No abstract available

Phase two of the China Australia Geological Storage of CO2 (CAGS2) project aimed to build on the success of the previous CAGS project and promote capacity building, training opportunities and share expertise on the geological storage of CO2. The project was led by Geoscience Australia (GA) and China's Ministry of Science and Technology (MOST) through the Administrative Centre for China's Agenda 21 (ACCA21). CAGS2 has successfully completed all planned activities including three workshops, two carbon capture and storage (CCS) training schools, five research projects focusing on different aspects of the geological storage of CO2, and ten researcher exchanges to China and Australia. The project received favourable feedback from project partners and participants in CAGS activities and there is a strong desire from the Chinese government and Chinese researchers to continue the collaboration. The project can be considered a highly successful demonstration of bi-lateral cooperation between the Australian and Chinese governments. Through the technical workshops, training schools, exchange programs, and research projects, CAGS2 has facilitated and supported on-going collaboration between many research institutions and industry in Australia and China. More than 150 experts, young researchers and college students, from over 30 organisations, participated in CAGS2. The opportunity to interact with Australian and international experts at CAGS hosted workshops and schools was appreciated by the participants, many of whom do not get the opportunity to attend international conferences. Feedback from a CAGS impact survey found that the workshops and schools inspired many researchers and students to pursue geological storage research. The scientific exchanges proved effective and often fostered further engagement between Chinese and Australian researchers and their host organisations. The research projects often acted as a catalyst for attracting additional CCS funding (at least A$700,000), including two projects funded under the China Clean Development Mechanism Fund. CAGS sponsored research led to reports, international conference presentations, and Chinese and international journal papers. CAGS has established a network of key CCS/CCUS (carbon capture, utilisation and storage) researchers in China and Australia. This is exemplified by the fact that 4 of the 6 experts that provided input on the 'storage section of the 12th Five-Year plan for Scientific and Technological Development of Carbon Capture, Utilization and Storage, which laid out the technical policy priorities for R&D and demonstration of CCUS technology in China, were CAGS affiliated researchers. The contributions of CAGS to China's capacity building and policy CCUS has been acknowledged by the Chinese Government. CAGS support of young Chinese researchers is particularly noted and well regarded. Letters have been sent to the Secretary of the Department of Industry and Science and to the Deputy CEO of Geoscience Australia, expressing China's gratitude for the Australian Government's support and GA's cooperation in the CAGS project.

There are numerous isotopic tracers that have the potential to track the movement of CO2 as it is sequestered underground. Their primary role is in verifying the presence of sequestered CO2. These tracers range from CO2 to 3He to PFT?s to SF6. With such a variety of possible tracers, it is important to identify which tracer(s) are (a) economically viable, (b) can be measured appropriately, (c) fit with the specifics of the geological site, and (d) meet the concerns of the public. Tracers can be used either in a continuous mix with the whole body of sequestered gas as an ownership label or in a pulse to monitor changes in the reservoir characteristics of the body of rock hosting the sequestered gas. Rather than going to the expense of adding a tracer to the stream of sequestered CO2 there may be the opportunity to use natural tracers, such as the very CO2 being injected. In the Weyburn Project, the CO2 injected was isotopically distinct from any CO2 that might have been present in the geological system to which it was being added. The CO2 piped from a gasification plant in North Dakota had an isotopic signature quite depleted in 13C (approx. ?13C -20 to -30?; ref Hirsche et al., 2004). This contrasted with the carbonate minerals and any CO2 present in the hydrocarbon reservoir to which the gas was being sequestered as part of an enhanced oil recovery (EOR) project. Unfortunately, the sequestered CO2 may not be as isotopically different as background sources, for example separating CO2 from natural gas prior to re-injection in the same formation. Costs of tracers per litre can range in orders of magnitude; however the cost should be measured as amount per metric tonne CO2 in order to obtain the true cost. Amounts required tend to be controlled by the background atmospheric presence of any tracer and by the sampling methods and locations. For example, the amount of tracer used to monitor subsurface movement of CO2 from an injection to a monitoring well would potentially be very low if that tracer is not present in deep saline aquifers. However, if shallow water bores or soil or atmospheric level measurements are also being taken, then the presence of the tracer in the soil or atmosphere will strongly control how much additional tracer is required to see changes above background. Addition of 14CO2 to sequestered CO2 may be regarded as a cost effective tracer that will closely mimic CO2. However, it will not advance ahead of the sequestered CO2, it will mask natural differences in 13C/14C variations in the soil and atmosphere, and of course is radiogenic and therefore less favored by the public. By contrast, SF6 (sulphur hexafluoride) is also inexpensive, and has been used in a variety of tracer experiments (Tingey et al., 2000 and references therein). However, SF6 is required in larger volumes (engineering issue for mixing), is increasing in presence in the atmosphere (Maiss and Brenninkmeijer, 1998) and is a highly potent greenhouse gas. As an example of its global warming potential (GWP), 5500 tonnes SF6 is the equivalent of releasing 132 million tons of CO2 (Maiss and Brenninkmeijer, 1998).

Increasing CO2 emissions resulting from the expansion of coal fired power generation capacity and other industry in Queensland suggests that a long-term high capacity storage solution is needed. Despite some relatively large distances (upwards of 500 km) between sources and sinks, a review of the Galilee Basin suggests that it may have the potential to sequester a significant amount of Queensland's stationary CO2 emissions, however a paucity of data in several significant regions do not allow this potential to be fully assessed at the present time. Sandstones with good porosity and permeability characteristics occur within several formations including the Early Permian Aramac Coal Measures, the Late Permian Colinlea Sandstone and the Triassic Clematis Sandstone. Intraformational and local seals as well as a regional seal, the Triassic Moolayember Formation and the Permian Bandanna Formation, appear sufficient although these have not been tested. Stratigraphic and residual/solution trapping are the most likely CO2 storage mechanisms, as low amplitude structures are a feature of the Galilee Basin. Most of the structures targeted by exploration companies are generally too small to store CO2 in the quantities anticipated to be emitted from potential emission nodes such as the Rockhampton-Gladstone region. Regional reconnaissance indicate small 15-20 km2 structures with a 50-125 m net sandstone section are typical for the Clematis Sandstone Formation in the south eastern area of the Galilee Basin. Covering an area of approximately 247,000 km2 and measuring around 700km north-south and 520 east-west, the Galilee Basin is a significant feature of central Queensland. Three main depocentres the Koburra Trough (east), the Lovelle Depression (west) and the Southern Galilee Basin (south) contain several hundred metres of Late Carboniferous to Middle Triassic sediments (up to 3000m, 730m, and 1400m respectively). Most of the low amplitude structures in the basin, generally trending north-easterly to north-westerly, are the result of reactivation of older basement structures in the underlying Drummond and Adavale Basins. Tectonic events were dominantly compressional resulting in uplift and erosion of parts of the basin during the Late Permian and Triassic. A regional south-westerly tilt was later imposed due to downwarping of the overlying Eromanga Basin, which is up to 1200 m thick over the Galilee strata. Sedimentation in the Galilee Basin was dominated by fluvial to lacustrine (and in part glacial) depositional systems. This resulted in a sequence of sandstones, mudstones, siltstones, coals and minor tuff in what was a relatively shallow intracratonic basin. The entire Galilee sequence is saturated with good to excellent quality fresh water in both the Permian and Triassic strata (Hawkins, unpublished) with probable recharge from the north-east into the outcropping Triassic reservoirs. Sediment composition is mixed as a result of a variety of provenances including older sedimentary rock, metasediments and other metamorphic rocks, granites, volcanics and direct volcanic input (tuffs). Climate varied from glacial to warm and humid to temperate. Forty years or more of exploration in the Galilee Basin has failed to discover any economic accumulations of hydrocarbons, despite the presence of apparently good to very good reservoirs and seals in both the Permian and Triassic sequence. Further geological study and in particular the interpretation of seismic data is required to increase the understanding and assess the quality of the basin for CO2 storage including; fully assessing reservoirs, seals and trapping mechanisms; estimating storage capacity; and addressing issues such as the presence of a potentially large fresh water resource.

This report is part of the results of a study into the potential for the geological storage of carbon dioxide within the Triassic Formations of the Galilee Basin in central Queensland carried out in Geoscience Australia on behalf of the CO2CRC. A review of the geological potential of the area has been issued as a separate report (Marsh et al., 2008) and this document describes the construction of a static geological model of one of the potential reservoirs in one area of the basin, while the results of a preliminary dynamic simulation study based on this model will be presented in a separate report by the reservoir engineer Yildiray Cinar of UNSW.

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.

Sampling, prior to CO2 injection at the CO2CRC Otway Project, southeastern Victoria at the end of 2007 early 2008, provided a stocktake of the molecular and isotopic (carbon and hydrogen) compositions of the subsurface hydrocarbon and non-hydrocarbon gases (and heavier hydrocarbons) at, and in close proximity to, the injection site. This baseline study is also fundamental to the assessment of present sub-surface petroleum components as natural tracers for injected gases arriving at the monitoring well. The CO2CRC Otway Project will use the CO2-rich natural gas (containing 79% CO2 and 20% methane) from the Buttress-1 well; totalling 100,000 tons of gas injected over 2 years. This gas mixture will be injected supercritically into sandstones of the CRC-1 well below the original gas-water contact at ~2000 m in the Waarre Formation. The depleted natural gas well at Naylor-1 is the monitoring well, situated 300 m updip of the injection well. Gas from the Waarre Formation in Naylor-1 observation well contains <1% CO2, which is isotopically depleted in 13C (13C -15.8) by 9 compared to CO2 (13C -6.8) in Buttress-1. Thus the carbon isotopes of CO2 can act as a primary natural tracer for monitoring purposes. Isotopically, the minimum detection limit would result from an increase of ~20 % in the CO2 concentration at Naylor-1 from the Buttress-derived CO2. On the other hand, the carbon and hydrogen isotopes of methane, wet gases and higher hydrocarbons are very similar between Buttress-1, CRC-1 and Naylor-1, requiring addition of external conservative tracers (Boreham et al., 2007) for the monitoring of hydrocarbon components. Although the content of liquid hydrocarbons in the gases is very low (<1%), there is the potential for supercritical CO2 extraction of these high molecular weight components (e.g. black oil in the Caroline-1 CO2 gas field and solid wax at the Boggy Creek CO2 production plant) that can be either advantageous (lubrication) or detrimental (clogging) to monitoring equipment at Naylor-1. The CRC-1 well provided an opportunity to collect downhole mud gases over many formations. Maximum total hydrocarbon concentration of 0.97 % occurred in the Waarre Formation Unit C. Surprisingly, a free gas zone in the overlying Flaxmans Formation had a lower maximum concentration (0.17 %). Carbon isotopes for the hydrocarbon gases from 1907 to 2249 mRT showed little downhole variation, while the 13C CO2 averaged -16, identical to CO2 at Naylor-1. Interestingly, the condensate recovered from a MDT in the Flaxmans Formation showed depletions in 13C for the C11 to C20 n-alkanes of up to 6 for n-C15 compared to n-alkanes of oils and condensates sourced from the Eumeralla Formation of the eastern Otway Basin (Boreham et al., 2004). Water washing is suspected at CRC-1 but is not expected to be a major factor affecting hydrocarbon compositions in the short term. The results of this subsurface petroleum audit have been pivotal in demonstrating the need for the addition of external tracers, especially for the hydrocarbon components, and provide an integral part of the near-surface, soil gas and atmospheric monitoring activities of the CO2CRC Otway Project. References Boreham, C.J., Hope, J.M., Jackson, P., Davenport, R., Earl, K.L., Edwards, D.S., Logan, G.A., Krassay, A.A., 2004. Gas-oil-source correlations in the Otway Basin, southern Australia. In: Boult, P.J., Johns, D.R., Lang, S.C. (Eds.), Eastern Australasian Basins Symposium II, Petroleum Exploration Society of Australia, Special Publication, pp. 603-627. Boreham, C.J., Underschultz, J., Stalker, L., Freifeld, B., Volk, H., Perkins, E., 2007. Perdeuterated methane as a novel tracer in CO2 geosequestration. In: Farrimond, P. et al. (Eds.), The 23rd International Meeting on Organic Geochemistry, Torquay, England 9th-14th September 2007, Book of Abstracts, 713-714.

Between 2009 and 2012, Australia and China successfully completed the first phase of a bilateral project that aimed to build capacity in the area of geological storage of carbon dioxide among Chinese researchers, students, policy makers and professionals from academia, government and industry. This paper details the activities and results of the International CCS CAGS project, Phase I.

This publication is the successor to Oil and Gas Resources of Australia 2004 and continues as the definitive reference on exploration, development and production of Australia's petroleum resources. OGRA 2005 provides the background for much of the advice on petroleum resources given to the Australian Government. The data are presented in categories that will allow the user to rapidly access specific data they are after. The categories are: - Well data - Seismic Data - Discoveries - Reserves - Production and Development - Expenditure - Titles - Coalbed Methane

Assessment and Sensitivity Considerations of a Potential Storage Site for Carbon Dioxide A Queensland Case Study Sayers, J.1, Marsh, C.1, Scott, A.1, Cinar, Y.2, Bradshaw, J.1, Hennig, A.3, Barclay, S.4 and Daniel, R.5 Cooperative Research Centre for Greenhouse Gas Technologies 1 Geoscience Australia, GPO Box 378, Canberra ACT 2601, Australia 2 School of Petroleum Engineering, University of New South Wales, Sydney NSW 2052, Australia 3 Commonwealth Scientific and Industrial Research Organisation (CSIRO) Petroleum, PO Box 1130, Bentley, WA 6102, Australia 4 Commonwealth Scientific and Industrial Research Organisation (CSIRO) Petroleum, PO Box 136, North Ryde, NSW 1670, Australia 5 Australian School of Petroleum, Santos Petroleum Engineering Building, University of Adelaide, SA 5005, Australia ABSTRACT Australia's coal-fired power plants produce about 70% of the nation's total installed electricity generation capacity and emit about 190 million tonnes of CO2/year, of which about 44 million tonnes come from central and southeast Queensland. A multi-disciplinary study has identified the onshore Bowen Basin as having potential for geological storage of CO2. Storage potential has been documented within a 295 km2 area on the eastern flank of the Wunger Ridge using a simplified regional 3-D model, and is based on estimating injection rates of 1.2 million tonnes CO2/year for 25 years. Paleogeographic interpretations of the Showgrounds Sandstone reservoir in the targeted injection area indicate a dominantly meandering channel system that grades downdip into a deltaic system. Seismic interpretation indicates a relatively unfaulted seal and reservoir section. The depth to the reservoir extends to 2700 m. CO2 injection simulations indicate that at least one horizontal or two vertical wells would be required to inject at the proposed rate into homogeneous reservoirs with a thickness of approximately 5 m and permeability of 1 darcy. The existence of intra-reservoir shale baffles necessitates additional wells to maintain the necessary injection rate: this is also true for medium-permeability reservoirs. The long-term storage of the injected CO2 involves either stratigraphic and residual gas trapping along a 10 to 15 km migration path, and ultimately, potentially, within updip depleted hydrocarbon fields; or trapping in medium-permeability rocks. Trapping success will be a function of optimal reservoir characteristics including specific permeability ranges and the distribution of seals and baffles. Sensitivity analysis of CO2 injectivity indicates that dissolution effects may increase injection rates by up to 20 %.