This report provides an analysis and evaluation of fluid seepage and habitats in two targeted areas of the Petrel Sub-basin, Bonaparte Basin, northern Australia, and provides scientific information on the seabed and shallow sub-surface geology as part of a study on the potential of this area for CO2 sequestration. The Petrel Sub-basin, located beneath the modern Joseph Bonaparte Gulf, has been assessed by Geoscience Australia as part of the Australian Government funded National Low Emissions Coal Initiative (NLECI) to accelerate the development and deployment of low emissions coal technologies including geological sequestration of CO2. This study is the first undertaken by Geoscience Australia that integrates seafloor and shallow sub-surface geology data to provide information on the potential to sequester CO2 in sub-surface geological reservoirs and their suitability for purpose. In particular, this work involved the integration of data from seabed habitat characterisation studies and sub-surface geological studies to determine if evidence for fluid seepage from depth to the seabed exists at the two study sites within the Petrel Sub-basin. No evidence for hydrocarbons from depth were found. However, fluid seepage at the seabed has been and potentially is occurring; this result stemming from observations on seabe geomorphology, sedimentology, chemistry, and acoustic sub-bottom profiles.

As part of Australian Government's National Low Emission Coal Initiative (NLECI) and National CO2 Infrastructure Plan (NCIP), Geoscience Australia (GA) has been assessing offshore sedimentary basins for their CO2 storage potential. These studies, scheduled for completion by 30 June 2015, aim to identify potential sites for the geological storage of CO2 and provide pre-competitive information for the development of CO2 transport and storage infrastructure near major emission sources. The basins targeted for these studies are the Bonaparte Basin (Petrel Sub-basin), Browse Basin, Perth Basin (Vlaming Sub-basin) and Gippsland Basin. GA completed a series of marine surveys over the Petrel and Vlaming sub-basins and the Browse Basin during 2012-2013, that acquired 2D reflection seismic, multibeam bathymetry/backscatter and sub-bottom profiling data, and seabed samples and video footages. The datasets have been analysed to inform the assessment of potential CO2 storage capacity and containment for each study area. Integrated interpretation of the seabed, shallow subsurface and deep basin data has assisted the identification of potential fluid migration features that may indicate seal breach and the presence of migration pathways. Data on seabed environments and ecological habitats will provide a baseline for an assessment of the potential impacts of CO2 injection and storage, and associated infrastructure development.

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.

The decision at the 2011 United Nations climate change meeting in Durban to accept CCS as a CDM project activity was truly historic and long overdue. The United Nations Clean Development Mechanism (CDM) allows emission reduction projects in developing countries to earn certified emission reduction (CER) credits, each equivalent to one tonne of CO2. CERs can be traded and sold, and used by developed countries to meet part of their emission reduction targets under the Kyoto Protocol. The intention of the mechanism is to stimulate sustainable development and emission reductions, while providing developed countries with some flexibility in how they achieve their emission reduction targets. The CDM allows developed countries to invest in emission reductions at lowest cost. Since its inception, the CDM has been identified as a means to reduce the cost of CCS projects and so initiate more projects. After five years of negotiations to get CCS accepted as a CDM project activity, the Cancun Decision (2010) put in place a work program to address issues of general concern before CCS could be included in the CDM. The 2010 work program consisted of submissions, a synthesis report, a technical workshop, and concluded with the UNFCCC Secretariat producing draft 'modalities and procedures' describing comprehensive requirements for CCS projects within the CDM. This twenty page 'rulebook' provided the basis for negotiations in Durban. The challenging negotiations, lasting over 32 hours, concluded on 9th December, 2012, with Parties agreeing to the text specifying the modalities and procedures for CCS as CDM project activities. The provisions of the Durban Decision (2011) cover a range of technical issues including site selection and characterisation, risk and safety assessment, monitoring, liabilities, verification and certification, environmental and social impact assessments, responsibilities for non-permanence, and timing of the CDM-project end. etc

The Collaborative Research Centre for Greenhouse Gas Technologies (CO2CRC) Program 3.2 Risk Assessment is working toward a risk assessment procedure that integrates risk across the complete CCS system and can be used to meet the needs of a range of stakeholders. Any particular CCS project will hold the interest of multiple stakeholders who will have varied interests in the type of information and in the level of detail they require. It is unlikely that any single risk assessment tool will be able to provide the full range of outputs required to meet the needs of regulators, the general public and project managers; however, in many cases the data and structure behind the outputs will be the same. In using a suite of tools, a well designed procedure will optimize the interaction between the scientists, engineers and other experts contributing to the assessment and will allow for the required information to be presented in a manner appropriate for each stakeholder. Discussions of risk in CCS, even amongst the risk assessment community, often become confused because of the differing emphases on what the risks of interest are. A key question that must be addressed is: 'What questions is the risk analysis trying to answer?' Ultimately, this comes down to the stakeholders, whose interests can be broken into four target questions: - Which part of the capture-transport-storage CCS system? - Which timeline? (project planning, project lifespan, post closure, 1,000 years, etc) - Which risk aspect? (technical, regulatory, economic, public acceptance, or heath safety and environment) - Which risk metric? (Dollars, CO2 lost, dollars/tonne CO2 avoided, etc.) Once the responses to these questions are understood a procedure and suite of tools can be selected that adequately addresses the questions. The key components of the CO2CRC procedure we describe here are: etc

Australia has been making major progress towards early deployment of carbon capture and storage from natural gas processing and power generation sources. This paper will review, from the perspective of a government agency, the current state of various Australian initiatives and the advances in technical knowledge up until the 2010 GHGT conference. In November 2008, the Offshore Petroleum and Greenhouse Gas Storage Bill 2006 was passed by the Australian Parliament and established a legal framework to allow interested parties to explore for and evaluate storage potential in offshore sedimentary basins that lie in Australian Commonwealth waters. As a result of this Act, Australia became the first country in the world, in March 2009, to open exploration acreage for storage of greenhouse gases under a system that closely mirrors the well-established Offshore Petroleum Acreage Release. The ten offshore areas offered for 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. The co-incidence of the 2009 Global Financial Crisis may have reduced the number of prospective CCS projects that were reported to be in the 'pipe-line' and the paper examines the implications of this apparent outcome. The Carbon Storage Taskforce has brought together both Australian governments technical experts to build a detailed assessment of the perceived storage potential of Australia's sedimentary basins. This evaluation has been based on existing data, both on and offshore. A pre-competitive exploration programme has also been compiled to address the identified data gaps and to acquire, with state funding, critical geological data which will be made freely available to encourage industrial participation in the search for commercial storage sites.

Introduction This National Carbon Infrastructure Plan study assesses the suitability of the Vlaming Sub-basin for CO2 storage. The Vlaming Sub-basin is a Mesozoic depocentre within the offshore southern Perth Basin, Western Australia (Figure 1). It is around 23,000 km2 and contains up to 14 km of sediments. The Early Cretaceous Gage Sandstone was deposited in paleo-topographic lows of the Valanginian breakup unconformity and is overlain by the South Perth Shale regional seal. Together, these formations are the most prospective reservoir/seal pair for CO2 storage. The Gage Sandstone reservoir has porosities of 23-30% and permeabilities of 200-1800 mD. It lies mostly from 1000 - 3000 m below the seafloor, which is suitable for injection of supercritical CO2 and makes it an attractive target as a long-term storage reservoir. Methods & datasets To characterise the Gage reservoir, a detailed sequence stratigraphic analysis was conducted integrating 2D seismic interpretation, well log analysis and new biostratigraphic data (MacPhail, 2012). Paleogeographic reconstructions of components of the Gage Lowstand Systems Tract (LST) are based on seismic facies mapping, and well log and seismic interpretations. Results The Gage reservoir is a low stand systems tract that largely coincides with the Gage Sandstone and is defined by the presence of the lower G. mutabilis dinoflagellate zone. A palynological review of 6 wells led to a significant revision, at the local scale, of the Valanginian Unconformity and the extent of the G. mutabilis dinoflagellate zones (MacPhail, 2012). G. mutabilis dinoflagellates were originally deposited in lagoonal (or similar) environments and were subsequently redeposited in a restricted marine environment via mass transport flows. Mapping of the shelf break indicates that the Gage LST was deposited in water depths of >400 m. Intersected in 8 wells, the Gage LST forms part of a sand-rich submarine fan system (Figure 2) that includes channelized turbidites, low stand fan deposits, debris flows (Table 1). This interpretation is broadly consistent with Spring & Newell (1993) and Causebrook (2006). The Gage LST is thickest (up to 360 m) at the mouth of large canyons adjacent to the Badaminna Fault Zone (BFZ) and on the undulating basin plain west of Warnbro 1 (Figure 1). Paleogeographic maps depict the evolution of the submarine fan system (Figure 3). Sediment transport directions feeding the Gage LST are complex. Unit A is sourced from the northern canyon (Figure 3a). Subsequently, Unit B (Figure 3b) derived sediment from multiple directions including incised canyons adjacent to BFZ and E-W oriented canyons eroding into the Badaminna high. These coalesce on an undulating basin plain west of Warnbro 1. Minor additional input for the uppermost Unit C (Figure 3c) is derived from sources near Challenger 1. Summary 1: The Gage LST is an Early Cretaceous submarine fan system that began deposition during the G. mutabilis dinoflagellate zone. It ranges from confined canyon fill to outer fan deposits on an undulating basin plain. 2: The 3 units within the Gage LST show multidirectional sediment sources. The dominant supply is via large canyons running north-south adjacent to the Badaminna Fault Zone. 3: Seismic facies interpretations and palaeogeographic mapping show that the best quality reservoirs for potential CO2 storage are located in the outer fan (Unit C sub-unit 3) and the mounded canyon fill (Unit A). These are more likely to be laterally connected. 4: The defined units and palaeogeographic maps will be used in a regional reservoir model to estimate the storage capacity of the Gage LST reservoir.

This work is a baseline study used to underpin the role of bacteria in the alteration and mineralisation of CO2 during geological storage following its injection into depleted natural gas reservoirs. In doing so it is paramount to first understand and characterise natural deep-earth biological systems. Here we report the molecular and isotopic signatures of gas, oil and formation waters from the biodegraded Tubridgi gas field. The onshore Tubridgi gas field is thought to lie at the end of a fill-spill chain from the offshore major oil and gas accumulations in the southern Barrow Sub-basin. An initial oil column at Tubridgi has been subsequently displaced by later gas charges. The Tubridgi gas is very dry (%methane/%ethane ~ 1000). Methane is isotopically light (delta13C = -49.2) and is depleted in 13C by ~10 compared to non-biodegraded gases from the Barrow Sub-basin. This, together with an isotopically heavy CO2 (delat13C = +1.8; ~6 enriched in 13C compared to non-biodegraded gas), suggests a major biogenic methane input derived from anaerobic methanogenic bacteria. The carbon isotopic composition of ethane (delta13C = -27) is only slightly enriched in 13C compared to non-biodegraded gas. Much larger enrichments occur in the hydrogen isotopes of ethane (deltaD = +42; ~180 enriched in D compared to non-biodegraded gas), suggesting anaerobic biodegradation has completely removed the higher (C3-C5) wet gases. This is supported by the less severely biodegraded Barrow Sub-basin natural gases, which can show up to 17 and 225 enrichment in 13C and D of propane, respectively, compared to non-biodegraded Barrow gas. Interestingly, the strong biogenic methane input seen in the carbon isotopes is not expressed in the hydrogen isotopes of methane (deltaD = -177 ), which is similar to the non-biodegraded gas. The Tubridgi-2 residual biodegraded heavy oil has a low API gravity of 23.5o and is the most sulphur-rich oil (S= 1.14 %) of all Australian oils. The gas-chromatogram displays an unresolved complex mixture with no n-alkanes. The level of biodegradation is heavy with 25-norhopane being present but no alteration of the sterane distributions are observed. The biomarker distribution of the Tubridgi-2 oil implies derivation from Late Triassic Middle Jurassic calcareous-influenced source rock deposited in a sub-oxic marine environment. Organic material extracted from the Tubridgi formation waters associated with the biodegraded gases mainly reflect the biodegraded oil input since very little low molecular weight `organics' was detected. Thus, the neutral organic compounds extracted at pH 7 are dominated by a homologous series of C19-C30 n-alkanes, while organic compounds extracted from acidified (pH 1) waters include a homologous series of C8-C18 n-alkylmonocarboxylic acids. The mutual exclusion between carbon numbers of the n-alkanes and n-alkylcarboxylic acids suggests a precursor-product relationship mediated by bacteria. However, the major organic components in the "acid" fraction are unidentified N and O containing compounds, most likely metabolic by-products of the biological activity. Cell counting is in progress, which will give an independent measure of the diversity and activity of the biological community within the reservoir.

Geoscience Australia conducted a marine seismic survey (GA-0352) over poorly defined areas of the Gippsland Basin between 5th of April to the 24th of April 2015. The aim was to acquire industry-standard precompetitive 2D seismic data, Multi-beam echo-sounder (MBES) and sub-bottom profiling (SBP) data to support an assessment of the CO2 storage potential of the basin. The survey, undertaken as part of the Department of Industry and Science's National CO2 Infrastructure Plan (NCIP), aimed to identify and characterise indicators of natural hydrocarbon or fluid seepage that may indicate compromised seal integrity in the region. The data collected during this survey will enhance sequence stratigraphic studies in the Gippsland Basin that provide constraints on the most suitable areas for storage of CO2 and help to identify potential CO2 storage reservoirs. The survey was conducted by Gardline CGG vessel MV Duke The data collected during the survey are available for free download from the Geoscience Australia website. This dataset include all the bathymetry data collected during the survey.<p><p>This dataset is not to be used for navigational purposes.

Geological Storage Potential of CO2 & Source to Sink Matching Matching of CO2 sources with CO2 storage opportunities (known as source to sink matching), requires identification of the optimal locations for both the emission source and storage site for CO2 emissions. The choice of optimal sites is a complex process and can not be solely based on the best technical site for storage, but requires a detailed assessment of source issues, transport links and integration with economic and environmental factors. Many assessments of storage capacity of CO2 in geological formations have been made at a regional or global level. The level of detail and assessment methods vary substantially, from detailed attempts to count the actual storage volume at a basinal or prospect level, to more simplistic and ?broad brush? approaches that try to estimate the potential worldwide (Bradshaw et al, 2003). At the worldwide level, estimates of the CO2 storage potential are often quoted as ?very large? with ranges for the estimates in the order of 100?s to 10,000?s Gt of CO2 (Beecy and Kuuskra, 2001; Bruant et al, 2002; Bradshaw et al 2003). Identifying a large global capacity to store CO2 is only a part of the solution to the CO2 storage problem. If the large storage capacity can not be accessed because it is too distant from the source, or is associated with large technical uncertainty, then it may not be possible to reliably predict that it would ever be of value when making assessments. To ascertain whether any potential storage capacity could ever be actually utilised requires analysis of numerous other factors. 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. Over 100 potential Environmentally Sustainable Sites for CO2 Injection (ESSCIs) were assessed by applying a deterministic risk assessment (Bradshaw et al, 2002). At a regional scale Australia has a risked capacity for CO2 storage potential in excess of 1600 years of current annual total net emissions. However, this estimate does not incorporate the various factors that are required in source to sink matching. If these factors are included, and an assumption is made that some economic imperative will apply to encourage geological storage of CO2, then a more realistic analysis can be derived. In such a case, Australia may have the potential to store a maximum of 25% of our total annual net emissions, or approximately 100 - 115 Mt CO2 per year.