GA contribution to CO2CRC. Report describes the work done to create a PETREL model of the Naylor Field proposed injection reservoir; eighteen appendicies.

The Australian Cooperative Research Centre for Greenhouse Gas Technologies (CO2CRC) is planning a pilot project to inject, store, and monitor carbon dioxide in a depleted gas field (Naylor Field) in the Otway Basin, Victoria, in Southeast Australia. Approximately 100,000 tonnes of CO2 are planned to be injected over a 2 year period in a new well to be located down dip of the existing crestal well. An accurate and detailed geological assessment and characterization is essential to the selection/evaluation of any potential carbon storage site, as this provides the inputs for the reservoir models that are needed to design the monitoring and verification programs. For the proposed Otway Basin Pilot Project, the stratigraphy and structure of the Early Cretaceous Waarre Formation in the Port Campbell Embayment has been studied. Detailed geological models for reservoir simulation have been established based on geological, geophysical and history matching studies. Particular emphasis has been placed on the Early Cretaceous Waarre Formation (the main regional and proposed injection reservoir) in the Naylor Field. Uncertainties in the geological model (based on good 3D seismic but poor well data) will be ultimately minimized through the drilling and logging of a new well and the re-logging of the existing well. Prior to this, there is a need to understand the geological uncertainties as they stand, so that an effective well location and well testing program can be defined. Based on limited palynological control (from neighboring wells) the Waarre Formation is not notably time transgressive within the study area; beyond this only a broad breakdown is possible. The Waarre Formation is divisible into units A, B, C and D, A being the oldest. Only the Waarre C reservoir unit is of immediate interest. From regional work it is interpreted that the top of unit B is associated with minor erosion and incision, prior to the onset of significant growth faulting associated with continental breakup. Initial Waarre C deposition is sandy incised valley fill deposits on this eroded surface. The configuration of these basal Waarre C deposits has been seismically mapped. Core interpretation establishes that subsequent Waarre C deposition occurred on a sandy low sinuosity fluvial braid plain. study area; although there are indications that the upper Waarre C was partially eroded prior to transgression of the overlying marine Waarre D unit. The Waarre C section is characterized by clean high permeability sandstones, interpreted as abandoned channel fill ~2m thick, within which there are thin shales. These shales form the only significant flow barriers within this upper unit; and appear to comprise less than 10% of the section, but mapping their distribution is difficult. Several PETREL reservoir models were created to capture the uncertainty and potential reservoir heterogeneity of the Waarre C in the Naylor Field; key parameters (for example: porosity, permeability, channel orientation, shale content, connectivity, and gradient of the top structure) have been systematically varied to provide the most likely and extreme cases for the subsequent reservoir simulation studies. The reservoir properties have been characterized through history matching of the well-head pressure and water-cut data over the 18-month production history of the well using systematic numerical simulation approaches. The results indicate that the reservoir has an average permeability of 500-1000 mD, the original gas-water contact was at 2020 meters depth and that there was a significant aquifer support to the reservoir. This reservoir characterization and history matching study has provided additional and essential knowledge of the field and helped to constrain the injection location. The study establishes a sensible current reservoir condition, which will subsequently be used as the initial condition in the simulation of CO2 injection in the depleted gas field.

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

This report details the suitability of two identified sites in the Browse Basin for the geological storage of carbon dioxide: the Carbine Ponded Turbidite and the Leveque Shelf long migration dissolution trap. Detailed site assessments were completed by undertaking detailed geophysical interpretation of the top and base of each site, combined with a comprehensive structural, stratigraphic and sedimentological analysis, in order to construct a series of static 3D reservoir models for each potential storage site. These were submitted for CO2 injection simulation in order to better estimate the potential storage capacity, the potential injectivity volumes, and identify any containment-related issues of each site. Therefore this reports aims to provide technical recommendations regarding the viability of the long-term geological storage of CO2 in the Browse Basin.

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.

Between 3 May 2012 to 24 June 2012 Geoscience Australia undertook two major surveys off the coast of the Northern Territory in the Petrel Sub-Basin. The data acquisition was funded through the National Low Emissions Coal Initiative (NLECI) and the Petrel Sub-basin was selected in particular as it has been identified as a prospective area for CO2 storage. These surveys collected a range of data, including industry standard high resolution seismic reflection data, multibeam data and sub-bottom profiler data. This data is available for purchase as raw or final products. PETREL SUB-BASIN C02 DATA PACKAGE CONTENTS: GA336 2D seismic reflection data - 4091 line kilometres GA336 Velocities, navigation, processing and acquisition reports GA336 Multibeam data - 8000 line kilometres GA335 2D 24-ch sub-bottom profiler data - 655 line kilometres GA335 Multibeam and backscatter data - 5300 line kilometres GA335 Underwater videography at 11 stations GA335 Biological, sedimentological and geochemistry analyses for 15 stations GA335 Post survey report

Underground gas storage (UGS) facilities provide a wealth of information, which can be used to better understand various aspects of CO2 storage in depleted reservoirs. In some cases UGS facilities can provide important site specific information for carbon storage projects that are planned in similar formations in close proximity. In this paper, we discuss the various ways in which UGS facilities can be used to extract important information, and when possible we draw upon information from the Iona gas storage facility in Australia's Otway basin. The Iona facility is located 20 km away from the CO2CRC Otway Project, in which CO2 65445 tonnes of 77 mole% carbon dioxide, 20 mole% methane and 3 mole% other gas components (containing about 58000 tonnes of carbon dioxide) was injected into the Waarre C formation over a 17 month period. In this paper, we compare the factors that control CO2 seal capacity and discuss how UGS facilities can provide information on sustainable column heights either limited by faults or by cap rocks. We also present dynamic modeling results in which information is gained regarding injectivity, pressure evolution of the reservoir, storage capacity and maximum fluid pressures sustained by the faults. Understanding such parameters is important for the safe operation of any carbon storage project, be it on a demonstration or industrial scale.

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.

Geoscience Australia (GA) conducted a marine survey (GA0345/GA0346/TAN1411) of the north-eastern Browse Basin (Caswell Sub-basin) between 9 October and 9 November 2014 to acquire seabed and shallow geological information 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 survey was conducted in three legs aboard the New Zealand research vessel RV Tangaroa, and included scientists and technical staff from GA, the NZ National Institute of Water and Atmospheric Research Ltd. (NIWA) and Fugro Survey Pty Ltd. Shipboard data (survey ID GA0345) collected included multibeam sonar bathymetry and backscatter over 12 areas (A1, A2, A3, A4, A6b, A7, A8, B1, C1, C2b, F1, M1) totalling 455 km2 in water depths ranging from 90 - 430 m, and 611 km of sub-bottom profile lines. Seabed samples were collected from 48 stations and included 99 Smith-McIntyre grabs and 41 piston cores. An Autonomous Underwater Vehicle (AUV) (survey ID GA0346) collected higher-resolution multibeam sonar bathymetry and backscatter data, totalling 7.7 km2, along with 71 line km of side scan sonar, underwater camera and sub-bottom profile data. Twenty two Remotely Operated Vehicle (ROV) missions collected 31 hours of underwater video, 657 still images, eight grabs and one core. This catalogue entry refers to standard Geotek multi-sensor core logger data from piston cores collected on the survey. Please follow link to manual for further information.

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".