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The middle to lower Jurassic sequence in Australia's Surat Basin has been identified as a potential reservoir system for geological CO2 storage. The sequence comprises three major formations with distinctly different mineral compositions, and generally low salinity formation water (TDS<3000 mg/L). Differing geochemical responses between the formations are expected during geological CO2 storage. However, given the prevailing use of saline reservoirs in CCS projects elsewhere, limited data are available on CO2-water-rock dynamics during CO2 storage in such low-salinity formations. Here, a combined batch experiment and numerical modelling approach is used to characterise reaction pathways and to identify geochemical tracers of CO2 migration in the low-salinity Jurassic sandstone units. Reservoir system mineralogy was characterized for 66 core samples from stratigraphic well GSQ Chinchilla 4, and six representative samples were reacted with synthetic formation water and high-purity CO2 for up to 27 days at a range of pressures. Low formation water salinity, temperature, and mineralization yield high solubility trapping capacity (1.18 mol/L at 45°C, 100 bar), while the paucity of divalent cations in groundwater and the silicate reservoir matrix results in very low mineral trapping capacity under storage conditions. Formation water alkalinity buffers pH at elevated CO2 pressures and exerts control on mineral dissolution rates. Non-radiogenic, regional groundwater-like 87Sr/86Sr values (0.7048-0.7066) indicate carbonate and authigenic clay dissolution as the primary reaction pathways regulating solution composition, with limited dissolution of the clastic matrix during the incubations. Several geochemical tracers are mobilised in concentrations greater than found in regional groundwater, most notably cobalt, concentrations of which are significantly elevated regardless of CO2 pressure or sample mineralogy.

Covering an area of approximately 247 000km2, the Galilee Basin is a significant feature of central Queensland. Three main depocentres contain several hundred metres of Late Carboniferous to Middle Triassic sediments. Sedimentation in the Galilee Basin was dominated by fluvial to lacustrine depositional systems. This resulted in a sequence of sandstones, mudstones, siltstones, coals and minor tuff in what was a relatively shallow intracratonic basin with little topographic relief. Forty years or more of exploration in the Galilee Basin has failed to discover any economic accumulations of hydrocarbons, despite the presence of apparently fair to very good reservoirs and seals in both the Permian and Triassic sequence. Despite some relatively large distances (upwards of 500km) between sources and sinks, previous and ongoing work on the Galilee Basin suggests that it has potential to sequester a significant amount of Queensland's carbon dioxide emissions. Potential reservoirs include the Early Permian Aramac Coal Measures, the Late Permian Colinlea Sandstone and the Middle Triassic Clematis Sandstone. These are sealed by several intraformational and local seals as well as the regional Triassic Moolayember Formation. With few suitable structural traps and little faulting throughout the Galilee sequence, residual trapping within saline reservoir is the most likely mechanism for storing CO2. The current study is aimed at building a sound geological model of the basin through activities such as detailed mapping, well correlation, and reservoir and seal analysis leading to reservoir simulations to gain a better understanding of the basin.

This paper briefly summaries how intrinsic uncertainties in reservoir characterization, at the proposed Otway Basin Naylor Field carbon-dioxide geo-sequestration site, were risk managed by a process of creation and evaluation of a series of geo-models (term to describe the geo-cellular geological models created by PETREL software) that cover the range of plausible geological possibilities, as well as extreme case scenarios. Optimization methods were employed, to minimize simulation run time, whilst not compromising the essential features of the basic geo-model. For four different Cases, 7 geo-models of the reservoir were created for simulation studies. The reservoir simulation study relies primarily on production history matching and makes use of all available information to help screen and assess the various geo-models. The results suggest that the bulk reservoir permeability is between 0.5 - 1Darcy, the original gas-water-contact was about 2020 mSS and there is a strong aquifer drive.

Many industries and researchers have been examining ways of substantially reducing greenhouse gas emissions. No single method is likely to be a panacea, however some options do show considerable promise. Geological sequestration is one option that utilises mature technology and has the potential to sequester large volumes of CO2. In Australia geological sequestration has been the subject of research for the last 2? years within the Australian Petroleum Cooperative Research Centre's GEODISC program. A portfolio of potential geological sequestration sites (?sinks?) has been identified across all sedimentary basins in Australia, and these have been compared with nearby known or potential CO2 emission sources. These sources have been identified by incorporating detailed analysis of the national greenhouse gas emission databases with other publicly available data, a process that resulted in recognition of eight regional emission nodes. An earlier generic economic model for geological sequestration in Australia has been updated to accommodate the changes arising from this process of ?source to sink? matching. Preliminary findings have established the relative attractiveness of potential injection sites through a ranking approach. It includes the ability to accommodate the volumes of sequesterable greenhouse gas emissions predicted for the adjacent region, the costs involved in transport, sequestration and ongoing operations, and a variety of technical geological risks. Some nodes with high volumes of emissions and low sequestration costs clearly appear to be suitable, whilst others with technical and economic issues appear to be problematic. This assessment may require further refinement once findings are completed from the GEODISC site-specific research currently underway.

In July 2010 Geoscience Australia and CSIRO Marine & Atmospheric Research jointly commissioned a new atmospheric composition monitoring station (' Arcturus') in central Queensland. The facility is designed as a proto-type remotely operated `baseline monitoring station' such as could be deployed in areas that are likely targets for commercial scale carbon capture and geological storage (CCS). It is envisaged that such a station could act as a high quality reference point for later in-fill, site based, atmospheric monitoring associated with geological storage of CO2. The station uses two wavelength scanned cavity ringdown instruments to measure concentrations of carbon dioxide (CO2), methane (CH4), water vapour and the isotopic signature (?13C) of CO2. Meteorological parameters such as wind speed and wind direction are also measured. In combination with CSIRO's TAPM (The Air Pollution Model), data will be used to understand the local variations in CO2 and CH4 and the contributions of natural and anthropogenic sources in the area to this variability. The site is located in a region that supports cropping, grazing, cattle feedlotting, coal mining and gas production activities, which may be associated with fluxes of CO2 and CH4. We present in this paper some of the challenges found during the installation and operation of the station in a remote, sub-tropical environment and how these were resolved. We will also present the first results from the site coupled with preliminary modelling of the relative contribution of large point source anthropogenic emissions and their contribution to the background.

A geomechanical assessment of the Naylor Field, Otway Basin has been undertaken by the Cooperative Research Centre for Greenhouse Gas Technologies (CO2CRC) to investigate the possible geomechanical effects of CO2 injection and storage. The study aims to: - further constrain the geomechanical model (in-situ stresses and rock strength data) developed by van Ruth and Rogers (2006), and; - evaluate the risk of fault reactivation and failure of intact rock. The stress regime in the onshore Victorian Otway Basin is: - strike-slip if maximum horizontal stress is calculated using frictional limits, and; - normal if maximum horizontal stress is calculated using the CRC-1 leak-off test. The NW-SE maximum horizontal stress orientation (142ºN) determined from a resistivity image log of the CRC-1 borehole is broadly consistent with previous estimates and verifies a NW-SE maximum horizontal stress orientation in the Otway Basin. The estimated maximum pore pressure increase (Delta-P) which can be sustained within the target reservoir (Waarre Formation Unit C) without brittle deformation (i.e. the formation of a fracture) was estimated to be 10.9 MPa using maximum horizontal stress determined by frictional limits and 14.5 MPa using maximum horizontal stress determined using CRC-1 extended leak-off test data. The maximum pore pressure increase which can be sustained in the seal (Belfast Mudstone) was estimated to be 6.3 MPa using maximum horizontal stress determined by frictional limits and 9.8 MPa using maximum horizontal stress determined using CRC-1 extended leak-off test data. The propensity for fault reactivation was calculated using the FAST (Fault Analysis Seal Technology) technique, which determines fault reactivation propensity by estimating the increase in pore pressure required to cause reactivation (Mildren et al., 2002). Fault reactivation propensity was calculated using two fault strength scenarios; cohesionless faults (C = 0; ? = 0.60) and healed faults (C = 5.4; ?= 0.78). The orientations of faults with high and low reactivation propensity are similar for healed and cohesionless faults. In addition, two methods of determining maximum horizontal stress were used; frictional limits and the CRC-1 extended leak-off test. Fault reactivation analyses differ as a result in terms of which fault orientations have high or low fault reactivation propensity. Fault reactivation propensity was evaluated for three key faults within the Naylor structure with known orientations. The fault segment with highest fault reactivation propensity in the Naylor Field is on the Naylor South Fault near the crest of the Naylor South sub-structure. Therefore, leakage of hydrocarbons from the greater Naylor structure may have occurred through past reactivation of the Naylor South Fault, thus accounting for the pre-production palaeo-column in the Naylor field. The highest reactivation propensity (for optimally-orientated faults) ranges from an estimated pore pressure increase (Delta-P) of 0.0 MPa to 28.6 MPa depending on assumptions made about maximum horizontal stress magnitude and fault strength. Nonetheless, the absolute values of Delta-P presented in this study are subject to large errors due to uncertainties in the geomechanical model. In particular, the maximum horizontal stress and rock strength are poorly constrained.

This geomechanical analysis of the Browse Basin was undertaken as part of the CO2CRC's Browse Basin Geosequestration Analysis. This study aims to constrain the geomechanical model (in situ stresses), and to evaluate the risk of fault reactivation. The stress regime in the Browse Basin is one of strike-slip faulting i.e. maximum horizontal stress (~ 28.3 MPa/km) > vertical stress (22 MPa/km) > minimum horizontal stress (15.7 MPa/km). Pore pressure is near hydrostatic in all wells except for two, which exhibit elevated pore fluid pressures at depths greater than 3500 m. A maximum horizontal stress orientation of 095' was considered to be most appropriate for the Barcoo sub-basin, which was the area of focus in this study. The risk of fault reactivation was calculated using the FAST (Fault Analysis Seal Technology) technique, which determines fault reactivation risk by estimating the increase in pore pressure required to cause reactivation. Fault reactivation risk was calculated using two fault strength scenarios; cohesionless faults (C = 0; ? = 0.6) and healed faults (C = 5; ? = 0.75). The orientations of faults with high and low reactivation risks is almost identical for healed and cohesionless faults. High angle faults striking N-S are unlikely to reactivate in the current stress regime. High angle faults orientated ENE-WSW and ESE-WNW have the highest fault reactivation risk. Due to the fact that the SH gradient was determined using frictional limits, the most unfavourably oriented cohesionless faults cannot sustain any pore pressure increase without reactivating. By contrast, using a cohesive fault model indicates that those same faults would be able to sustain a pore pressure increase (Delta P) of 9.6 MPa. However, it must be emphasized that the absolute values of Delta P presented in this study are subject to large errors due to uncertainties in the geomechanical model, in particular for the maximum horizontal stress. Therefore, the absolute values of Delta-P presented herein should not be used for planning purposes. Fault reactivation risk was evaluated for 10 faults with known orientations. All faults were interpreted as extending from below the Jurassic target reservoir formation to the surface. The dominant fault in the Barcoo sub-basin is the large fault which extends from Trochus 1 to Sheherazade 1 to Arquebus 1. This deeply penetrating, listric fault initially formed as a normal fault and was subsequently reactivated in thrust mode. Most of the faults in the Barcoo sub-basin trend broadly N-S and are therefore relatively stable with respect to increases in pore pressure. However, there are sections within some individual faults where fault orientation becomes close to optimal. In these sections, small increases in pore pressure (<5 MPa) may be sufficient to cause fault reactivation. If this were to occur, then significant risk of CO2 leakage would exist, as these sections cross-cut the regional seal.

No abstract available

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.