cooperative Research Centre (APCRC), Geoscience Australia (GA) and the University of New South Wales (UNSW) completed an analysis of the potential for the geological storage of CO2. The geological analysis produced an assessment from over 100 potential Environmentally Sustainable Sites for CO2 Injection (ESSCI) by applying a deterministic risk assessment. Out of 100 potential sites, 65 proved to be valid sites for further study. This assessment examined predominantly saline reservoirs which is where we believe Australia?s greatest storage potential exists. However, many of these basins also contain coal seams that may be capable of storing CO2. Several of these coal basins occur close to coal-fired power plants and oil and gas fields where high levels of CO2 are emitted. CO2 storage in coal beds is intrinsically different to storage in saline formations, and different approaches need to be applied when assessing them. Whilst potentially having economic benefit, enhanced coal bed methane (ECBM) production through CO2 injection does raise an issue of how much greenhouse gas mitigation might occur. Even if only small percentages of the total methane are liberated to the atmosphere in the process, then a worse outcome could be achieved in terms of greenhouse gas mitigation. The most suitable coal basins in Australia for CO2 storage include the Galilee, Cooper and Bowen-Surat basins in Queensland, and the Sydney, Gunnedah, and Clarence-Moreton Basins in New South Wales. Brief examples of geological storage within saline aquifers and coal seams in the Bowen and Surat basins, Queensland Australia, are described in this paper to compare and contrast each storage option.

Geoscience Australia is investigating the suitability of offshore sedimentary basins as potential CO2 storage sites. In May 2012 a seabed survey (GA0335/SOL5463) was undertaken in collaboration with the Australian Institute of Marine Science to acquire baseline marine data in the Petrel Sub-basin, Joseph Bonaparte Gulf. The aim was to collect information on possible connections (faults and fluid pathways) between the seabed and key basin units, and to characterise seabed habitats and biota. Two areas were surveyed (Area 1: 471 km2, depth ~ 80-100 m; Area 2: 181 km2, depth ~ 30-70 m), chosen to investigate the seabed over the potential supercritical CO2 boundary (Area 1) and the basin margin (Area 2), with Area 2 located around Flat Top 1 Well. Data analysed include multibeam sonar bathymetry and backscatter, seabed samples and their geochemical and biological properties, video footage and still images of seabed habitats and biota, and acoustic sub-bottom profiles. Pockmarks, providing evidence for fluid release, are present at the seabed, and are particularly numerous in Area 1. Area 1 is part of a sediment-starved, low-relief section of shelf characterised by seabed plains, relict estuarine paleochannels, and low-lying ridges. Facies analysis and radiocarbon dating of relict coastal plain sediment indicates Area 1 was a mangrove-rich environment around 15,500 years ago, transgressed near the end of the Last Glacial period (Meltwater Pulse 1A). Modern seabed habitats have developed on these relict geomorphic features, which have been little modified by recent seabed processes. Seabed habitats include areas of barren and bioturbated sediments, and mixed patches of sponges and octocorals on hardgrounds. In the sub-surface, stacked sequences of northwest-dipping to flat-lying, well-stratified sediments, variably incised by palaeochannels characterise the shallow geology of Area 1. Some shallow faulting through these deposits was noted, but direct linkages between seabed features and deep-seated faults were not observed. Area 2 is dominated by carbonate banks and ridges. Low-lying ridges, terraces and plains are commonly overlain by hummocky sediment of uncertain origin. Pockmarks are present on the margins of banks, and on and adjacent to ridges. Despite the co-location of banks and ridges with major faults at depth, there is a lack of direct evidence for structural connectivity, particularly because of significant acoustic masking in the sub-surface profiles of Area 2. While no direct structural relationship was observed in the acoustic sub-bottom profiles between these banks, ridges and faults visible in the basin seismic profiles, some faults extend through the upper basin units towards the seabed on the margin of Area 2. No evidence was detected at the seabed for the presence of thermogenic hydrocarbons or other fluids sourced from the basin, including beneath the CO2 supercritical boundary. The source of fluids driving pockmark formation in Area 1 is most likely decomposing mangrove-rich organic matter within late Pleistocene estuarine sediments. The gas generated is dominated by CO2. Additional fluids are potentially derived from sediment compaction and dewatering. Conceptual models derived from this are being used to inform regional-scale assessments of CO2 storage prospectivity in the Petrel Sub-basin.

A question and answer style brochure on geological storage of carbon dioxide. Questions addressed include: - What is geological storage? - Why do we need to store carbon dioxide? - How can you store anything in solid rock? - Could the carbon dioxide contaminate the fresh water supply? - Could a hydrocarbon seal leak? - Are there any geological storage projects in Australia?

The Browse Basin is located in the southern Timor Sea region of Australia's North West Shelf and covers an area of ~140,000 km2. It was identified as containing potential Environmentally Suitable Sites for carbon dioxide (CO2) Injection (ESSCI) by the Australian Petroleum CRC's GEODISC program (1999-2003). A regional geological reconnaissance of Cenozoic sandstone and carbonate sequences in the Browse Basin was undertaken in 2007 to determine the potential storage and sealing capacity for geological storage of CO2, the results of which are presented in this report. Methods included the review of available literature and well-completion reports, lithological and mineral analysis of selected well cuttings and interpretation of the wire-line and seismic response of the Cenozoic section.

A geomechanical assessment of the Naylor Field, Otway Basin, Australia has been undertaken to investigate the possible geomechanical effects of CO2 injection and storage. The study aims to evaluate the geomechanical behaviour of the caprock/reservoir system and to estimate the risk of fault reactivation. The stress regime in the onshore Victorian Otway Basin is inferred to be strike-slip if the maximum horizontal stress is calculated using frictional limits and DITF (drilling induced tensile fracture) occurrence, or normal if maximum horizontal stress is based on analysis of dipole sonic log data. The NW-SE maximum horizontal stress orientation (142 degrees N) determined from a resistivity image log is broadly consistent with previous estimates and confirms a NW-SE maximum horizontal stress orientation for the Otway Basin. An analytical geomechanical solution is used to describe stress changes in the subsurface of the Naylor Field. The computed reservoir stress path for the Naylor Field is then incorporated into fault reactivation analysis to estimate the minimum pore pressure increase required to cause fault reactivation (Pp) The highest reactivation propensity (for critically-oriented faults) ranges from an estimated pore pressure increase (Pp) of 1MPa to 15.7MPa (estimated pore pressure of 18.5-233. MPa) depending on assumptions made about maximum horizontal stress magnitude, fault strength,reservoir stress path and Biot's coefficient. The critical pore pressure changes for known faults at Naylor Field range from an estimated pore pressure increase (Pp) of 2MPa to 17MPa (estimated pore pressure of 19.5-34.5 MPa).

Geoscience Australia has recently completed the Bonaparte CO2 Storage project, an assessment of the CO2 storage potential of the Petrel Sub-basin. In 2009, two greenhouse gas assessment leases were released, PTRL-01 and PTRL-02, under the Offshore Petroleum and Greenhouse Gas Storage Act of 2006. Both are proximal to the developing LNG market in Darwin, as well as a number of hydrocarbon accumulations in the Bonaparte Basin. A key phase of the project was geological modelling to test CO2 injection scenarios. Initial 3D seismic horizon surfaces were generated to create a 'simple' geological model. A 'complex' geological model was built by integrating a structure model, which was depth converted. Subsequently, models were populated with reservoir properties such as Vshale, porosity and permeability. Palaeogeography maps were generated for all key stratigraphic units and were used to populate the model where well control was lacking. Using Permedia', CO2 migration simulations with randomly located injection wells were run on a high resolution model to study the migration pathways, major accumulations and the effects of vertical anisotropy. Smaller areas of interest were then identified to reduce the size of the model and allow fluid flow reservoir simulations study using Permedia' and CMG-GEM'. The later study estimated the practical injectivity, storage volume, reservoir pressure during and after CO2 injection.

The Early Cretaceous Gage Sandstone and South Perth Shale formations are one of the most prospective reservoir-seal pairs in the Vlaming Sub-basin. Plays include post-breakup pinch-outs with the South Perth Shale forming a top seal. The Gage reservoir has porosities of 23-30% and permeabilities of 200-1800 mD and was deposited in palaeotopographic lows of the Valanginian breakup unconformity. This is overlain by the thick deltaic South Perth (SP) Supersequence. To characterise the reservoir-seal pair, a detailed sequence stratigraphic analysis was conducted by integrating 2D seismic interpretation, well log analysis and new biostratigraphic data. The palaeogeographic reconstructions for the Gage reservoir are based predominantly on the seismic facies mapping, whereas SP Sequence reconstructions are derived from mapping higher-order prograding sequences and establishing changes in sea level and sediment supply. The Gage reservoir forms part of a sand-rich submarine fan system and was deposited in water depths of > 400 m. It ranges from confined canyon fill to fan deposits on a basin plain. Directions of sediment supply are complex, with major sediment contributions from a northern and southern canyon adjacent to the Badaminna Fault Zone. The characteristics of the SP Supersequence differ markedly between the northern and southern parts of the sub-basin due to variations in palaeotopography and sediment supply. Palaeogeographic reconstructions reveal a series of regressions and transgressions leading to infilling of the palaeo-depression. Seven palaeogeographic reconstructions for the SP Supersequence portray a complex early post-rift depositional history in the central Vlaming Sub-basin. The developed approach could be applicable for detailed studies of other sedimentary basins

As part of the Australian Government National CO2 Infrastructure Plan (NCIP), Geoscience Australia is undertaking CO2 storage assessment of the Vlaming Sub-basin located offshore Western Australia in the southern Perth Basin. The Vlaming Sub-basin is a Mesozoic depocentre containing up to 14 km of sediments. Close proximity of the basin to industrial polluters in the Perth area dictates the need to find CO2 storage solutions in this basin. The main reservoir unit identified as suitable for storage of CO2 is the Early Cretaceous Gage Sandstone deposited in paleo-topographic lows of the Valanginian breakup unconformity. The reservoir unit is laterally extensive (over 1,500 km2) and over most of the area reasonably thick (100 - 300 m). It lies at depths between 1400 and 2000 m below the seafloor, which is suitable for injection of the supercritical CO2 and makes it an attractive target for the long-term storage. The reservoir unit is overlain by a thick deltaic to shallow marine succession of the South Perth Shale, which represents a regional seal in the area. Carbon Storage taskforce estimated that up 1 GT of CO2 can be stored in the Gage Sandstone. The first assessment of the Vlaming Sub-basin undertaken by CO2CRC focused on evaluation of the reservoir unit and overall storage capacity. The current study is based on interpretation and integration of the seismic, well and marine datasets, both existing and acquired since the previous assessment. It includes detailed analysis of reservoir and seal properties and a comprehensive evaluation of the seal integrity risks to allow a more accurate and realistic modeling for CO2 storage.