Australia has become the first country to offer commercial offshore acreage for the purpose of storing greenhouse gases in geological formations. Ten offshore areas in five basins/sub-basins are open for applications for Assessment Permits, which will allow exploration in those areas for suitable geological formations and conditions for storage of greenhouse gases (predominantly CO2). The acreage was released on the 27th March 2009 under the Offshore Petroleum and Greenhouse Gas Storage Act 2006. The acreage release is modelled on Australia's annual Offshore Petroleum Acreage Release; applicants can apply for an Assessment Permit for any of the ten areas, which is approximately equivalent to an exploration permit in petroleum terms. Applications will be assessed on a work-bid basis and other selection criteria outlined in the Regulations and Guidance Notes for Applicants. Following the assessment period, project proponents may apply for an injection license (equivalent to a production license in the petroleum industry) to inject and store greenhouse gas substances in the permit area. The areas offered in this first round of Acreage Release include five areas located within the Gippsland and Otway basins, offshore Victoria and South Australia, and the other five areas are located in the Vlaming and Petrel sub-basins, offshore Western Australia and the Northern Territory. The offshore areas offered for GHG geological storage assessment are significantly larger than their offshore petroleum counterparts to account for, and fully contain, the expected migration pathways of the injected GHG substances.

Groundwater monitoring around the CO2CRC Otway Project CO2 injection site aims to (1) establish baseline aquifer conditions prior to CO2 injection, and (2) enable detection monitoring for CO2 leakage, in the unlikely event any should occur in the future. The groundwater composition was monitored at 24 bores around the site for nearly 2 years before injection started. The water samples were analysed for standard bulk properties, and inorganic chemical and isotopic compositions. In addition to sampling, standing water levels were monitored continuously in 6 of the bores using barometric loggers. The shallow groundwaters have compositions typical of carbonate aquifer-hosted waters, being fresh (EC 800-4000 S/cm), dominated by Ca2+, Na+, HCO3- and Cl-, cool (T 12-23°C), and near-neutral (pH 6.6-7.5). Most of the deep groundwater samples are fresher (EC 400-1600 S/cm), also dominated by Ca2+, Na+, HCO3- and Cl-, cool (T 15-21°C), but are more alkaline (pH 7.5-9.5). Time-series reveal that most parameters measured have been relatively stable over the sampling period, although some bores display changes that appear to be non-seasonal. Groundwater levels in some of the shallow bores show a seasonal variation with longer term trends evident in both aquifers.

Total contribution of six recently discovered submerged coral reefs in northern Australia to Holocene neritic CaCO3, CO2, and C is assessed to address a gap in global budgets. CaCO3 production for the reef framework and inter-reefal deposits is 0.26-0.28 Mt which yields 2.36-2.72 x105 mol yr-1 over the mid- to late-Holocene (<10.5 kyr BP); the period in which the reefs have been active. Holocene CO2 and C production is 0.14-0.16 Mt and 0.06-0.07 Mt, yielding 3.23-3.71 and 5.32-6.12 x105 mol yr-1, respectively. Coral and coralline algae are the dominant sources of Holocene CaCO3 although foraminifers and molluscs are the dominant constituents of inter-reefal deposits. The total amount of Holocene neritic CaCO3 produced by the six submerged coral reefs is several orders of magnitude smaller than that calculated using accepted CaCO3 production values because of very low production, a 'give-up' growth history, and presumed significant dissolution and exports. Total global contribution of submerged reefs to Holocene neritic CaCO3 is estimated to be 0.26-0.62 Gt or 2.55-6.17 x108 mol yr-1, which yields 0.15-0.37 Gt CO2 (3.48-8.42 x108 mol yr-1) and 0.07-0.17 Gt C (5.74-13.99 x108 mol yr-1). Contributions from submerged coral reefs in Australia are estimated to be 0.05 Gt CaCO3 (0.48 x108 mol yr-1), 0.03 Gt CO2 (0.65 x108 mol yr-1), and 0.01 Gt C (1.08 x108 mol yr-1) for an emergent reef area of 47.9 x103 km2. The dilemma remains that the global area and CaCO3 mass of submerged coral reefs are currently unknown. It is inevitable that many more submerged coral reefs will be found. Our findings imply that submerged coral reefs are a small but fundamental source of Holocene neritic CaCO3, CO2, and C that is poorly-quantified for global budgets.

Between March 2008 and August 2009, 65,445 tonnes of ~75 mol% CO2 gas were injected in a depleted natural gas reservoir approximately 2000 m below surface at the Otway project site in Victoria, Australia. Groundwater flow and composition were monitored biannually in 2 near-surface aquifers between June 2006 and March 2011, spanning the pre-, syn- and post-injection periods. The shallow (~0-100 m), unconfined, porous and karstic aquifer of the Port Campbell Limestone and the deeper (~600-900 m), confined and porous aquifer of the Dilwyn Formation contain valuable fresh water resources. Groundwater levels in either aquifer have not been affected by the drilling, pumping and injection activities that were taking place, or by the rainfall increase observed during the project. In terms of groundwater composition, the Port Campbell Limestone groundwater is fresh (electrical conductivity = 801-3900 ?S/cm), cool (temperature = 12.9-22.5 C), and near-neutral (pH 6.62-7.45), whilst the Dilwyn Formation groundwater is fresher (electrical conductivity 505-1473 ?S/cm), warmer (temperature = 42.5-48.5 C), and more alkaline (pH 7.43-9.35). Evapotranspiration and carbonate dissolution control the composition of the groundwaters. Comparing the chemical and isotopic composition of the groundwaters collected before, during and after injection shows either no sign of statistically significant changes or, where they are statistically significant, changes that are generally opposite those expected if CO2 addition had taken place. The monitoring program demonstrates that the physical and chemical properties of the groundwaters at the sampled bores have not been affected by CO2 sequestration.

Methane is present in all coals, but a number of geological factors influence the potential economic concentration of gas. The key factors are (1) depositional environment, (2) tectonic and structural setting, (3) rank and gas generation, (4) gas content, (5) permeability, and (6) hydrogeology. Commercial coal seam gas production in Queensland has been entirely from the Permian coals of the Bowen Basin, but the Jurassic coals of the Surat and Clarence-Moreton basins are poised to deliver commercial gas volumes. Depositional environments range from fluvial to delta plain to paralic and marginal marine coals in the Bowen Basin are laterally more continuous than those in the Surat and Clarence-Moreton basins. The tectonic and structural settings are important as they control the coal characteristics both in terms of deposition and burial history. The important coal seam gas seams were deposited in a foreland setting in the Bowen Basin and an intracratonic setting in the Surat and Clarence-Moreton basins. Both of these settings resulted in widespread coal deposition. The complex burial history of the Bowen Basin has resulted in a wide range of coal ranks and properties. Rank in the Bowen Basin coal seam gas fields varies from vitrinite reflectane of 0.55% to >1.1% Rv and from Rv 0.35-0.6% in the Surat and Clarence-Moreton basins in Queensland. High vitrinite coals provide optimal gas generation and cleat formation. The commercial gas fields and the prospective ones contain coals with >60% vitrinite. Gas generation in the Queensland basins is complex with isotopic studies indicating that biogenic gas, thermogenic gas and mixed gases are present. Biogenic processes occur at depths of up to a kilometre. Gas content is important, but lower gas contents can be economic if deliverability is good. Free gas is also present. Drilling and production techniques play an important role in making lower gas content coals viable. Since the Bowen and Surat basins are in a compressive regime, permeability becomes a defining parameter. Areas where the compression is offset by tensional forces provide the best chances for commercial coal seam gas production. Tensional setting such as anticline or structural hinges are important plays. Hydrodynamics control the production rate though water quality varies between the fields.

This publication is the successor to Oil and Gas Resources of Australia 2001 and continues as the definitive reference on exploration, development and production of Australia's petroleum resources. OGRA 2002 provides the background for much of the advice on petroleum resources given to the Australian Government.

The Cooperative Research Centre for Greenhouse Gas Technologies (CO2CRC) Otway Project in the onshore Otway Basin, Victoria, is Australia's first pilot project for the long term sequestration of CO2. The Otway Project has injected 65,445 tonnes of a mixed CO2-CH4 supercritical fluid (77 mol% CO2, 20 mol% CH4, 3 mol% of minor wet gases and N2) some 2000 m below the surface into the Waarre Formation, which is capped by the Belfast Mudstone regional seal. The site has been comprehensively characterised by a multidisciplinary team and the risk analysis has shown the likelihood of leakage out of the injection horizon, let alone to the land surface, to be exceedingly low. Nevertheless, the objectives of the CO2CRC through the Otway Project are not only to demonstrate safe CO2 injection, but also to develop new methodologies for monitoring and verification (M&V) of carbon storage that might apply to future commercial scale injection. At Otway, this involves M&V at the reservoir level and Assurance Monitoring, in the shallow subsurface (aquifers and soils) and the atmosphere. The groundwater monitoring system represents the most comprehensive system for monitoring freshwater in the vicinity of a CO2 storage demonstration to date. Monitoring the groundwater is of particular significance in demonstrating the ongoing integrity of natural resources to the general community.

Identification of major hydrocarbon provinces from existing world assessments for hydrocarbon potential can be used to identify those sedimentary basins at a global level that will be highly prospective for CO2 storage. Most sedimentary basins which are minor petroleum provinces and many non-petroliferous sedimentary basins will also be prospective for CO2 storage. Accurate storage potential estimates will require that each basin be assessed individually, but many of the prospective basins may have ranges from high to low prospectivity. The degree to which geological storage of CO2 will be implemented in the future will depend on the geographical and technical relationships between emission sites and storage locations, and the economic drivers that affect the implementation for each source to sink match. CO2 storage potential is a naturally occurring resource, and like any other natural resource there will be a need to provide regional access to the better sites if the full potential of the technology is to be realized. Whilst some regions of the world have a paucity of opportunities in their immediate geographic confines, others are well endowed. Some areas whilst having good storage potential in their local region may be challenged by the enormous volume of CO2 emissions that are locally generated. Hubs which centralize the collection and transport of CO2 in a region could encourage the building of longer and larger pipelines to larger and technically more viable storage sites and so reduce costs due to economies of scale.

In mid 2011 the Australian Government announced funding of a new four year National CO2 Infrastructure Plan (NCIP) to accelerate the identification and development of sites suitable for the long term storage of CO2 in Australia that are within reasonable distances of major energy and industrial CO2 emission sources. The NCIP program promotes pre-competitive storage exploration and provides a basis for the development of transport and storage infrastructure. The Plan follows on from recommendations from the Carbon Storage Taskforce and the National CCS Council (formerly, the National Low Emissions Coal Council). It builds on the work funded under the National Low Emissions Coal Initiative and the need for adequate storage to be identified as a national priority. Geoscience Australia is providing strategic advice in delivering the plan and will lead in the acquisition of pre-competitive data. Four offshore sedimentary basins (Bonaparte, Browse, Perth and Gippsland basins) and several onshore basins have been identified for pre-competitive data acquisition and study. The offshore Petrel Sub-basin is located in Bonaparte Basin, in NW Australia, has been identified as a potential carbon storage hub for CO2 produced as a by-product from future LNG processing associated with the development of major gas accumulations on the NW Shelf. The aim of the project is to determine if the sub-basin is suitable for long-term storage, and has the potential capacity to be a major storage site. The project began in June 2011 and will be completed by July 2013. As part of the project, new 2D seismic data will be acquired in an area of poor existing seismic coverage along the boundary of the two Greenhouse Gas Assessment Areas, which were released in 2009.

Australia's coal-based power-stations produce about 70% of its energy needs and consequently have led, to the adoption of a multi-disciplinary approach to instigating low emission technologies, which include CO2 capture, injection and storage. The onshore Bowen Basin could provide potential multi-scale storage site projects. Storage potential was demonstrated within a 256 square kilometer area on the eastern flank of the 60-km by 20-km Wunger Ridge using a regional model pertaining to a potential commercial-scale 200 megawatt power-station with emission/injection rates of 1.2 million ton/year. Palaeogeography interpretations of the targeted reservoir indicate a dominantly meandering channel system with permeabilities of up to 1 darcy on the ridge's eastern flank, waning to a deltaic system downdip. Seismic interpretation indicates a relatively unfaulted reservoir-to-seal section on the flank with low-relief structures. Depth to reservoir ranges from 2100 to 2700-m. Simulation from a simplified 3-D block model indicates at least two vertical wells are needed to inject at 1.2 million ton/year in permeabilities of 1 darcy, and reservoir thicknesses of about 5-m. The presence of intra-reservoir baffles reduces the injection rate possible, with a subsequent increase in the number of wells required to maintain the project injection rate, also true for a low-permeability trapping scenario. Long-term storage of acceptable volumes would involve intra-reservoir baffle, stratigraphic, residual, and potentially depleted field trapping scenarios along a 10 to 15-km migration route. Trapping success is ultimately a function of optimal reservoir characteristics both estimated from more complex modeling and, ultimately, collection of infill seismic and new wells.