Northern Territory Low Emissions Carbon Capture Storage and Utilisation Hub Concept Specification/Statement of Requirement Đ Task 6 Report Bahman Joodi, Andrew Ross, Jody Rogers, Ryan Gee, Indiana Squiers December 2024 CSIRO Energy Citation Joodi, B., Ross, A., Rogers, J., Gee, R., Squiers, I (2024) Northern Territory Low Emissions Carbon Capture Storage and Utilisation Hub, Concept Specification/Statement of Requirement Đ Task 6 Report. CSIRO report number EP2024-6158, pp 90. CSIRO, Australia. Copyright Š Commonwealth Scientific and Industrial Research Organisation 2024. To the extent permitted by law, all rights are reserved and no part of this publication covered by copyright may be reproduced or copied in any form or by any means except with the written permission of CSIRO. Important disclaimer CSIRO advises that the information contained in this publication comprises general statements based on scientific research. The reader is advised and needs to be aware that such information may be incomplete or unable to be used in any specific situation. No reliance or actions must therefore be made on that information without seeking prior expert professional, scientific and technical advice. To the extent permitted by law, CSIRO (including its employees and consultants) excludes all liability to any person for any consequences, including but not limited to all losses, damages, costs, expenses and any other compensation, arising directly or indirectly from using this publication (in part or in whole) and any information or material contained in it. CSIRO is committed to providing web accessible content wherever possible. If you are having difficulties with accessing this document, please contact csiro.au/contact. Foreword Transitioning the global energy system while rapidly reducing emissions to net zero by 2050 is a vast and complex global challenge. Modelling of a range of emissions pathways and decarbonisation scenarios from the Intergovernmental Panel on Climate Change (IEA, 2024), International Energy Agency (IPCC, 2023a) and Net Zero Australia (NZA, 2024) shows that to meet net zero 2050 greenhouse gas emissions targets, a wide range of emissions reduction technologies will be required to decarbonise existing and future industries globally (IPCC, 2023b). These organisations identify that emissions elimination from hard-to-abate and high-emissions industries will require using carbon capture and storage (CCS) alongside other abatement strategies, such as electrification, underpinned by generation from renewable energy sources such as photovoltaics and wind. Globally, there is considerable effort to identify industrial hubs and clusters where common user infrastructure can enable rapid decarbonisation of existing industries and future low-emissions industrial development. Australia has an opportunity to create new low-carbon growth industries and jobs in these areas, but lacks the infrastructure, skills base and business models to realise this. The transition to net zero will have greater impact on regional communities, particularly those reliant on industries in transition, but it may also create economic opportunities through a wide range of new industries and jobs suited to regional areas. The Commonwealth Scientific and Industrial Research Organisation (CSIRO) is working to identify decarbonisation and transition pathways for existing and potential future industries that may be established in the Northern Territory by developing a Low Emissions Hub concept in the Darwin region. CSIRO has established a portfolio of projects to explore and evaluate a range of emissions reduction and emerging transition technologies and approaches. This includes research into Northern Territory renewable energy potential, hydrogen demand generation and storage, and carbon capture utilisation and storage (CCUS). CSIRO is working collaboratively with industry and government to understand their needs, drivers and strategic directions so that our research is informed and relevant. This includes establishing appropriate pathways and partnerships to understand and incorporate the perspectives of First Nations peoples. A key activity is the research into a business case project (CSIRO, 2024); (Ross et al., 2022) that aims to enhance understanding of the viability of a CCUS hub centred on the Middle Arm of Darwin Harbour. The work has three elements comprising 15 tasks: 1. analysing macroeconomic drivers, Northern Territory and regional emissions, low-emissions product markets (Ross et al., 2023a), identifying key learnings from other low-emissions hubs being developed globally, and cross-sector coupling opportunities (Tasks 0?5) 2. completing CCUS hub technical definition and technical risk reduction studies, including detailed studies on the infrastructure requirements for a CCUS hub, renewable power requirements for existing and potential future industries, and road-mapping for CO2 utilisation industries that could be established to produce low or net zero products (e.g. zero-emission chemical feedstocks) (CSIRO, 2023) (Tasks 6?9) 3. creating a business case to appreciate the scale of investment required to develop a Low Emissions Hub and the economic returns from doing so; this will lead to suggested business models and routes of execution (Tasks 10?14). The CCUS business case project will involve research that is based on possible industrial development scenarios, models of future potential emissions, market demand, technologies and costs. The project is intended to provide an understanding of possible future outcomes. Industry development will be determined by individual industry proponent investment decisions, government policies and regulations, and the development trajectories of technologies essential to the energy and emissions transition. On completion of this research, outcomes of the CCUS business case project will be made publicly available. The work summarised in this report comprises Task 6 of the Northern Territory CCUS business case project. It provides an understanding of the concept-level design for the CCUS hub that includes the infrastructure elements within the Middle Arm Sustainable Development Precinct (MASDP), CO2 import facilities, pipeline systems and storage locations. Much of the reportŐs contents are drawn from Northern Territory Government and industry data provided to CSIRO, with further additional work undertaken by CSIRO. The report provides only a concept-level understanding of a possible CCUS hub ? further, more detailed studies are required to provide a better understanding of the final makeup of the hub. Contents Abbreviations ix Summary xi 1 Introduction 1 2 Northern Territory CCUS hub 4 2.1 Codes and standards 5 2.2 Chemical specification 7 3 MASDP CCUS system design 10 3.1 MASDP industry capture and conditioning 10 3.2 MASDP CCUS pipeline network 14 3.3 LCO2 receiving and storage terminal 20 4 Integration with CO2 export pipelines 37 5 CO2 storage locations 39 5.1 Bayu-Undan reservoirs 40 5.2 Petrel sub-basin 42 6 CCUS system: indicative cost estimates 47 6.1 CCUS system capital cost estimate 47 6.2 LCO2 receiving and storage terminal capital cost estimate 51 6.3 Operating cost estimate 52 6.4 Proportional breakdown of costs 53 6.5 Development cost phasing 55 7 Conclusions 57 References 59 Figures Figure 1: The NT CCUS hub. xiii Figure 2: Phased MASDP CCUS hub development capital cost options. xviii Figure 3: The Balanced Scenario: potential industries, their inputs and outputs, and typical uses 2 Figure 4: Examples of engineering and infrastructure project development stages 3 Figure 5: Task 0 report (Ross et al., 2023b) NT CCUS hub definition showing the elements of the CCUS hub. 5 Figure 6: Typical proponent compression process flow diagram 12 Figure 7: TEG dehydration process flow diagram 13 Figure 8: Process flow diagram illustrating CO2 export into the collection header 13 Figure 9: The CO2 pipeline network. 14 Figure 10: Dense-phase export compression concept (one of three trains) 17 Figure 11: Gas-phase export compression concept (one of three trains) 18 Figure 12: The MASDP CO2 export pipeline is shown in yellow. The solid yellow line represents the export pipeline from the GHG Wood Group (2023) study and the dotted yellow line indicates the alternative tie-in point for the CO2 export pipeline 19 Figure 13: LCO2 facilities in the MASDP. 21 Figure 14: Notional concept-level process flow diagram for 5 Mtpa LCO2 receiving and storage terminal 30 Figure 15: The proposed route for the high-pressure CO2 export line is shown by the solid magenta line, with an alternative route shown by the magenta dotted line. Alternative option CO2 receiving a storage pipeline to central compression facility shown in light blue. 33 Figure 16: Interface schematic. 38 Figure 17: Related value chain scope 38 Figure 18: Phase envelope for CO2 fluids 39 Figure 19: Schematic showing the relative importance of CO2 trapping mechanisms over time 40 Figure 20: Schematic of Bayu-Undan CCS project 41 Figure 21: Conceptual offshore plan for Bayu-Undan CCS 42 Figure 22: Petrel Sub-basin CO2 storage potential 43 Figure 23: 2021 Greenhouse Gas Permits Acreage Release, Petrel Sub-basin 44 Figure 24: G-7-AP permit location over GHG21-1 45 Figure 25: Bonaparte CCS development schematic 45 Figure 26. GHG21-2 permit location over G-11-AP. 46 Figure 27: Proportional capital cost breakdown for the MASDP CCUS system assuming full Balanced Scenario development, using the base option LCO2 import facility costs 54 Figure 28: Phased MASDP CCUS hub development capital cost options. White hatched area is the compressor cost for the lowest cost option. Note: As these are concept design costs they are subject to significant uncertainty 56 Tables Table 1: A selection of applicable standards Source: adapted from GHG Wood Group (2023) 6 Table 2: Reference composition for the MASDP (blended composition of CO2 stream from MASDP industries), compared with the lower and upper levels for maximum concentrations compared with specifications from other projects 9 Table 3: MASDP industries and emissions categorisation and contribution 11 Table 4: Design parameters for the collection header 15 Table 5: Design parameters for the CO2 export pipeline 19 Table 6: Characteristics of the base case and alternative option for LCO2 import concept design 22 Table 7: LCO2 import composition 23 Table 8: Buffer storage calculations 25 Table 9:Types of storage tanks: pros and cons 27 Table 10: Types of storage tanks: traffic light comparison 28 Table 11: Design pressures and temperatures for LCO2 pipeline 31 Table 12: Design parameters for loading and return lines 31 Table 13: Options investigated for screening exercise 34 Table 14: Design parameters for the base case dense-phase pipeline and alternative low-pressure transfer pipeline 35 Table 15: Characteristics of class 5 cost estimate 47 Table 16: Cost estimate assumptions 47 Table 17: CCUS-related cost estimates for the expected industries in the MASDP 49 Table 18: Summary of the pipeline characteristics and cost estimate 50 Table 19: Summary MASDP CCUS hub compression facility cost estimate 50 Table 20: Characteristics of class 4 cost estimate 51 Table 21: Cost estimate assumptions 51 Table 22. Base-case CapEx estimate for LCO2 import facility. Increase to 6 Mtpa at additional $10 million 51 Table 23. Alternative CO2 vaporisation option (gas export from common user facility) CapEx estimate 52 Table 24: Capital costs of the MASDP CCUS system assuming full Balanced Scenario development 53 Table 25: Operating costs of the MASDP CCUS system assuming full Balanced Scenario development 54 Table 26: Phased MASDP CCUS hub development capital cost options 56 Acknowledgements CSIRO acknowledges the Traditional Owners of the land, sea and waters, of the area that we live and work on across Australia. We acknowledge their continuing connection to their culture, and we pay our respects to their Elders past and present. The authors of this report acknowledge the support and funding provided by CSIRO to undertake this work. We thank the internal CSIRO independent peer reviewers for their review of the report and valuable comments and suggestions. While this report is an output from a CSIRO-funded initiative, we thank our industry and government collaborators for their insights, contributions and suggestions, which have improved the report outcomes. In addition, we would like to thank the Northern Territory Government and INPEX for their contributions of materials and data used in the generation of this report. Although CSIRO has sought feedback from government and industry on the technical content of the report, CSIRO has sole discretion on including such feedback. Northern Territory Low Emissions Carbon Capture Utilisation and Storage Hub business case project The Northern Territory Low Emissions Carbon Capture Utilisation and Storage Hub business case project is a result of a collaborative approach between CSIRO, government and industry to develop a business case to assess the viability of a large-scale low-emissions carbon capture utilisation and storage hub outside Darwin. The project includes inputs from the wider Northern Territory Low Emissions Hub (NT LEH) collaboration group, whose current members include the Northern Territory Government, Xodus, INPEX, Santos, Woodside Energy, Eni, TotalEnergies, Tamboran Resources and SK E&S. Abbreviations ĄC Degrees Celsius AACE Association of Advancement Cost Engineers AGRU acid gas removal unit barg unit of gauge pressure Bcf billion cubic feet CapEx capital expenditure CCS carbon capture and storage CCUS carbon capture utilisation and storage DLNG Darwin LNG DN diameter nominal FEED front-end engineering design FID final investment decision GTL gas to liquid hr hour IEA International Energy Agency ILNG Ichthys LNG IPCC International Panel on Climate Change ISO International Organization for Standardisation km kilometre ktpa Kilotons per annum kWe kilowatt (electrical) LNG liquefied natural gas m metres MASDP Middle Arm Sustainable Development Precinct mm millimetres MOF module offloading facility mol unit of measurement Mtpa million tonnes per annum (106 tonnes per year)Ę Mt million tonnes MW megawatt (106 watts) NT Northern Territory NT LEH Northern Territory Low Emissions Hub NT-DIPL Northern Territory Department of Infrastructure, Planning and Logistics OD outside diameter OpEx operating expense ppmv parts per million volume s seconds SMR steam methane reforming TC technical committee Tcf trillion cubic feet WT weight yr year Chemical compounds Ar argon Cd cadmium CH3CHO acetaldehyde CH4 methane CO carbon monoxide CO2 carbon dioxide H2 hydrogen H2O water H2S hydrogen sulfide HCHO formaldehyde Hg mercury LCO2 liquid carbon dioxide N2 nitrogen NH3 ammonia NOx oxides of nitrogen O2 oxygen SOx (as SO2) oxides of sulfide TI thallium TEG triethylene glycol Summary CCUS hubs are seen as critical in the decarbonisation of hard-to-abate industries and are being pursued by several jurisdictions around the world to assist in the delivery of their decarbonisation strategies. CCUS hubs cannot be developed in isolation, and they are typically considered in conjunction with other emissions reduction approaches, such as sector coupling, renewable electrification, hydrogen and other low-emissions product development (see the Task 1, 5 and 7 reports (Czapla et al., 2024; Green et al., 2024; Rogers et al., 2024). The purpose of this report is to provide a concept-level overview of the components and requirements of a potential Northern Territory Low Emissions Hub (NT LEH). Understanding concept-level designs and requirements aids understanding of the system boundaries, shared infrastructure needs and high-level costs. In developing this report, CSIRO has drawn heavily on work undertaken by the Northern Territory Government, in particular the Northern Territory Department of Infrastructure, Planning and Logistics (NT-DIPL) and two studies commissioned to be undertaken by (GHG Wood Group, 2023; Wood and GHD, 2024). This has been supplemented with work undertaken by INPEX and Santos and publicly available information. Where possible, CSIRO has provided additional inputs to build a more comprehensive understanding of the CCUS hub. These inputs are clearly attributed throughout. There are also elements of the CCUS hub design and costing that CSIRO does not have access to, due to their commercial sensitivity, and these are noted. The concept-level design of a CCUS hub requires an understanding of the inclusions of sources and sinks of CO2, as well as the connective infrastructure. This design assumes the development of the MASDP and uses the NT-DIPL Balanced Scenario, which represents the widest mix of industries anticipated in the MASDP development. The actual industrial mix that is established in the MASDP, and therefore the CCUS demand, may not match the exact composition of industries in the Balanced Scenario, but it offers a way to align with other modelling and design activities that the Northern Territory Government is pursuing, and therefore this scenario has been chosen for the whole of the NT-LEH CCUS business case project. The Task 0 outputs are used here to describe the low-emissions hub Ôsystem boundariesŐ and provide a framework for subsequent sections of the report (Ross et al., 2023b). At a system level, common standards and codes would be used in the hub development, many of which are in use in the industries already situated in the Middle Arm. These standards include limits on the impurities within the CO2 streams to ensure that the CO2 gas stream constituent concentrations are not detrimental to the CCUS hub, equipment, piping and main CO2 exporting pipeline integrity. MASDP CCUS hub system components For each of the industries contemplated within the Balanced Scenario, the maximum volume of CO2 required for transport and storage has been assessed. This assessment identified a maximum projected capacity requirement of around 9.1 Mtpa of CO2 from the industries. CO2 capture for each industry is assumed to occur within its respective facilities, and across the industries it has been estimated that pre-combustion sources will account for 60% of emissions and post-combustion sources for 40%, once the precinct is fully developed. It is assumed that industrial proponents will predominantly use amine capture (used for cost estimations below) but it will ultimately be the decision of the industrial proponents to determine their preferred capture technology. It is important to note that the GHG Wood Group (2023) study does not specify how each capture plant is configured. Understanding the configuration of the capture systems and the relative proportion of each capture system that is an unavoidable cost (i.e. an embedded cost as part of the industrial process) will be key to understanding the complexity in the design and additional sizing of MASDP industry capture systems. Once captured, CO2 will undergo gas conditioning steps to enable its transport within the hub. Each industry will be required to treat and dehydrate its produced CO2 to meet hub CO2 composition specifications. The design also requires each industrial supplier of CO2 to compress its CO2 to provide it at 8.5 barg to a centralised high-pressure compression facility (Figure 1). The compression process was modelled by GHG Wood Group (2023) using a two-stage centrifugal machine, while dehydration was modelled with triethylene glycol (TEG). Following dehydration, the CO2 will undergo final filtration to protect the pipeline against TEG carryover, before continuous online moisture analysis and custody transfer metering. Figure 1: The NT CCUS hub. The MASDP header pipelines are shown in red and blue. The centralised high pressure compression hub is in area G. The MASDP hub CO2 export pipeline is shown in yellow with an alternative export pipeline route shown as a dotted yellow line. Tie-in points into the CO2 interface pipeline are shown as orange circles. The LCO2 receiving and storage terminal location is shown as a purple box within common user facility in area F and associated transfer and export pipelines lines are shown as magenta lines Source: adapted from Wood and GHD (2023) The header pipeline, which will take the CO2 from each industry to the centralised high-pressure compression facility, has western and eastern branches: the western branch will have a pipeline outside diameter (OD) of 800 mm and the eastern branch will have outside diameters of 400 mm and 800 mm, reflective of the CO2 transport capacity requirements of the industries of the MASDP. The design allows flexibility in the development of the header pipeline system for phased development. A medium-pressure design and a high-pressure design were considered for the centralised CO2 compression facility. The preference is for high-pressure export as it enables more efficient integration with the downstream facilities. On arrival at the centralised high-pressure compression facility, CO2 will be compressed to 180 barg using a three-stage compressor. The MASDP compression system is configured into three trains, each rated at 25 MW providing one third of the total capacity. This arrangement allows its phased development. The resultant dense-phase fluid is then pumped into the 600 mm pipeline to be transported ~4 km to the INPEX Access Road Junction tie-in point and the third-party downstream CO2 storage/sequestration system (MASDP CCUS hub battery limit). This tie-in point is one of two possible options, with a second point contemplated in the vicinity of the Ichthys gas pipeline shore-crossing easement close to the Darwin liquefied natural gas (LNG) facility (see section 4). This location is ~7.4 km from the compression facility. Liquid CO2 receiving and storage terminal A liquid CO2 (LCO2) receiving and storage terminal has been defined by Wood and GHD (2024). The inclusion of a CO2 import (and, in principle, export) terminal allows importation of additional CO2 volumes to lower the unit cost of CO2 storage, maximise CCUS system capacities and reduce regional emissions. The LCO2 import terminal was designed to receive CO2, pump it and then export it to the designated tie-in point for downstream export to the CO2 storage/sequestration sites. The LCO2 import terminal is designed to share Berth 3 of the proposed MASDP port facility with ammonia and ethylene export activities (Figure 1). It is assumed that the facility will have at least 346 operational days each year (Wood and GHD (2024) and be able to accept 40,000 m3 to 80,000 m3 ships as the facilityŐs capacity increases. Delivered CO2 is assumed to have a purity level of 99.9%, reflecting the higher specification requirements associated with liquid-phase CO2 conditions at 7 barg and -48ĄC. A key design requirement was the infrastructureŐs flexibility to accommodate an initial processing capacity between 0.5 and 1 Mtpa. The system is designed to expand progressively to 5 Mtpa (or 6 Mtpa) to align with forecast growth in demand. Modelling suggests that an optimal limit for a 40,000 m3 cargo size is 3 Mtpa. This critical consideration has established an initial maximum importation rate of 3 Mtpa as the base case. Future vessel size growth up to 80,000 m3 allows for expansion of the facility to 5?6 Mtpa. For these models, berth utilisation ranges from a minimum of 4% to a maximum of 22%, with offloading taking approximately 12 hours for both 40,000 m3 vessels and, with and upgrade to loading arms, 80,000 m3 vessels. The concept design also focuses on a single expansion phase from 3 Mtpa to 6 Mtpa, rather than multiple smaller brownfield expansions to incrementally boost throughput capacity. The design contemplates CO2 offload in a liquid phase through two lines to the storage tanks located in the CO2 receiving facility. A vapor balance line is required to facilitate the transfer of CO2 gas back to the import vessel, allowing the vessel to completely empty its tanks. Loading operations occur only when the vessel is berthed, making the loading intermittent. Process design of the facility incorporates a keep-cold loop on the import offloading lines and a boil-off-gas recovery system. Onshore buffer storage is a crucial aspect of the design process, as it directly impacts the systemŐs flexibility to respond to fluctuations in vessel arrivals. Sufficient buffer storage mitigates the challenges posed by the arrival of two vessels within a short period of time and reduces vessel demurrage by offering extra capacity for the cargo of the second ship. It was recommended that the buffer storage volume be set at 150% of the cargo size. This storage of LCO2 will occur in the common user facility within the MASDP with the storage facilities expected to cover an area of 6 hectares in the southern section (Figure 1). The common user facility will also handle various hydrocarbons for export, module and material imports, potential bunker fuel storage, and other related activities. As such, it is desirable to design the LCO2 operations to be as simple as possible to minimise brownfield work. The LCO2 storage conditions were assumed to be 7.5 barg, while the design temperature is -60ĄC. The concept design study evaluated three types of storage tanks: Horton spheres, horizontal bullets and vertical cylinders. Horton spheres were selected, as horizontal cylinders have a substantial land footprint and vertical cylinders require extensive interconnected piping and maintenance. The imported LCO2 is expected to be exported in the supercritical or dense phase from the CO2 compression facility through a pipeline to the offshore export pipeline tie-in point (Figure 1). However, alternative options were considered as part of the concept design. Based on the outcomes of this options screening study, a base case option and an alternative option were selected. In the base case, CO2 is exported in a dense phase (150 barg, 5ĄC) directly from the common user facility to the specified tie-in location at the INPEX Access Road Junction via pipeline. The fluid travels from the heaters at the common user facility storage facility through a custody metering skid and into a 4.5 km DN 450 dense-phase pipeline. The alternative option is to transfer the CO2 in a gas phase from the common user facility to a compression and export facility in Area G, where it is compressed and exported in a dense phase to the nominated tie-in location at the INPEX Access Road Junction. In the base case, the treatment process includes pumping the CO2 to the required export pressure of 150 barg and subsequently heating the compressed fluid from its storage temperature to approximately 5ĄC. In this system, a booster pump withdraws LCO2 from storage and raises the pressure from 7 barg to 35 barg. The pressure is then further increased to 150 barg by the export pumps. This two-stage pumping process is essential because the pumping conditions of the liquid are close to its bubble point. The condition of the exported CO2, which is supercritical at 150 barg, will be set by the downstream operator. In the alternative option, the LCO2 is initially pumped to 35 barg and then vaporised into gas at the common user facility. A gas pipeline transports this vaporised CO2 to Area G, where it is compressed to a supercritical state (150 barg) and exported through another pipeline to the nominated tie-in point. In both the base case and the alternative export pipeline options, the pressure of the LCO2 is increased to 35 barg using booster pumps designed as 3 x 50% units. Two pumps are required to transfer 3 Mtpa. These pumps will be equipped with variable-frequency motor drives. Using a single pump, the system capacity can be reduced to 1.5 Mtpa. By reducing the speed of the running pump, it is possible to achieve lower rates. In the base case, variable-speed reciprocating export pumps are responsible for pumping the LCO2 to a supercritical state. Positive-displacement type pumps are selected for exporting the CO2, as there is no correlation between flow rate and pressure in this type of pump, and it can maintain low throughputs. The minimum operational capacity is determined by the performance of the booster pumps, which will be specified in the detailed design stage. It should be noted that no technical showstoppers have been identified for systems within the MASDP precinct in the GHG Wood Group (2023) studies and global examples of each element of the system have been identified to establish the technical and cost bases. Integration of export pipelines The Darwin and Ichthys LNG facilities already capture CO2 as part of the requirement to remove CO2 from the natural gas coming from offshore reservoirs. Upgrade works will occur at these facilities for CO2 gas conditioning (e.g. dehydration of CO2) and compressor installation. It is envisaged that CO2 will be exported from each of these facilities in a dense phase at the required pressure for transport to the offshore storage facilities. The CO2 exported from these facilities is expected to enter a common export pipeline interface, which will permit CO2 to be exported to both the Bayu-Undan depleted field CO2 storage/sequestration site and the Bonaparte CCS saline aquifer storage/sequestration site. The design of this system is currently underway and the pipeline interface system schematic process flow diagram has been provided by INPEX. This interface system includes a tie-in point at the INPEX Access Road Junction, the approximate proposed tie-in location for the LCO2 export terminal pipeline (Figure 1). A Bonaparte CCS tie-in point is envisaged close to the easement associated with the existing Ichthys gas import pipeline. This location provides a pass-through tie-in point for a second MASDP CO2 pipeline associated with CO2 exported from the centralised MASDP compression facility. It is assumed that, without the Bonaparte CCS interface, the pipeline interface system will have sufficient capacity to manage existing and future CO2 volumes from the Darwin and Ichthys LNG facilities and the CO2 import terminal. Additional interface pipeline capacity will be incorporated through the pipeline to Bonaparte CCS. The offshore CO2 export pipeline from the Santos facility is expected to reuse the existing Bayu-Undan natural gas import pipeline and therefore will not require new shore crossings or pipelines. The offshore CO2 export pipeline for the Bonaparte CCS is envisaged to use the same shore crossing easement corridor as the existing Ichthys pipeline, with this new pipeline following the route of the Ichthys pipeline to the offshore storage location in the Petrel Sub-basin. CCUS system indicative costs The indicative costs of the MASDP CCUS system have been developed by the NT-DIPL in its CCUS hub studies (GHG Wood Group (2023) and include estimates of both capital and operating costs. For clarity, the costs represent class 5 cost estimates only, are subject to large uncertainties and require much more detailed study to more accurately define. They do not include estimates of the costs of the Darwin and Ichthys LNG facilities, nor do they include costs for the pipeline interface system or offshore/storage components. However, it can be assumed that these costs will not be insignificant. It is assumed by CSIRO that in the GHG Wood Group (2023) study each industry generates its own products separately. While this approach reduces risk for individual proponents, it does not contemplate efficiencies that may be gained through sector coupling (see the Task 5 report (Czapla et al., 2024)), and therefore the number of emissions locations and the estimated capital infrastructure costs may be conservative if sector coupling can be implemented. The largest component of costs for the CCUS hub development are those associated with capital equipment. When the costs are collated across the base option capture, compression, LCO2 and CO2 export line elements of the CCUS system, they total ~$7.3 billion. More than 70% of these costs are associated with industry capture facility costs and a further 8% are associated with the conditioning and first-stage compression within the battery limits of these facilities. Consolidated operational costs, derived as a proportion of capital costs, are $360?$373 million per year assuming a full Balanced Scenario development, noting that most of these operating costs are associated with the CO2 capture plants. The costs of capture for each industry identified in the GHG Wood Group (2023) study are assumed to be the costs of all capture facilities for each industry. Many of these costs may be unavoidable or embedded process costs for the industries (e.g. pressure swing adsorption/acid gas removal unit [AGRU] separation of CO2 from hydrogen in steam methane reforming [SMR], or the use of AGRU systems in LNG production), whereas in industries such as spodumene processing for lithium hydroxide, CO2 capture would represent an additional cost to normal process operations. This is an important consideration, as the cost of capture is either a cost factored into standard operations or an additional cost to industries. The additional capture costs represent a major uncertainty in understanding the extra costs that would be encountered by industry through the implementation of CCUS in the MASDP. The MASDP header pipelines, compression and CO2 export pipelines represent less than 8% of total costs, and the LCO2 import and export pipeline elements of the system represent 12?13% of the total costs. It is assumed that MASDP developments will not occur simultaneously. As each industry is developed, it will incur the costs associated with its CO2 capture, conditioning and low-pressure compression systems. Phased development of the MASDP will also enable phased development of the associated CCUS header pipeline and compression and export systems. In addition, the costs of the LCO2 receiving and storage terminal can be phased. Figure 2 illustrates the potential phased development options for the MASDP CCUS hub, excluding the costs of industry capture, conditioning and low-pressure compression. The lowest-cost development option contemplates installation of the 800 mm OD header pipeline and one compression train (CSIRO estimates this as 47% of the total costs of the compression facility). This would facilitate compression to the dense phase and transport of up to 3 Mtpa of CO2 at a total estimated cost of $307 million. Where CO2 was not immediately available, these costs could, in principle, be minimised further by installing the header pipelines and completing early work on the compression station without procuring the compressor. Figure 2: Phased MASDP CCUS hub development capital cost options. Note: As these are concept design costs, they are subject to significant uncertainty 1 1 Introduction As discussed in the Task 4 report (Stalker et al., 2024), CCUS hubs are seen as critical in the decarbonisation of hard-to-abate industries and are being pursued by several jurisdictions around the world to assist in the delivery of their decarbonisation strategies. CCUS hubs cannot be developed in isolation ? they are typically considered in conjunction with other emissions reduction approaches, such as sector coupling, renewable electrification, hydrogen and other low-emissions product development (see the Task 1, 5 and 7 reports (Czapla et al., 2024; Green et al., 2024)). Many of the low-emissions hubs under consideration globally are brownfield developments (i.e. developments within and around existing infrastructure and industries). The Northern Territory Low Emissions Hub is part of the MASDP development and as such is ostensibly a greenfield development, meaning that it is a new industrial precinct in which master planning of shared infrastructure can occur from the outset. The NT-DIPL has defined the possible makeup of future industries that could be situated in the MASDP in its Balanced Scenario (this scenario uses the widest range of industries that are envisaged to be established in the MASDP). From this range of industries, CCUS infrastructure demand can be derived. The actual industrial mix that is established in the MASDP, and therefore the CCUS demand, may not match the exact composition of industries in the Balanced Scenario. However, it offers a way to align with other modelling and design activities that the Northern Territory Government is pursuing, and therefore this scenario has been chosen for the whole of the CCUS business case project. The industries included in the Balanced Scenario are shown in Figure 3 and include the production of LNG, hydrogen (from SMR and electrolysis based), methanol, ammonia (one option based on hydrogen production from steam methane reforming, and another on hydrogen production from electrolysis), urea, ethylene, CCUS and critical minerals processing (e.g. lithium, vanadium). In addition to the Balanced Scenario industries, existing LNG industry CCUS infrastructure needs are also considered, as well as incorporation of a CO2 import/export terminal (see the Task 4 and 8 reports (Stalker et al., 2024; Tocock et al., 2024)). Figure 3: The Balanced Scenario: potential industries, their inputs and outputs, and typical uses The purpose of this report is to provide a concept-level overview of the components and requirements of the potential low-emissions CCUS hub. Understanding designs and requirements at the concept level aids in understanding of the system boundaries, shared infrastructure needs and expected development costs. It is worth introducing here where concept-level designs fit within an engineering/infrastructure project development framework. There are many ways of defining a project development framework, some of which are summarised in Figure 4. Typically, at the inception of a project, there is a requirement to define the problem (Dym et al., 2009), develop a technical definition and set a commonly held vision (e.g. Task 0 activities). After the problem has been defined and supported by additional data (including data developed in this business case project), the project moves into the conceptual design or appraisal phase. The project then moves into the preliminary design or concept-selection phase (sometimes called pre-front-end engineering design [pre-FEED]). If the design is deemed viable, the decision is taken to enter the FEED stage. At the end of FEED, final investment decisions are taken that move the project to the execution phase, meaning construction, and ultimately into the operation phase. Thus concept-level design is just the start of a much more intensive series of design steps where risks and costs are evaluated in ever greater detail. As such, the concept-level design illustrated within this report contains significant uncertainties in both the design components and the estimates of the costs involved. Figure 4: Examples of engineering and infrastructure project development stages Source: Xodus In illustrating the concept-level design of the potential low-emissions CCUS hub, the report first develops an understanding of the system-level considerations that will be required in the design and development of the hub. This includes a high-level scan of some of the main design codes and standards that need to be followed in the development of the hub. In addition, there is a discussion of CO2 quality and specification. The report then provides a system overview, followed by a breakdown of the major elements of the CCUS hub and a high-level cost estimation of the MASDP parts of the hub. In developing this report, CSIRO has drawn heavily on work undertaken by the Northern Territory Government, in particular the NT-DIPL and two studies commissioned to be undertaken by GHG Wood Group (2023) and (Wood and GHD, 2024). This has been supplemented with work undertaken by INPEX and Santos and publicly available information. Where possible, CSIRO has provided additional inputs to build a more comprehensive understanding of the CCUS hub. These inputs are clearly attributed throughout. There are also elements of the CCUS hub design and costing that CSIRO does not have access to due to their commercial sensitivity, and these are noted. 2 Northern Territory CCUS hub The concept-level design of a CCUS hub requires an understanding of the inclusions of sources and sinks of CO2 as well as the connecting infrastructure. In Task 0 of the study (Ross et al., 2023b), a technical definition basis and a reference case for the CCUS hub were developed through consultation with government and industry stakeholders. The process was designed to elicit each stakeholder organisationsŐ understanding of opportunity and its vision of success, CCUS hub definition, opportunity statement, value drivers and success factors, commercial showstoppers, technical criteria, decisions required and their hierarchy, stakeholders and engagement required, and risks, challenges and uncertainties. This process also enabled the collaborative development of a Ôtechnical definition basisŐ and a reference case for a CCUS hub that comprises base, near-future and far-future cases (Figure 5). The Task 0 outputs are used here to describe the CCUS hub Ôsystem boundariesŐ and provide the framework for the subsequent sections of this report. The elements of the CCUS hub system include capture of CO2 from MASDP industries (section 3.1) and gathering of that captured CO2 within the MASDP through a pipeline system (section 3.2, Figure 5) to a central compression facility (section 3.2, Figure 5). In addition to the delivery of CO2 from MASDP industries, an importation terminal is also considered within the MASDP boundary (section 3.3, Figure 5). High-pressure CO2 from the MASDP system is exported to the CO2 export pipelines via a shared interconnector system (section 4, Figure 5) where it is combined with high-pressure CO2 from the capture and compression facilities located at the Darwin and Ichthys LNG facilities. CO2 export pipelines in this case consider export to the Bayu-Undan depleted field using repurposed existing pipelines and a new pipeline installation through to one or more saline aquifer storage locations in the Petrel Sub-basin (section 5, Figure 5). Figure 5: Task 0 report (Ross et al., 2023b) NT CCUS hub definition showing the elements of the CCUS hub. The blue outline shows CCUS elements associated with the MASDP. The CO2 transport pipelines are shown as yellow dotted lines and the offshore CO2 storage facilities are represented by platform icons (not representative of actual development strategies). The CO2 hub boxes refer to either compression facilities or pipeline tie-in points. While development of the CCUS hub will occur in phases and across several industrial entities (i.e. it is unlikely to be developed in its entirety by a single operator) the hub requires system-level considerations to enable all parts of the system to operate coherently. These include participants in the hub adhering to a set of common standards and specifications, which are briefly discussed below. 2.1 Codes and standards In the development of a CCUS hub there are many standards and codes applicable to its construction that all proponents would have to adhere to. In many cases these standards and codes are already in widespread use, including in the industries already situated in the Middle Arm. Table 1 provides a list of selected standards that could apply to the CCUS hub. It is not exhaustive, but it does illustrate that through the adoption of standards proponents within the CCUS hub will have a common set of design and development criteria through which to work. The list of standards also illustrates the level of technical understanding required for the safe and successful development of integrated CCUS projects. Development of CCS specific standards The International Organization for Standardisation (ISO) Technical Committee 265 (ISO/TC 265) is responsible for the development of standards for the design, construction, operation, environmental planning and management, risk management, quantification, monitoring and verification, and related activities in the field of CO2 capture, transportation and geological storage (CCS). The South Australian Government Department of Energy and Mining chairs the Standards Australia National Mirror Committee to contribute on the ISO/TC 265 for CCS. Table 1: A selection of applicable standards Source: adapted from GHG Wood Group (2023) Standard body Document number Standard name ABCB NCC National Construction Code AS AS 3000 Wiring Rules AS AS 60079 (ICE 60079) Various hazardous area installation standards AS AS 1210 Pressure vessels Đ design, manufacture, testing, inspection, certification and despatch of fired and unfired pressure vessels AS/NZS AS/NZS 2885.1 (2018) Pipelines Đ Gas and Liquid Petroleum Đ Part 1 Design and Construction AS/NZS AS/NZS 2885.6 (2018) Pipelines Đ Gas and Liquid Petroleum Đ Part 6 Pipeline Safety Management DNV DNVGL-RP-F104 Design and Operation of Carbon Dioxide Pipelines AS/ISO AS/ISO 27919.1 (2019) Carbon dioxide capture, Part 1: Performance evaluation methods for post-combustion CO2 capture integrated with a power plant AS/ISO AS ISO 27914 (2019) Carbon dioxide capture, transportation and geological storage Ń Geological storage ISO ISO/TR 27912 (2016) Carbon dioxide capture Ń Carbon dioxide capture systems, technologies and processes ISO ISO 27913 (2016) Carbon dioxide capture, transportation and geological storage Ń Pipeline transportation systems ISO ISO 27914 (2017) Carbon dioxide capture, transportation and geological storage Ń Geological storage ISO ISO/TR 27918 (2018) Lifecycle risk management for integrated CCS projects ISO ISO/TR 27921 (2020) Carbon dioxide capture, transportation, and geological storage Ń Cross Cutting Issues Ń CO2 stream composition ISO ISO/TR 27923 (2022) Carbon dioxide capture, transportation and geological storage Ń Injection operations, infrastructure and monitoring ISO ISO/DIS 27927 Carbon dioxide capture Ń Key performance parameters and characterization methods of absorption liquids for post-combustion CO2 capture ISO ISO/DIS 27928 Carbon dioxide capture Ń Performance evaluation methods for CO2 capture connected to a CO2 intensive plant ISO ISO/TR 27929 Transportation of CO2 by ship ISO ISO 13623 (2017) Petroleum and natural gas industries Ń Pipeline transportation systems AS AS 3008 Electrical installations Đ Selection of cables AS AS 3959 Construction of Buildings in Bushfire Prone Areas 2.2 Chemical specification CO2 captured from industrial sources is generally emitted as a low-pressure gas saturated with water. The combination of water and CO2 forms carbonic acid, which is corrosive to carbon steel pipelines, making water the primary impurity that must be removed or reduced to levels where there are no impacts. Other minor impurities ? including nitrogen (N2), methane (CH4), carbon monoxide (CO), hydrogen sulfide (H2S), oxides of nitrogen (NOx), oxides of sulfide (SOx) and amine carry-over ? also require consideration. These impurities can change the chemico-physical behaviour of the CO2 stream and may affect the hubŐs operational specifications in various ways: * Dew point: polar components present in the CO2 stream affect the dew point curve Đ increases the temperature at which liquid-phase drop-out occurs. * Bubble point: non-condensable components present in the CO2 stream affect the bubble point curve Đ increases the pressure at which two-phase conditions are seen. * Corrosivity: the presence of certain chemicals in combination with water leads to reactions and potential for corrosive films/pools. * Other: certain impurities in sufficient concentration can contribute to stress corrosion cracking, the potential of a running ductile fracture and impact the CO2 fluid physical properties, impacting, for example, metering accuracy. Risks to health and environment and biological growth in the reservoir (e.g. oxygen [O2]) are also concerns that require analysis. To ensure that operations remain within a safe and economically viable operational envelope (injection of gases other than CO2 still has the same costs on projects), it is essential to restrict impurity concentrations in the CO2 stream. A risk-based approach has been implemented for the MASDP that allows individual proponent industries to adhere to the CCUS CO2 specification guidelines, provided that the CO2 gas stream constituent concentrations are not detrimental to the CCUS hub, equipment, piping and main CO2 exporting pipeline integrity. The maximum allowable concentrations for each component are based on the quality specification guide provided by the NT-DIPL (GHG Wood Group (2023). To assess the impact of different impurity levels within these specified limits, computer modelling was conducted using HYSYS process simulation software (not shown here), based on an example inlet gas composition sourced from the AGRU. Previous studies have identified a maximum concentration of 100 ppmv water in the CO2 stream as appropriate for transport through carbon steel pipelines. This concentration was used in the design of the CarbonNet CO2 pipeline in Victoria and has been adopted as the maximum level for this development. However, it is acknowledged that some recent pipeline projects have set a lower maximum concentration of approximately 40?50 ppmv. Achieving these lower levels may necessitate additional dehydration treatment at the hub. The concept design incorporates the option for this additional processing should the lower water limit be specified. A reference (or typical) composition has been established for the CO2 stream anticipated across all of the MASDP industries by taking the typical gas compositions from both post-combustion and pre-combustion sources stated in the literature and modelled in a 40:60 ratio (Table 2). This reference case represents the composition expected from MASDP industries at full development and is used for cross-checking against the proposed upper and lower CO2 stream specifications (Walspurger and Dijk, 2012). The blending of CO2 streams from different industries could have the effect of diluting CO2 components across the CCUS hub but also eventuate in a more complex mixture of incidental associated compounds in the CO2. There will be a difference between these specifications and the actual composition of the CO2 streams within the MASDP and across the wider CCUS hub. The specifications represent limits associated with individual components in the CO2 streams, whereas the actual CO2 streams are expected to have lower concentrations of any one individual component but may also include other compounds not included in the specifications. For these other compounds there will need to be individual risk assessments of their impact, if any, on the CCUS hub. Key risks relating to staying within the specifications include: * high NOx content due to NOx removal failure in post-combustion sources Đ can also lead to high CO * high SOx content due to SOx removal failure in post-combustion sources * high O2 content due to catalytic oxidation unit failure in post-combustion sources * amine carry-over from CO2 removal system, pre- and post-combustion sources * glycol carry-over from the dehydration unit (if TEG), pre- and post-combustion sources * water excursion Đ dehydration unit failure/bypass, pre- and post-combustion sources. It should be noted that CO2 specifications globally are subject to continuous modification based on regulations in different jurisdictions and as more diverse sources of CO2 are identified by proponents of CCUS projects. Ongoing research on the synergistic effects of different chemical components in CO2 streams on both infrastructure and subsurface geology is required so that the standards and regulatory requirements can be properly kept up to date and fit for purpose. Table 2: Reference composition for the MASDP (blended composition of CO2 stream from MASDP industries), compared with the lower and upper levels for maximum concentrations compared with specifications from other projects Source: GHG Wood Group (2023) Component Post-combustion composition (dry) Pre-combustion composition (dry) Reference MASDP composition* MASDP spec. lower max limit MASDP spec. upper max limit Porthos** Fluxsys*** UK cluster conf. CO2 99.6Đ99.8 mol% 98.1Đ99.7 mol% 98.1 mol% >90.0 mol% ł95 mol% >95 mol% ł96 mol% H2 - 20Đ30,000 ppmv 1 mol% ? = 2 mol% ? = 5 mol% <0.75 mol% <4 mol% <0.75 mol% <4 mol% ˛0.75 mol% O2 0.0035Đ0.015 mol% - 0.0008 mol% <40 ppmv <40 ppmv ˛10 ppmv N2 0.045Đ0.29 mol% 0.0195Đ1 mol% 0.8 mol% <2.4 mol% <2.4 mol% ˛4 mol% Ar 0.0011Đ0.021 mol% 0.0001Đ0.15 mol% 0.05 mol% <0.4 mol% <0.4 mol% ˛4 mol% CH4 - 0Đ112 ppmv 25 ppmv <1 mol% <1 mol% ˛ 4 mol% CO 1.2Đ10 ppmv 0Đ2,000 ppmv 400 ppmv 900 ppmv 5,000 ppmv <750 ppmv <750 ppmv ˛1,000 ppmv SOx (as SO2) 0Đ67.1 ppmv 25 ppmv 30 ppmv 200 ppmv 2,000 ppmv STOTAL <20 ppmv <10 ppmv ˛20 ppmv NOx 20Đ38.8 ppmv 400 ppmv 20 ppmv 250 ppmv 2,500 ppmv <5 ppmv <5 ppmv ˛10 ppmv H2S - 200 ppmv 80 ppmv 100 ppmv 150 ppmv <5 ppmv <5 ppmv ˛5 ppmv H2O - - 50 ppmv 100 ppmv <70 ppmv <40 ppmv ˛50 ppmv *This is not a specification Đ it is an expectation of the typical blended MASDP CO2 export stream for reference. **Also stipulates NH3 < 3 ppmv, Methanol (MeOH) <20 ppmv, ethanol <20 ppmv, amines <1 ppmv, hydrogen cyanide (HCN) <2 ppmv***Also stipulates NH3 < 3 ppmv, Methanol (MeOH) <620 ppmv, ethanol <10 ppmv, amines <1 ppmv, HCN <2 ppmv 3 MASDP CCUS system design This section summarises the two studies undertaken by Wood and GHD (2023; 2024). It contemplates the volumes of CO2 that could be captured by the MASDP industries under the Balanced Scenario and the requirements of the industrial proponents to treat and provide low pressure compression, the CO2 collection pipeline network, common compression facilities to boost the low-pressure CO2 to high pressures, the CO2 import terminal and the high-pressure pipelines that will transport the CO2 to the export pipelines. 3.1 MASDP industry capture and conditioning 3.1.1 CO2 quantities from supplying industries For each industry and according to the size contemplated within the Balanced Scenario, the CO2 emissions that could be captured were assessed by the NT-DIPL to derive the maximum volumes of CO2 that may need to be transported for storage. This assessment identified a maximum projected capacity requirement of around 9.1 Mtpa of CO2 (Table 3). This approach differs somewhat from the approach detailed in the Task 1 report, in which each emissions category for the Northern Territory was assessed according to its ability to be avoided or abated, and where assumptions were applied for emissions categories as a whole, with emissions reduction technologies being adopted according to their future availability. Despite the differences in the two approaches, the NT-DIPL estimates of captured CO2 volumes and therefore CO2 hub capacity requirements are broadly in line with the Task 1 Base Scenario CCS abatement model where maximum CCS demand from the MASDP industries was estimated to be 9.5 Mtpa (see the Task 1 report (Rogers et al., 2024)). According to the concept design, CO2 capture for each industry in the MASDP occurs within its respective facilities, with the common pipelines used to transport the gas within the MASDP part of the CCUS hub. CO2 is compressed at a centralised facility within the MASDP and exported via a tie-in point to a downstream third-party pipeline. The expected industries in the MASDP and their respective contributions to the projected scope 1 emissions of approximately 9.1 Mtpa, once fully developed, are summarised in Table 3. It is estimated that pre-combustion sources will account for 60% of emissions and post-combustion sources for 40%, once the precinct is fully developed. The development is expected to be staged, with additional CCUS hub compression capacity being added in line with growing industrial development. For each of the industries contemplated in Table 3 a proportion of the captured CO2 will originate from the industrial processes used. For example, for the LNG industry 182 ktpa of CO2 emissions would be generated through AGRU CO2 separation from the natural gas. For the SMR hydrogen case it is assumed that all of the CO2 generated is through the pressure swing/AGRU adsorption system used to separate CO2 from the derived hydrogen. This is an integral part of producing purified hydrogen from natural gas using SMR. Within the GHG Wood Group (2023) study, the configuration of each capture plant is not specified. Understanding the configuration of the capture systems and identifying the relative proportion of a system that is an unavoidable cost (meaning an embedded cost as part of the industrial process) will be key to optimising the design and additional sizing of the capture systems for the MASDP. A further qualification is that in the analysis below, each industry is assumed to be a standalone entity with no sector coupling. Sector coupling and industrial symbiosis (see Task 5 report; Czapla et al. (2024)) have the potential to reduce overall costs and emissions of the integrated hub. Table 3: MASDP industries and emissions categorisation and contribution Source: GHG Wood Group (2023) Industry Description Classification Scope 1 contribution* Liquefied natural gas CO2 stream from acid gas removal, refrigerant turbines, power generation turbines Post-combustion 1.401 Mtpa (15% post-combustion, 2% CO2 from AGRU) Ethane cracker Natural gas fired, pyrolysis heating furnace exhaust gas, compressor turbine exhaust gas Post-combustion 0.673 Mtpa (7%) Methanol Natural gas reacted with steam and heat to produce H2, CO2 and CO (syngas); syngas then exothermically reacted to create methanol Pre-combustion 1.200 Mtpa (13%) Ammonia Natural gas reacted with steam and heat to produce H2 and CO2; CO2 separated via AGRU; N2 separated from air; H2 and N2 reacted with heat to produce ammonia Pre-combustion + post-combustion 2.129 Mtpa (23%) (assume 50/50 pre-/post-combustion) Condensate refining (gas to liquid) Water washing, condensate stabilisation and condensate treating processes Post-combustion 0.415 Mtpa (4%) Urea As per ammonia, but a portion of waste CO2 is reacted with ammonia to produce urea Pre-combustion + post-combustion 1.154 Mtpa (12%) (assume 50/50 pre-/post-combustion) Thermochemical reduction of methane to hydrogen Natural gas desulfurisation, SMR, CO shift conversion, pressure swing adsorption Pre-combustion (assumes CO2 captured from syngas) 2.054 Mtpa (22%) Lithium hydroxide Process spodumene ore concentrate, containing various amounts of lithium oxide, via pyrometallurgical and hydrometallurgical unit operations to produce lithium hydroxide monohydrate Post-combustion 0.064 Mtpa (1%) Ammonium phosphate Conversion of phosphate concentrate into ammonium phosphate (fertiliser) Đ energy-intensive Post-combustion 0.053 Mtpa (1%) Total 9.143 Mtpa *Rounded percentages indicate the estimated contribution of each industry to the overall MASDP scope 1 CO2 emissions of ~9 Mtpa. 3.1.2 Compression and treatment systems used by proponents For the cost estimations below, it has been assumed that the industrial proponents will predominantly use amine capture, but ultimately each industrial proponent will determine their own preferred capture technology. Once captured, CO2 will need to undergo gas conditioning, up to agreed standards, to enable its transport within the CCUS hub. It has also been assumed that each industry will treat and dehydrate the CO2 it produces to meet specifications and compress the gas to an acceptable level for the CCUS hub before it can be injected into the collection headers (pipelines). Process modelling was conducted with the aim to achieve the full flow of each proponentŐs CO2 contribution at an inlet pressure of at least 8.5 barg. Consequently, the discharge pressure of each proponentŐs CO2 stream into the collection header must be set 2?3 bar higher to compensate for pressure drop along the header. The compression process was modelled using a two-stage centrifugal pump (Figure 6), while dehydration was modelled with TEG recycling (Figure 7). These technologies are well-understood and commonly employed in the petrochemical industry. The choice of compressor driver, either an electric motor or a gas turbine, will be determined by each industrial proponent. The proposed two-stage compression system is shown schematically in Figure 6. This process incorporates air aftercooling and chilled-water subcooling ahead of the knock-out drum to achieve the maximum possible water drop-out prior to the dehydration phase. Figure 6: Typical proponent compression process flow diagram Source: GHG Wood Group (2023) In a typical design, multiple compression trains feed into a single TEG dehydration system (Figure 7). This system requires a heating system, which can be either hot oil or an electric heating element, with a power requirement of approximately 840 kW per 1 Mtpa of feed gas, in addition to a supply of nitrogen used as stripping gas to carry away the water vapour. Figure 7: TEG dehydration process flow diagram Source: GHG Wood Group (2023) Following dehydration, the CO2 undergoes final filtration to protect the pipeline against TEG carryover (Figure 8), before continuous online moisture analysis and custody transfer metering. The main isolation valve would be exclusively controlled by the operator of the CCUS hub. Figure 8: Process flow diagram illustrating CO2 export into the collection header Source: GHG Wood Group (2023) As illustrated in Figures 6-9, the industrial proponents will continuously capture and compress CO2 into the collection headers. Consequently, no requirement for CO2 storage is expected within the proponentsŐ facilities. 3.2 MASDP CCUS pipeline network The pipeline system consists of the CO2 collection header pipelines and the export pipeline. Two collection header lines are proposed: one from the western part of the MASDP and the other from the eastern part (including any other industries located outside the MASDP along Channel Island Road). The pipeline network is shown in Figure 9. All CO2 pipelines are assumed to be buried for most of their length and are rated for the inlet pressures and composition of CO2 (e.g. corrosion-resistant steel). Each industrial proponent treats and compresses the CO2 produced at its facilities for transport through the collection header to the CCUS hub. The systemŐs capacity utilisation will depend on the phasing of development, with initial flows expected to be low then gradually increasing as additional industries become operational. Figure 9: The CO2 pipeline network. The onshore main CO2 export pipeline beyond the MASDP CO2 pipeline tie-in and other downstream pipelines and facilities is not shown. The blue line shows the 400 mm OD header pipeline and the red lines show the 800 mm OD header pipelines. The captured CO2 volumes for each industrial proponent in Mtpa are shown. Area G is the MASDP CCUS hub compression facility. The yellow line is the CO2 export pipeline. Yellow shaded areas are service and utility corridors. Source: adapted from GHG Wood Group (2023) 3.2.1 Collection header The design parameters for the collection header pipeline are outlined in Table 4. Table 4: Design parameters for the collection header Source: GHG Wood Group (2023) Item Description Value 1 Flow rate: Western header 3.96 Mtpa Eastern header 5.19 Mtpa 2 Design pressure: Collection header inlet 11 barg Collection header outlet 8.5 barg 3 Suggested collection header linepipe properties: 800 mm OD x 15.9 mm WT, Grade 415 400 mm OD x 9.5 mm WT, Grade 415 The moisture content specification for each industry proponent to access the collection header is set at less than 100 ppmv. The CCUS hub operator will continuously monitor the water levels in each proponentŐs CO2 stream and will shut down the gas flow if this limit is surpassed. The compression provided by the industry proponents is sufficient to deliver the required quantity of CO2 to the MASDP CCUS hub compression system via the collection headers (at a nominal compression hub inlet pressure of 8.5 barg). The exact compression requirement for each industrial proponent will vary based on their distance from the compression facility. The two collection headers service different industries: * Western header Đ urea, ammonia and ethylene plants (Figure 9). * Eastern header Đ lithium hydroxide, phosphate, methanol, LNG, thermochemical reduction of methane to hydrogen and condensate refinery/gas to liquid plants (Figure 9). Two header pipeline sizes have been selected to gather the CO2 from these industries: * DN400 (400 mm) (Figure 9) * DN800 (800 mm) (Figure 9). Given the phased development of the precinct, the Eastern header has a compound design that includes both DN400 and DN800 sections. This arrangement has been selected to optimise the sizing of the lines ? the pipeline size changes along its length allow for higher flow rates as proponents inject CO2. A branched tie-in between the two sections enables: * staged installation of the smaller pipeline as proponents located further east begin production and require access to the CCUS facility * isolation between the sections to facilitate installation, pre-commission and maintenance activities * future pigging1 of the lines without requiring a multi-diameter tool The CO2 collection header pipelines are located within the service corridors and buried alongside the MASDP roads, ensuring easy access for inspection and maintenance activities. The operating philosophy is guided by MASDP CCUS hub compression facility requirements for a specific inlet pressure to deliver the inlet requirements of the export compression process. The flow rates and pressures are managed through the staging of the export compression. The condition of the pipeline may be assessed through in-service inspections by intelligent pigs. To accommodate potential future inspection requirements, it is proposed that the pipelines include the necessary facilities (e.g. blind flanges and valves) for the connection of temporary pig launchers and receivers. These temporary pigging facilities will also support pre-commissioning and commissioning activities and can therefore be retained as a permanent component of the pipeline. During operation, an inspection contractor will provide suitable launchers and receivers for their specific inspection tools. It should be noted that in-service inspections are required only if there is prolonged operation outside the approved operating parameters and to fulfill any regulatory inspection obligations. Additional inspection activities include management of the external corrosion control system, which involves inspecting the anode ground beds that protect the buried pipelines, the external coatings of pipelines that are above ground or exposed in culverts, and the cathodic protection cables and connections to the pipeline to ensure that there is no encroachment or potential exposure to third-party damage. Given that the collection header pipelines are within a dedicated pipeline easement, and access to the MASDP is controlled, the risk of third-party damage to the pipeline is deemed very low. As the locations of the proposed industries within the MASDP may change, the configuration of the header pipelines may change, but overall the costs will be within the bounds of the concept design costings. 3.2.2 CCUS hub compression and CO2 export Within the NT-DIPL concept design of the MASDP CCUS hub, two CO2 export options were investigated (export from the MASDP): one associated with dense-phase transport of CO2 and a second exploring medium-pressure gas-phase transport. Currently, dense-phase transport is the preferred option as it allows a more efficient integration with CO2 export pipelines to the geological storage/sequestration locations. Dense-phase transport In this option, the dehydrated CO2 arrives at the compression hub at a pressure of 8.5 barg and is subsequently compressed to a pressure of 180 barg using a three-stage compressor (Figure 10). The dense-phase fluid is then pumped into the DN600 (600 mm) pipeline and transported ~4 km to the tie-in point joining the third-party downstream CO2 storage/sequestration system (MASDP CCUS hub battery limit). The pressure loss experienced in this pipeline is approximately 0.2 bar, with a fluid velocity of around 2.5 m/s. The CCUS hub compression system is configured into three trains, each providing a third of the total capacity. This arrangement allows for staged development of the CCUS hub. The compression process flow diagram shown in the Figure 10 illustrates one of the three identical trains, each rated at 25.632 MW. Figure 10: Dense-phase export compression concept (one of three trains) Source: GHG Wood Group (2023) Gas-phase transport For this option, the dehydrated CO2 arrives at the compression facility at a pressure of 8.5 barg, where it is subsequently compressed to 74 barg in two stages. The compressed gas is then directed into a DN450 (450 mm) pipeline and transported ~4 km to the third-party downstream CO2 storage/sequestration system (MASDP CCUS hub battery limit). The pipeline undergoes a pressure loss of approximately 25.4 bar, resulting in an arrival pressure of 58 barg. The gas velocity in the pipeline is approximately 22.2 m/s. Similar to the dense-phase design, the hub compression system is configured into three trains, each providing about a third of the total capacity, to allow for staged development. The compression process flow diagram shown in the Figure 11 illustrates one of the three identical trains, each rated at 19.077 MW. Figure 11: Gas-phase export compression concept (one of three trains) Source: GHG Wood Group (2023) It is assumed that the export of CO2 will occur continuously. Any fluctuations in capacity will be managed through compressor turndown and the use of parallel compression trains, so the CCUS hub itself does not require CO2 storage facilities. 3.2.3 Export pipeline The CO2 is transported through the MASDP export pipeline from the hub compression system (Area G) to the INPEX Access Road Junction tie-in location, shown by the yellow line in Figure 12. This tie-in point represents one of two possible tie-in points, with a second contemplated in the vicinity of the Ichthys gas pipeline shore-crossing easement close to the Darwin LNG facility (see section 4). This location is ~7.4 km from the MASDP hub compression system. This second option was not explicitly considered in the GHG Wood Group (2023) study, but it will be discussed in subsequent sections. The design parameters for the MASDP export pipeline are listed in Table 5. The exported CO2 stream will flow from the MASDP hub compression system to the tie-in location at the downstream third-party pipeline. Therefore, the operation of the export pipeline needs to be coordinated with the operator of the downstream pipeline. As with the collection header pipelines, it is critical to operate the pipeline outside the free-water formation envelope to ensure the long-term integrity of the system. The downstream pipeline operator will control the operating envelope of the export pipeline system. Figure 12: The MASDP CO2 export pipeline is shown in yellow. The solid yellow line represents the export pipeline from the GHG Wood Group (2023) study and the dotted yellow line indicates the alternative tie-in point for the CO2 export pipeline Source: adapted from GHG Wood Group (2023) Table 5: Design parameters for the CO2 export pipeline Source: GHG Wood Group (2023) Item Description Value 1 Flow rate 9.14 Mtpa 2 Design inlet pressure Gas-phase export 74 barg Dense-phase export 180 barg 3 Distance from CCUS to tie-in ~ 4 km 4 Suggested CO2 export linepipe properties 610 mm OD x 19.1 mm WT, Grade 415 3.2.4 Metering and pigging facilities Before entering the collection header pipelines, the CO2 stream from each industry proponent will be closely monitored to ensure quality and compliance with specifications. Given the possible severity of corrosion concerns, any deviation from the specifications will prompt the CCUS hub operator(s) to halt the transfer from the relevant proponent until the issue has been resolved. Additionally, metering for custody transfer is necessary to satisfy anticipated regulatory requirements and to document the usage of the common header and the capacity of the CCUS facility. As discussed above, pigging facilities are needed for pre-commissioning, commissioning and potentially in-service inspection and maintenance activities. Pre-commissioning includes the activities that validate the pipelineŐs suitability for its intended purpose and prepare it for the introduction of the product. For an onshore CO2 pipeline, pre-commissioning activities typically include: * cleaning and gauging the pipeline following construction * flooding, pressurising and hydrotesting to verify the integrity of the pipeline * removing water and drying the pipeline. Once these activities have been completed, the pipeline is deemed ready for introduction of the product. Regular pigging is unlikely to be necessary because the gas specifications and flow rates are monitored, and the contaminants and moisture levels are managed. Thus, only temporary pigging facilities will be needed for the pre-commissioning activities. It is recommended to install weld neck flanges and isolation valves at the ends of the collection header pipeline runs. This setup allows pigging operations by connecting a temporary pig launcher and receiver to the flanges. The design should include a tie-in for the temporary pig receiver to enable flushing with inert gas, to minimise the risk of air and moisture entering the pipeline. Operational pigging would only be necessary if integrity issues were suspected related to internal or external corrosion. The effective management of external corrosion risk is achieved through careful selection of the coating, along with proper trench preparation ? including an appropriate bedding layer, quality control during installation and in-service checks (e.g. anode ground bed performance). 3.3 LCO2 receiving and storage terminal Much of the demand for a CO2 import facility is being driven by countries in Asia, such as South Korea and Japan, that are seeking to reduce their atmospheric CO2 emissions through permanent storage or sequestration but lack sufficient geological CO2 storage capacities for the volumes required or over the timeframe required. An LCO2 receiving and storage terminal has been defined as part of the potential CCUS hub infrastructure requirements (Wood and GHD (2024). The inclusion of a CO2 import (and, in principle, export) terminal allows importation of additional CO2 volumes, to both lower the unit cost of CO2 storage and maximise system capacities, reduce regional emissions and provide future capacities to export CO2 to other storage locations in the event that the hub capacities are exceeded. The LCO2 import terminal will be designed to receive CO2 with a defined composition, compress it and then export it to the designated tie-in point for downstream export to the pipelines for offshore geological CO2 storage/sequestration. A concept design study was conducted by the NT-DIPL (Wood and GHD (2024) to evaluate the importation and temporary storage of LCO2 in the MASDP, and the export of CO2 to a tie-in location operated and controlled by a downstream third-party recipient located ~4 km west of the MASDP. As noted above, this tie-in point represents one of two possible tie-in points, with a second contemplated in the vicinity of the Ichthys gas pipeline shore-crossing easement close to the Darwin LNG facility (see section 4). This location is ~7.4 km from the MASDP hub compression system. The LCO2 import terminal is designed to share Berth 3 of the proposed MASDP port facility with ammonia and ethylene export activities. The LCO2 storage facility is expected to cover an area of 6 hectares in the southern section of the common user facility (Figure 13). Figure 13: LCO2 facilities in the MASDP. The vessel-to-storage transfer pipeline route is shown in magenta, the storage facility is in purple and the export pipeline sharing the Stirling Road pipeline corridor is also shown in magenta. Source: adapted from Wood and GHD (2024) 3.3.1 Design considerations The concept design used the following key design assumptions: * shipping and buffer storage calculations have been conducted based on travel between Darwin and South Korea * Berth 3 at the MASDP will be configured for the importation of LCO2, and there will be sufficient spare berth utilisation capacity to support this import * the common user facility will receive electrical power from the local grid, which is expected to have adequate capacity to meet the projectŐs needs * LCO2 transport vessels with a cargo capacity of 80,000 m? will be available within the projectŐs lifespan * the construction of the module offloading facility will be completed on schedule to enable the timely delivery of the prefabricated spheres. The import concept design explored a base case and alternative configurations, as summarised in Table 6 . A key design feature is the infrastructureŐs flexibility: it accommodates an initial processing capacity of 0.5?1 Mtpa and is designed to expand to 5 Mtpa (or 6 Mtpa) to align with the forecast demand growth. Table 6: Characteristics of the base case and alternative option for LCO2 import concept design Source: Wood and GHD (2024) Parameter Base case Alternatives Notes Annual import amount ~0.5Đ1 Mtpa, rising to 5 Mtpa Throughput capacity increase to 6 Mtpa Phased expansion from initial capacity of 3 Mtpa using 40,000 m3 LCO2 cargo vessels, rising to 5 Mtpa using 80,000 m3 vessels Ship capacity Initial design capacity: 40,000 m3 Future capacity: 80,000 m3 Ship LCO2 storage pressure and temperature 7 barg 15 barg Upon discussions with Royal Haskoning DHV, it was advised that 15 barg LCO2 transport was unlikely to occur during the project lifetime, as it offered only a marginal increase in shipped volume while doubling the pressure storage requirement of the vessel; the 15 barg case is only included as a sensitivity test Import flow rate from vessel to terminal 3,000 m3/hr 6,000 m3/hr Export delivery CO2 to third party tie-in Supercritical or dense phase (120 to 150 bar) Gas phase Đ not assessed Export pipeline Sized for 6 Mtpa, dense phase Gas phase to Area G, then compressed to dense phase at Area G for export Onshore storage 60,000 m3 rising to 120,000 m3 (150% buffer storage) Export pump, heating and boil-off gas compressor capacities 3 Mtpa rising to 5 Mtpa 6 Mtpa Berth utilisation 0.6 days to offload/load vessel ~12% berth utilisation at 3 Mtpa ~19% berth utilisation at 5 Mtpa 1.0 days to offload/load vessel ~20% berth utilisation at 3 Mtpa ~33% berth utilisation at 5 Mtpa (40,000 m3 vessel size) Based on discussion with Royal Haskoning DHV, when Berth 3 is shared by three different products, the total utilisation of the berth should be capped at 65%; as a result, the offloading frequency for LCO2 imports should be set at a minimum of every 4?5 days Design life 30 years The NT-DIPL study assumed a nominal facility availability of 95%, corresponding to at least 346 operational days each year (Wood and GHD (2024). The LCO2 import composition is detailed in Table 7 . It is assumed to have a purity level of 99.83% (reflecting the higher specification requirements associated with liquid CO2 at 7 barg and -48ĄC). These specifications are somewhat higher than those detailed in section 2.2. Table 7: LCO2 import composition Source: Wood and GHD (2024) Component Specification (ppm mol unless otherwise specified) Carbon dioxide, CO2 ł99.83 %mol Water, H2O ˛30 Oxygen, O2 ˛10 Oxides of sulfur, SOx ˛10 Oxides of nitrogen, NOx ˛10 Hydrogen sulfide, H2S ˛9 Carbon monoxide, CO ˛100 Amines ˛10 Ammonia, NH3 ˛10 Hydrogen, H2 ˛50 Formaldehyde, HCHO ˛20 Acetaldehyde, CH3CHO ˛20 Cadmium, Cd, and thallium, TI ˛0.03 (sum) Mercury, Hg ˛0.03 3.3.2 Shipping, berth utilisation and buffer storage The concept design brief specified an initial throughput of 0.5?1 Mtpa, which is then expected to increase to 5 or 6 Mtpa, delivered by third-party vessels each with a capacity of 40,000m3. Larger ships of 80,000m3 capacity are anticipated to be introduced from around 2040 onwards. Based on an evaluation of shipping, berth utilisation and buffer storage, the concept design study proposed a suitable upper limit of 3 Mtpa using ships with a 40,000m3 capacity, and identified MASDP Berth 3 as the preferred import terminal. This configuration supports efficient use of both the vessels and the berth, noting that the berth is shared among other users. Expanding to 5 Mtpa would preferentially require ships with a capacity of 80,000m3. Further analysis of process and equipment sizing, which included duty and maintenance considerations, indicated that using the same equipment for both stages of development would be greatly beneficial. Therefore, it is recommended that the second phase increase the facilityŐs throughput to 6 Mtpa, not 5 Mtpa, providing a 20% increase for only a modest rise in capital costs. These throughput levels were chosen to ensure maximum operational life at 3 Mtpa level, delaying the need for further investment until the larger 80,000m3 ships come into operation. The common user facility will handle various hydrocarbons for export, module and material imports, potential bunker fuel storage, and other related activities. As such, it is desirable to design the LCO2 operations to be as simple as possible to minimise brownfield work. The concept design also focused on a single expansion phase from 3 Mtpa to 6 Mtpa, rather than multiple smaller brownfield expansions to incrementally boost throughput capacity. Onshore buffer storage is a crucial aspect of the design process, as it directly impacts the systemŐs flexibility to respond to fluctuations in vessel arrivals. Sufficient buffer storage mitigates the challenges posed by the arrival of two vessels within a short period of time and reduces vessel demurrage by offering extra capacity for the cargo of the second ship. The requirements for buffer storage are fundamental to the process design and equipment requirements. Table 8 presents the input parameters and resulting values from a comprehensive set of calculations to determine storage requirements. The table shows varying import rates from 1 Mtpa to 6 Mtpa, alongside vessel cargo capacities of 40,000m3 and 80,000m3. The results demonstrate that the required onshore storage-to-cargo size ratio can range from 113% to 169%. It is recommended that the buffer storage volume be set at 150% of the cargo size, which corresponds to 60,000m3. This storage capacity is believed to achieve the best balance between efficient vessel operations (minimising demurrage), capital investment, layout footprint and operational requirements. According to the Table 8 import levels exceeding 3 Mtpa with a 40,000m3 cargo capacity result in offloading frequencies falling below 5 days. The increasing possibility of vessel demurrage, particularly given that the berth will be shared with other users, coupled with the necessary capital investment for additional storage and expanded land utilisation, suggest that the optimal limit for a 40,000m3 cargo size is 3 Mtpa. This critical consideration has established an initial maximum importation rate of 3 Mtpa as the base case. Berth utilisation is another critical factor, and ranges from a minimum of 4% to a maximum of 22%. The rate depends on the number of trips needed each year to meet import demands and the duration of each stay at the berth. Ships with a capacity of 40,000m3 are expected to spend 12 hours (0.5 days) offloading at an assumed flow rate of 3,000m3/hr, and ships with a capacity of 80,000m3 will take 24 hours (1 day) to offload at the same flow rate. If this flow rate proves to be inadequate, the import pipelines can be replaced with larger ones to accommodate higher flow rates, or additional lines can be installed, as there will be growth allowance for additional lines within the pipe racks. Table 8: Buffer storage calculations Source: Wood and GHD (2024) Parameter Unit Values Notes Annual import volume Mtpa 1 2 3 4 5 5 6 6 Annual average LCO2 carrier storage m3 40,000 40,000 40,000 40,000 40,000 80,000 80,000 80,000 Gross Carrier usable capacity m3 36,400 36,400 36,400 36,400 36,400 72,800 72,800 72,800 Net (type-C vessel, 91% working capacity) Storage pressure barg 7 7 7 7 7 7 7 15.5 Storage temperature ĄC -48 -48 -48 -48 -48 -48 -48 -28 Carrier LCO2 density kg/m3 1,147 1,147 1,147 1,147 1,147 1,147 1,147 1,067 Shipped LCO2 volume m3/yr 874,126 1,748,252 2,622,378 3,496,503 4,370,629 4,370,629 5,244,755 5,623,243 Load/offload rate m3/hr 3,000 3,000 3,000 3,000 3,000 3,000 3,000 6,000 Load/offload duration days 0.5 0.5 0.5 0.5 0.5 1 1 0.5 Time in port (South Korea & Darwin) allowance days 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 Entry and exit durations at loading and receiving ports No. of trips required per year [rounded up] no. 24 [25] 48 [49] 72 [73] 96.1 [97] 120.1 [121] 60 [61] 72 [73] 77.2 [78] Annual shipped volume/carrier capacity Carrier availability % 95.9 95.9 95.9 95.9 95.9 95.9 95.9 95.9 Assumes 350 carrier service days per year Number of carriers required [rounded up] no. 1.6 [2] 3.3 [4] 4.9 [5] 6.5 [7] 8.1 [9] 4.2 [5] 5.1 [6] 5.2 [6] Frequency of offload days 15 7 5 4 3 6 5 4.7 Ship arrives every [value] days Allowance for unplanned delays days 2 2 2 2 2 2 2 2 Key assumption Đ port and weather delays Gross storage (to nearest 2,500 m3) m3 45,000 52,500 57,500 62,500 67,500 107,500 112,500 115,000 Ratio of onshore storage to carrier capacity - 113% 131% 144% 156% 169% 134% 141% 144% Berth utilisation 4% 8% 12% 16% 19% 18% 22% 8% Storage recommendation - 150% 150% 150% 150% 150% 150% 150% 150% m3 60,000 60,000 60,000 60,000 60,000 120,000 120,000 120,000 3.3.3 Onshore LCO2 storage tank options The import terminal must have the capacity to store the volume of LCO2 delivered by a vessel, plus a minimum buffer storage volume to mitigate most vessel demurrage problems. As discussed above, the recommended storage volume is 150% of the shipping cargo volume. The concept design study evaluated three types of storage tanks: Horton spheres, horizontal bullets2 and vertical bullets. The design pressure was 7.5 barg, and the design temperature -60 ĄC. The selected tank size for each option was determined by a combination of factors, including the feasibility of fabrication and delivery (including cost and duration), installation capabilities (phased into two stages) and operational requirements. The advantages and disadvantages of each storage type are compared in the Table 9. The storage tanks are expected to be fabricated overseas and shipped to the site. The proposed maximum dimensions for modules arriving at the MASDP are 44.5 m in width and 98 m in length, so the storage tanks must fit within these parameters. This is not considered as a limitation in selecting the type of storage tank. Table 9:Types of storage tanks: pros and cons Source: Wood and GHD (2024) Storage type Advantages Disadvantages Horton sphere * Lowest surface area for volume ? a sphere contains the most volume for the lowest surface area of any body. This low surface-area-to-volume ratio indicates that heat ingress will be lowest. * Largest storage volume ? also due to the geometry, spheres have a uniform resistance to stress, making large-volume tanks possible. * In some cases, spheres benefit from being easier to transport than cylinders. * Small quantity required ? due to the large storage volume, fewer storage spheres are required. * Less piping required ? due to the lower quantities, less pipework is needed for the total storage setup. * Use of the module offloading facility enables offsite fabrication and delivery * Low footprint * Complex construction ? due to large size required, fabrication is more complex (and spheres are much less commonly fabricated than bullets) and installation requires detailed consideration. * Strong foundation required ? spheres allow for concentrated mass within an area. * If the module offloading facility is not available, spheres are not easily transported by road. * Long lead times ? due to the complex construction, long lead times of upwards of 12 months are possible. * Costly ? spheres can be costly to construct due to their complexity and large size. * Offline maintenance ? taking a sphere offline for maintenance significantly reduces the overall available storage volume. Vertical bullet * Short lead times Đ cylinders have a relatively simple design and can be fabricated in a matter of weeks. * Easier to maintain Đ can take one vessel offline and not significantly affect system performance. * Easier to source but harder to replace Đ a replacement cylinder can be sourced in a matter of weeks; however, due to the vertical arrangement installation will be difficult and extensive * Larger number of tanks Đ over 3x more tanks compared with spheres. * Require tall storage frame to support vertical cylinders. * Strong foundation required Đ weight is concentrated within a relatively small area. * Significantly larger amount of interconnecting piping required, due to the larger number of tanks. Increases equipment CapEx, installation work and maintenance, plus greater chance of gas leaks. * Installation in a small footprint requires a large crane and may impede installation of other equipment. Horizontal bullet * Short lead times Đ cylinders have a relatively simple design and can be fabricated in a matter of weeks. * Easier to maintain Đ can take one vessel offline and not affect system performance significantly. * Easier to replace Đ replacing a cylinder is a relatively simple process and a replacement can be sourced in a matter of weeks. * Easy to install Đ horizontal cylinders can be a readily available storage solution due to a lack of complex vertical supporting structures. * Large footprint required Đ horizontal cylinders require approx. 2x the amount of land as spheres and vertical cylinders. * Larger number of tanks Đ approx. 1.5x the number of tanks required compared with spheres. * Large amount of interconnecting piping required, due to the larger overall footprint. To finalise the evaluation, the storage types were analysed using a traffic light comparison (Table 10). The conclusion was that spheres represent the best storage option. Horizontal bullets were excluded due to their substantial land footprint, and vertical bullets were excluded because of the extensive interconnected piping needed, as well as the maintenance and construction challenges. Table 10: Types of storage tanks: traffic light comparison Source: Wood and GHD (2024) Traffic light comparison (6 Mtpa) Sphere Vertical bullet Horizontal bullet Comments Footprint 27,500m2 21,600m2 37,800m2 Footprint of the horizontal bullet would likely be too large for the allocated space within the common user facility Construction and operations Preferred Greatest concerns Increasing issues Bullets present a tight construction working space and significant maintenance and leak path challenges Quantity of tanks required 12 40 16 Spheres have the lowest quantity of tanks required, reducing the amount of interconnecting piping and associated equipment needed Heat ingress Lowest Highest Mid Low heat ingress results in lower energy required to refrigerate the storage tanks Lead times Possible concern = lowest = lowest Time is not seen as a constraint Containment failure Largest impact Lowest impact Lesser impact Spheres have the largest release from storage failure and largest loss of storage capacity from a single failure. Quantitative Risk Analysis required to assess the issue Transport to site prefabricated Uses module offloading facility only Uses module offloading facility or roads; highest no. of loads Uses module offloading facility or roads All options can be transported prefabricated and can fit within the limits of the module offloading facility, but spheres cannot be transported by road Outcome Go No go No go Spheres are the preferred storage type Spheres can accommodate the entire volume of LCO2 from a single shipŐs cargo, while also providing a minimum surplus capacity. The concept design study is based on a total working volume of 150% of the cargo size (40,000 m?) for the 3 Mtpa scenario, requiring six cryogenic spheres of 10,000 m? each, with an internal diameter of 27 m, at the common user storage facility. It is common for projects to set the working volume at 120?150% of the cargo size. In a future phase of the project, discrete event modelling could identify potential reduction opportunities in the working volume. For the 6 Mtpa expansion scenario, the larger shipping size of 80,000 m? results in a need for six additional spheres, providing a total storage capacity of 120,000 m? (Figure 14). Each storage sphere would be equipped with a self-contained boil-off gas refrigeration system to manage any issues that necessitate the suspension of exports. As such, they can store LCO2 indefinitely. BOG = boil-off gas Figure 14: Notional concept-level process flow diagram for 5 Mtpa LCO2 receiving and storage terminal Source Wood and GHD (2024) 3.3.4 Pipelines The imported LCO2 is expected to be exported in a supercritical or dense phase from the CO2 compression facility through a pipeline to the tie in-point. However, an alternative option was considered as part of the concept design. The relevant design pressures and temperatures are summarised in Table 11. Table 11: Design pressures and temperatures for LCO2 pipeline Source: Wood and GHD (2024) Parameter Jetty pipeline Storage sphere Low pressure transfer pipeline to CCUS* Export pipeline LCO2 Transfer Gas balance line Pressure 13.5 barg 8 barg 10 barg 33 barg 150 barg Temperature -46ĄC -37ĄC -60ĄC 2.2ĄC 5ĄC *Required in case final export compression occurs in Area G (Figure 13). Two options are considered: base case is direct export of CO2 from common user storage facility to export pipeline tie-in location; alternative is low-pressure transfer to Area G for final compression and export. Import pipelines The CO2 will be offloaded in liquid phase through two lines from the import vessel moored at Berth 3 to the storage tanks located in the CO2 receiving facility. A vapor balance line is required to facilitate the transfer of CO2 gas back to the import vessel, allowing the vessel to completely empty its tanks. Loading operations occur only when the vessel is berthed, making the loading intermittent. Table 12 lists the design parameters for the loading line and vapour return line. The offloading rate of the pipelines is 3,000 m3/hr. This enables the system to offload a 40,000m3 vessel in approximately 12 hours, and an 80,000m3 vessel in approximately 24 hours. Process design of the facility incorporates a keep-cold loop on the import offloading lines, a boil- off gas recovery system featuring a cascade refrigeration design, ship vapour return pumps, ambient air heaters and high-pressure export pumps (Figure 14). The design of all pipeline systems accounts for the material considerations held with CO2 transport and the necessary provisions for pipeline facilities such as pigging and metering. The two offloading pipelines are sized at 508 mm OD and the vapour return line at 356 mm OD. The export line is sized at 457 mm OD, to cater for the 6 Mtpa capacity. The selected material for all pipelines is X65 (Table 12). The increase in diameter of the export pipeline from DN 400 mm to DN 450 mm is the main difference between the 5 Mtpa and 6 Mtpa throughput capacity. Table 12: Design parameters for loading and return lines Source: Wood and GHD (2024) Description Value Unit Twin CO2 loading line design parameters Flow rate 1,731,528 kg/hr Design inlet pressure Design inlet temperature 13.5 -48 barg ĄC Distance from jetty to common user facility 1.48 km CO2 offloading linepipe properties: 2 x off 508 mm OD ? 15.1 mm (SCH 40), carbon steel X65 Insulation: polyurethane foam 150 mm Corrosion allowance 1.0 mm Vapour return line design parameters Flow rate 69,022 kg/hr Design inlet pressure Design inlet temperature 8.0 -37 Barg ĄC Distance from jetty to common user facility 1.48 km CO2 offloading linepipe properties: 356 mm OD ? 7.92.1 mm (SCH 20), carbon steel X65 Insulation: polyurethane foam 100 mm Corrosion allowance 1.0 mm Layout and CO2 export options Figure 15 shows the proposed route for the high-pressure CO2 export line in magenta, located within the pipeline corridor between Areas D and E, alongside Spitfire Road. This location may present a potential hazard and safety risk, because the areas surrounding the corridor (Areas D and E) may host gas-based industries and be classified as major hazard facilities, and the pipeline corridor already contains export lines for hydrocarbon and/or hydrocarbon products. As such, several other layouts were also evaluated (Figure 15). Further, more detailed design is required on the export pipeline routes as part of pre-FEED and FEED design. Figure 15: The proposed route for the high-pressure CO2 export line is shown by the solid magenta line, with an alternative route shown by the magenta dotted line. Alternative option CO2 receiving a storage pipeline to central compression facility shown in light blue. Source adapted from Wood and GHD (2024)) An initial screening exercise assessed several CO2 export options (Table 13). These options assumed a 6 Mtpa capacity. The reasoning behind this assumption is that there is minimal additional cost to install the larger pipelines compared with the benefit of avoiding the costs of future installations of additional or larger pipelines, especially in pipeline corridors carrying other products that potentially could lead to scheduling, cost and safety challenges. Based on the outcomes of the screening exercise, options 1 and 5 were selected for consideration in the concept design. A summary of design parameters for each of these options is provided in the sections below. Table 13: Options investigated for screening exercise Source: Wood and GHD (2024) Explanation Base case option: export pipeline * Transfer lines take LCO2 from the import vessels to the storage tanks located in the common user facility. * All processing is undertaken at the common user facility. * The export pipeline transports supercritical CO2 (150 barg, 5ĄC) from storage tanks at the common user facility to the tie-in point at INPEX Access Road Junction. This is shown in magenta in Figure 15. Selected for further investigation Alternative case option: low-pressure transfer of gaseous CO2 to Area G (Option 5) * Transfer lines take LCO2 from the vessels to the storage tanks located in the common user facility. * The LCO2 from the storage tanks is heated to a gaseous phase using a closed-loop heat exchanger taking heat from the air, so energy consumption is minimal. It is then compressed to 35 barg. * The transfer pipeline takes CO2 gas from the storage tanks to Area G. As the gas is transferred at ambient temperature, its condition is stable in the event of a shutdown. This is shown in light blue in Figure 15. * Compression and cooling of the gas to a supercritical state happens at Area G. * The export pipeline transports supercritical CO2 from Area G to the tie-in point at INPEX Access Road Junction. This is shown in yellow in Figure 15. * Larger energy demand to compress CO2 to 150 barg Considered to be the best alternative to the base case Base case option: export pipeline In the base case, CO2 is exported in a dense phase (150 barg, 5ĄC) directly from the common user facility to the specified tie-in point at the INPEX Access Road Junction via pipeline (Figure 15). The fluid travels from the heaters at the storage facility through a custody transfer metering skid and into a 4.5 km DN450 dense-phase pipeline (Table 14). The pipeline inlet is equipped with a pig launcher to enable intelligent pipeline condition monitoring. A matching pig receiver is installed at the tie-in point to the third-party pipeline. This pigging system enables regulatory-mandated internal inspections at nominal 5-yearly intervals. Given that the CO2 does not contain any water or other liquids, operational pigging is not required, and internal corrosion is not expected. The pipeline is buried throughout the entire length of the corridor. It is protected from external corrosion by a three-layer polyethylene coating and anodes. Alternative option: low-pressure transfer of gaseous CO2 to Area G For the alternative option, one possibility is to transfer the CO2 in a gas phase from the common user facility to a compression and export facility in Area G, where it is compressed and exported in a dense phase to the nominated tie-in point at the INPEX Access Road Junction. The gas-phase transfer CO2 pipeline will be buried for the majority of the route (Figure 15). Three-layer polyethylene coating and anodes protect the pipeline from external corrosion (Table 14). Table 14: Design parameters for the base case dense-phase pipeline and alternative low-pressure transfer pipeline Source: Wood and GHD (2024) Description Value Unit Base case option: dense-phase pipeline Flow rate 714,285.8 kg/hr Design inlet pressure Design inlet temperature 150 5 barg ĄC Distance from common user facility to third party tie-in 4.5 km Dense-phase export pipeline: 457 mm OD x 11.1 mm (SCH 30), carbon steel X65 Coating: three-layer polyethylene corrosion coating and anode bed (buried line) Corrosion allowance 1.0 mm Alternative option: low-pressure transfer pipeline to MASDP compression station Flow rate 714,285.8 kg/hr Design inlet pressure Design inlet temperature 35 5 barg ĄC Distance from common user facility to third party tie-in 2.25 km Low-pressure transfer pipeline: 457 mm OD x 11.1 mm WT, carbon steel X65 Coating: three-layer polyethylene corrosion coating and anode bed (buried line) Corrosion allowance 1.0 mm While Option 5 provides a reduction in the risk profile in the pipeline corridor along Stirling Road, when the LCO2 industry is assesses in combination with the MASDP Balanced Scenario industries, there is no observable change in the risk profile. 3.3.5 Export processing The CO2 stream must undergo treatment before being pumped from the storage tanks to the pipeline. Base case option: CO2 pumping and heating In the base case, the treatment process includes pumping the CO2 to the required export pressure of 150 barg and subsequently heating the compressed fluid from its storage temperature to approximately 5ĄC. In this system a booster pump withdraws LCO2 from storage and raises the pressure from 7 barg to 35 barg. The pressure is then further increased to 150 barg by the export pumps. This two-stage pumping process is essential because the pumping conditions of the liquid are close to its bubble point. The condition of the exported gas, which is supercritical at 150 barg, will be set by the downstream operator. Alternative option: CO2 vaporisation In the alternative option, the LCO2 is initially pumped to 35 barg and then vaporised into gas at the common user facility. A gas pipeline then transports this vaporised CO2 to Area G, where it is compressed to a supercritical state (150 barg) and exported through another pipeline to the nominated tie-in point. 3.3.6 Operational capacity considerations In both the base case and alternative export pipeline options, the pressure of the LCO2 is increased to 35 barg using booster pumps which are designed as 3 x 50% units. Two pumps are required to transfer 3 Mtpa. These pumps will be equipped with variable-frequency motor drives. Using a single pump the system capacity can be reduced to 1.5 Mtpa with a lower running cost. By reducing the speed of the running pump, it is possible to achieve lower flow rates. In the base case, variable-speed reciprocating export pumps are responsible for pumping the LCO2 to a supercritical state. Positive-displacement type pumps are selected for exporting the CO2, as there is no correlation between the flow rate and pressure in this type of pumps, and they can maintain low throughputs at high efficiency. The minimum operational capacity is determined by the performance of the booster pumps, which will be specified in the detailed design stage. The arrangement presented can achieve a minimum operational capacity of 0.5?1 Mtpa. If a lower rate is required, the booster pumps would be specified as 4 x 33% units instead of 3 x 50%. For the elements of the onshore export pipeline with only imported CO2 flows, if flows fall below the minimum allowable level, it will require a stop-start operation for the export pipeline. Although this is achievable, it is not ideal because it requires isolating both the spheres and the export pipeline while venting the cryogenic LCO2 within the intermediate export processing equipment. The export pipelineŐs inventory does not require venting since it is maintained in a supercritical or dense state, at or near ambient temperature, based on the selected option. 3.3.7 Power requirements It is assumed that the domestic electrical grid (or similar infrastructure) will provide all the power for the LCO2 marine receiving and storage terminal. For the base case, the power requirement is up to 6 MW for the initial 3 Mtpa case, increasing up to 11 MW when it is further developed to 5 or 6 Mtpa capacity. The alternative option requires up to 14 MW for the initial 3 Mtpa case and up to 32 MW for the 5 or 6 Mtpa expansion stage. This shows the inefficiency of the alternative option over the base case. The main reason for this inefficiency is the greater heating demands at the common user facility and the two-stage compression process at Area G. It should be noted that these power estimates do not include the import vesselsŐ offloading pumps, which are assumed to be powered by the vesselsŐ engines. It is assumed that a backup generator, supported by an uninterruptible power supply, will provide all the required power in case there is a grid power outage. 4 Integration with CO2 export pipelines The Darwin and Ichthys LNG facilities already capture CO2 as part of the requirement to remove CO2 from natural gas prior to export. The Ichthys facility currently captures ~2.3 Mtpa of CO2 (reporting year 2020?21; (INPEX, 2022a) and it is expected that on completion of the life extension of Darwin LNG that ~2.3 Mtpa CO2 will be captured at the Darwin facility (Wilson, 2022). It is anticipated that over their operational lifetimes, and assuming that CO2 storage is available, that captured CO2 volumes available for storage will increase. Upgrade works will occur at these facilities for CO2 gas conditioning (e.g. dehydration of CO2) and compressor installation. It is envisaged that CO2 will be exported from each of these facilities in a dense phase at the required pressures for transport to the offshore storage facilities (see section 5). The CO2 exported from these facilities is anticipated to enter a common export pipeline interface that will permit CO2 to be exported to both the Bayu-Undan depleted field CO2 storage/sequestration site and to one or more Bonaparte CCS saline aquifer storage/sequestration sites. The design of this system and planning for offshore sequestration locations, involving several industry participants, is currently underway. The pipeline interface system schematic process flow diagram has been provided by INPEX and is shown in Figure 16. The pipelines and system components are also shown in a map view in PL = Pipeline Figure 17. The pipeline interface system envisages a high-pressure dense-phase pipeline connection between the INPEX and Santos facilities (onshore CCS pipeline project and Ichthys LNG Cadastral boundary in Figure 16, yellow onshore interconnector pipeline in Figure 20). At each end of this pipeline will be fiscal meters, valves vents and pigging facilities. The pipeline interface system includes a tie-in point at interface point 2 in the approximate proposed tie-in location for the LCO2 terminal CO2 export pipeline. A Bonaparte CCS tie-in point is envisaged close to the easement associated with the existing Ichthys gas import pipeline at the proposed location of the CCS onshore station. This location provides a pass-through tie-in point for a second MASDP CO2 pipeline associated with CO2 export from the central MASDP compression facility. The Bonaparte CCS onshore station connection to the offshore pipeline includes further pigging, fiscal meters, valving and venting facilities. It is assumed that the pipeline interface system including interfaces 1, 2 and 5 will have sufficient capacity to manage existing and future CO2 volumes from both Ichthys LNG and the CO2 import terminal. Additional overall interface pipeline capacity will be incorporated through the pipeline between interfaces 3 and 4 (assuming that addition Bonaparte CCS storage capacity is available). The CO2 export pipeline from the Santos facility will, in principle, reuse the existing Bayu-Undan natural gas import pipeline so will not require new shore crossings or pipelines through Darwin Harbour. The CO2 export pipeline for the Bonaparte CCS is envisaged to use the same shore crossing easement corridor as the existing Ichthys natural gas pipeline, with the new CO2 pipeline following the route of the Ichthys natural pipeline as far as the offshore storage location in the Petrel Sub-basin (see section 5.2). Figure 16: Interface schematic. Source: INPEX PL = Pipeline Figure 17: Related value chain scope Source: INPEX 5 CO2 storage locations Geological storage of CO2 is an established operation in subsurface engineering, with sites such as Sleipner in Norway operating for more than 30 years (see the Task 4 report (Stalker et al., 2024)). Potential sites must have a suitable deep geological formation where the CO2 will be injected via injection wells and retained in the subsurface formation, isolated from the atmosphere for millennia (Herzog et al., 2003; Metz et al., 2005; Ringrose, 2020; Tucker and Tinios, 2017). Storage mechanisms The phase state of CO2 impacts its storage potential. Pure CO2 is a supercritical fluid above a temperature of 31.1oC and a pressure of 7.39 MPa, conditions that generally occur at subsurface depths below ~800 m. Phase behaviour is affected by the purity of the fluid (see Figure 18). The relative density increase from gaseous CO2 at 100 kg/m3 to 400?750 kg/m3 optimises storage volumes (CO2CRC, 2024). Supercritical CO2 has the viscosity of a gas but has a density lower than freshwater, creating the potential buoyancy-driven migration requiring adequate trapping mechanisms to ensure it remains in storage. Figure 18: Phase envelope for CO2 fluids Source: Lim et al. (2024) CO2 storage can be secured using a variety of different trapping mechanisms. Injected CO2 is trapped by geological structures and sealing rocks (structural trapping), and over time an increasing amount is immobilised by residual trapping, dissolution into brine (solubility trapping) and reactions with the rock matrix (mineral trapping) ? see Figure 19 * In structural trapping, free-phase CO2 is trapped by buoyancy in a closed structure below a low permeability seal, in a manner similar to naturally occurring oil or gas. In this way, CO2 accumulations can remain preserved for millions of years. * In residual trapping, small bubbles of CO2 remain trapped in the centre of the pore spaces within the rocks by imbibition of formation water and become immobilised. The bubbles form during the movement of supercritical CO2 through the reservoir rock. Capillary forces arise between the CO2, which is a non-wetting phase, and the saline formation water, which is the wetting phase more closely in contact with rock surfaces. * In solubility trapping, CO2 that is injected into a saline aquifer gradually dissolves into the formation water. This CO2-enriched water is slightly denser than the surrounding water and buoyancy forces induce it to migrate downwards and mix with the formation water throughout the reservoir volume. * In mineral trapping, CO2 that has been contained for a long period (hundreds to thousands of years) may, if the mineralogy of the reservoir rock is suitable, react to precipitate new minerals, which lock up the carbon permanently. Figure 19: Schematic showing the relative importance of CO2 trapping mechanisms over time Source:?IPCC (2005) 5.1 Bayu-Undan reservoirs Santos, as operator on behalf of the joint venture3, has announced an intention to use the depleted Bayu-Undan hydrocarbon fields as a CO2 storage location. The Bayu-Undan gas field, which began production in 2006, transitioned from LNG to domestic gas production on 30 November 2023 after nearly 3 Tcf of production. The subsurface is well understood: the reservoir is a structural trap with an extensive aquifer for pressure support. With high permeability and historical gas injection (of 1 Bcf of gas per day during the gas cycling phase of production) proving injectivity, it is expected to be able to store up to 10 Mtpa of CO2 for more than 20 years (Santos, 2023b). The project entered the FEED phase in the second quarter of 2022 to use the depleted reservoir for CO2 storage. The project is designed to reuse existing infrastructure such as the export pipeline, offshore platform and wells, but will need additional facilities for capture and export. Initially ~2.3 Mtpa of CO2 will be injected from the Barossa Field (Wilson, 2022). Santos announced on 3 May 2023 that four non-binding memoranda of understanding have been signed for proposed storage of CO2 emissions by third parties at Bayu-Undan (Santos, 2023c). While the projects have not been named, should all four memoranda be converted to binding agreements they indicate that demand for storage at Bayu-Undan will be in excess of the proposed pipeline capacity of 10 Mtpa. Santos has announced further memoranda of understanding with Timor-LesteŐs regulator, Autoridade Nacional do Petroleo e Minerais (ANPM), and the national oil company, TIMOR GAP, to assess local opportunities and the regulatory framework, and explore partnership opportunities ? these show a desire to facilitate development of the Bayu-Undan CCS (Santos, 2021; 2023a). One additional memorandum of understanding with SK E&S, K-CCUS Association, CO2CRC and Korea Trade Insurance Corporation to support and collaborate in the development carbon storage facilities including Bayu-Undan CCS Ňopens the potential for broader bilateral partnership and cooperation on CCS between Australia and KoreaÓ (Santos, 2022b). Figure 20 illustrates the proposed Bayu-Undan CCS project (Santos, 2022a). Figure 20: Schematic of Bayu-Undan CCS project Source: Santos (2022a) Construction of the project will include onshore compression and dehydration facilities. CO2 will be transported through the existing Bayu-Undan production pipeline to the Bayu-Undan offshore platform, where three injection wells (with potential for three additional/alternative wells; Figure 21) will be used for the CO2 injection. A further two repurposed gas production wells are nominated as potential observation wells. Figure 21: Conceptual offshore plan for Bayu-Undan CCS Source: Wilson (2022) Outside of scope of the CCS project will be modifications to the Darwin LNG plant, which will be included in the Darwin LNG Life Extension project to accommodate a different specification for natural gas feedstock. This will include replacement of the existing acid gas thermal oxidiser and amine system upgrades that support CO2 removal from the gas stream. Additionally, a ~100 km section of the offshore pipeline will be duplicated to allow for the Barossa-Caldita gas delivery to shore. 5.2 Petrel sub-basin In 2009 the Carbon Storage Taskforce issued a report and plan to analyse the potential of carbon storage locations around Australia (Carbon Storage Taskforce, 2009). Initial probabilistic modelling indicated that the Northern Territory side of the Petrel Sub-basin within the Greater Bonaparte Basin had a potential P10 storage capacity of 88.0 Gt and a P90 storage capacity of 32.2 Gt. P10 resents the 10th percentile that capacity estimates will exceed this value (lowest value). Whereas P90 is the 90th percentile of estimates will exceed the capacity estimates (highest value). Onshore basins within the Northern Territory were not considered during this assessment. A 2014 Geoscience Australia report (Consoli et al., 2014) focused on two Mesozoic-aged saline reservoir-seal pairs located over the central and eastern flank of the basin. Dynamic reservoir simulation showed that the dominant CO2 trapping mechanism in the Petrel Sub-basin is migration-assisted trapping, consisting of residual and dissolution trapping. Potential storage in the Petrel Sub-basin was modelled with a P50 estimate of 15,930 Mt (300 Tcf) and is illustrated in Figure 22 . The report concluded that the Petrel Sub-basin is suitable for the geological storage of CO2, although with a somewhat lower capacity than the earlier estimate. Figure 22: Petrel Sub-basin CO2 storage potential Source: Geoscience Australia (2014) Investigations by Shell, ENI and CSIRO, supported by funding from the Australian Commonwealth and reported by Johnstone and Stalker (2022), provided further geological appraisal and derisking for CO2 storage in the eastern part of the Petrel Sub-basin. Two greenhouse gas storage permits have been issued in the Petrel Sub-basin from AustraliaŐs 2021 Offshore Greenhouse Gas Storage Acreage Release (see Figure 23). Figure 23: 2021 Greenhouse Gas Permits Acreage Release, Petrel Sub-basin Source: DISR (2021) In the eastern sector of the basin, permit GHG21-1 was awarded in August 2022. Operated by INPEX, the permit covers 27,550 km2 and includes the prospective area illustrated in Figure 24. Other joint venture partners are TotalEnergies CCS Australia and Woodside Energy. The Bonaparte CCS project is currently drilling, coring and testing two wells in the permit to assess possible injection of supercritical CO2 into the Plover saline aquifer at a depth of ~2,000 m. The project proposes to start injecting CO2 at a rate of 2 Mtpa from the Ichthys onshore LNG processing facility, with potential expansion to 7 Mtpa (INPEX, 2023). Figure 24: G-7-AP permit location over GHG21-1 Source: INPEX (2022b) Bonaparte CCS development schematics (Figure 25) show the potential initial development and possible expansion. The initial development includes a circa 250 km subsea pipeline to the storage location with subsea installations and two to three initial injection wells. Expansion concepts contemplate more than 10 injection wells via multiple wellhead platforms/injection systems served by additional CO2 export pipelines. Figure 25: Bonaparte CCS development schematic Source: Grainger and Ovenden (2023) In the western sector of the basin, area G-11-AP over GHG21-2 was awarded in September 2022. Operated by Santos, the permit spans 26,239 km2 (Figure 26). Other joint venture partners are Chevron Australia and an affiliate of SK E&S. Appraisal drilling in this permit is planned, with the first of three wells, Astraea-1, scheduled in 2025 (Santos, 2024). A 3D seismic survey (Eos 3D) is also scheduled to commence at the end of 2024 and run until the end of 2026. Figure 26. GHG21-2 permit location over G-11-AP. Source: Santos (2022c) Onshore reservoirs CSIRO and the Northern Territory Geological Survey have recently completed a screening assessment into the storage potential of various onshore basins (Amadeus, McArthur, Bonaparte, Georgina and Ngalia) for CO2, hydrogen and compressed-air energy storage The basins were assessed for their suitability for CO2 storage of 1 Mtpa for 25 years, injectivity, level of knowledge, containment and distance to CO2 sources (Talukder et al., 2024). Based on these, rankings of the top five plays for onshore CO2 storage are: northern onshore Bonaparte Basin (Kulshill Group); the two younger sandstones (Moroak) of the Beetaloo Sub-basin, part of the McArthur Basin; parts of the northern Georgina Basin near the Queensland border (Kiana group); and the Palm Valley and Ooraminna fields in the Amadeus Basin. These locations will require further acquisition of targeted data to reduce geological uncertainty and understand economic feasibility. 6 CCUS system: indicative cost estimates The indicative costs of the MASDP CCUS system have been developed by the NT-DIPL in two studies (GHG Wood Group (2023) and Wood and GHD (2024)), which include estimates of both capital and operating costs from upstream (point of CO2 capture) to downstream (export of CO2 into the MASDP export pipelines). These cost estimates are summarised below. For clarity, these are high-level estimates only and are subject to large uncertainties ? much more detailed study is required to more accurately define the costs. The purpose of this section is to identify the key cost components of the CCUS hub within the system design, and how these costs could be broken up and staged. This will help pinpoint approaches that could be employed to minimise upfront costs while maximising future CCUS hub development options. This extends the discussion in earlier sections on staged development strategies and cost efficiencies. The cost estimates do not include costs for the Darwin or Ichthys LNG CCS facilities, nor for the pipeline interface system and offshore/storage components. These costs are commercial-in-confidence and were not made available to CSIRO. However, it can be assumed that they will be significant. 6.1 CCUS system capital cost estimate The largest component of the cost to develop a CCUS hub is associated with the capital equipment. The capital expenditure (CapEx) required for the project components was estimated by GHG Wood Group (2023) as the total installed cost, based on the Association of Advancement Cost Engineers (AACE) International estimate classes. Based on the stage of the design definition, costs were estimated according to the AACE International class 5, which includes the characteristics shown in Table 15. The list of assumptions used in the cost estimation process is summarised in Table 16. Table 15: Characteristics of class 5 cost estimate Source: GHG Wood Group (2023) Parameter Value/Description Design definition <~2% Typical purpose/end usage of estimate Screen or feasibility Methodology Stochastic (factor and/or models) Accuracy range Low: -20% to -50% High: +30% to +100% Table 16: Cost estimate assumptions Source: GHG Wood Group (2023) Parameter Value/Description General Normal economic and industry circumstances Q4 2022 real terms; escalations allowances excluded Ł to A$ 1.8 Growth 0% Contingency 30% Lang factors CO2 Capture = 4.537 CO2 Compression = 2.893 The cost of the components of the CCUS system include estimates of: * design and project management * approvals and right of way * equipment procurement * bulk procurement * fabrication * site construction * commissioning * ownerŐs cost allowances. All the cost estimates include a 30% contingency. 6.1.1 CO2 capture facilities capital cost estimate Costs for CO2 capture and compression facilities have been included for each industry type in the Balanced Scenario based on their estimated CO2 emissions (Table 17). The costs of capture for each industry identified in the GHG Wood Group (2023) study are assumed to be the cost of all capture facilities for each industry. As highlighted in section 3.1, many of these costs may be unavoidable/embedded process costs for the industry (e.g. pressure swing adsorption/AGRU separation of CO2 from hydrogen in SMR, or the use of AGRU systems for capturing reservoir gas CO2 during LNG production), whereas in other industries (e.g. spodumene processing for lithium hydroxide) CO2 capture would represent an additional cost to normal process operations. This is an important consideration, as the cost of capture is either a cost factored into standard operations or represents an additional cost to industries. It is assumed that the costs of conditioning and compressing CO2 comprise additional cost for all industries located in the MASDP. As this was a concept design, cost estimates for CO2 capture and compression facilities were driven by historical costs of CO2 capture and compression equipment. Specifically, they reflected cost data captured between 2018 and 2021 from projects in the UK. Inflation, location factor and foreign exchange have been applied to normalise these costs for 2022 work in Darwin. Engineering design and project management team, bulk procurement, fabrication, construction, commissioning and ownerŐs costs have been factored against equipment procurement. Different Lang factors4 have been applied for the capture and compression facilities given that compression equipment procurement costs will be higher (with lower bulk procurement costs) than capture equipment procurement costs (higher bulk procurement costs). Table 17: CCUS-related cost estimates for the expected industries in the MASDP Source: GHG Wood Group (2023) Item CO2 capture ($Ő000s) CO2 compression ($Ő000s) Total ($Ő000s) Methanol plant carbon capture and compression $192,217 $85,688 $277,905 Condensate refinery/GTL plant carbon capture and compression $543,169 $36,946 $580,115 LNG plant carbon capture and compression $1,312,136 $97,370 $1,409,505 Blue hydrogen plant carbon capture and compression $736,818 $120,119 $856,937 Ammonia plant carbon capture and compression $537,137 $125,386 $662,522 Urea plant carbon capture and compression $1,001,772 $78,315 $1,080,087 Ethane cracker plant carbon capture and compression $709,708 $58,434 $768,142 Ammonia phosphate plant carbon capture and compression $116,516 $8,292 $124,807 Lithium hydroxide plant carbon capture and compression $133,757 $9,493 $143,250 Carbon capture network CapEx total $5,283,228 $620,042 $5,903,273 6.1.2 Onshore pipelines cost estimate The cost estimate for the header and export CO2 pipelines (Table 18) is based on the layout shown in Figure 9. The export pipeline connects the CCUS hub to the main export pipeline tie-in point south of the INPEX Ichthys facility (4 km). For the possible export pipeline tie-in to the pipeline interface system to the north close to the Ichthys gas import shore crossing location, this distance would be increased to ~7.4 km. A prorated cost of $7.15 million $/km to account for the additional distance would increase the $28.6 million cost to $53 million. However, some pipeline costs such as design and approvals are unlikely to scale linearly, so this cost will be conservative (notwithstanding the overall uncertainty associated with a class 5 cost estimate). For the actual tie-in infrastructure (e.g. valves, metering, pigging facilities), no specific cost allowance was included in the GHG Wood Group (2023) study. Collection header pipelines connecting each proponent facility to the CCUS hub have been costed on the basis of the whole header pipeline system being installed, but with each pipe diameter costed separately (Table 18). Table 18: Summary of the pipeline characteristics and cost estimate Source: GHG Wood Group (2023) Pipeline type Size Length Total cost ($Ő000s) CCUS hub export pipeline 600 mm OD 4.00 km $28,660 Collection headers (Areas A, H and I) 400 mm OD 5.48 km $29,834 Collection headers (Areas B, C, D and E) 800 mm OD 7.18 km $65,509 Assumptions Pipeline wall thickness 44.45 mm Steel density 7,850 kg/m3 Pipework allowance 200 m at the entry to each proponent lot 6.1.3 CCUS hub compression facility cost estimate The equipment lists and weights are not provided at the concept design stage so the cost estimate for the CCUS hub compression facility is driven by the estimated equipment cost using the Lang factor method. The cost estimate for the compression facility (Table 19) includes costs for compression only as each proponent area caters for the capturing of CO2 and low-pressure compression. When fully built to the ~9 Mtpa level, the CCUS hub will be serviced by three identical trains that each provide one third of the compression capacity of the facility. The compression facility costs can therefore be staged based on capacity need. However, the costs will not scale equally, with the first train including a larger proportion of total compression facility costs than the final train (discussed below). In the absence of a layout or plot plan of the CCUS hub area, tentative sizes were assumed for the required buildings. Building costs, although small compared with the other components, are also included in the estimates. Table 19: Summary MASDP CCUS hub compression facility cost estimate Source: GHG Wood Group (2023) Item Total cost ($Ő000s) CO2 compression hub $432,202 CCUS hub buildings $10,973 Total $443,175 6.2 LCO2 receiving and storage terminal capital cost estimate Based on the stage of the design definition, the LCO2 terminal capital costs were estimated according to the AACE International class 4, using the characteristics shown in Table 20 . A list of assumptions used in the cost estimation process is shown in Table 21. Table 20: Characteristics of class 4 cost estimate Source: Wood and GHD (2024) Parameter Value/Description Design definition 1% to 15% Typical purpose/end usage of estimate Study or feasibility Methodology Stochastic (factor and/or models) Accuracy range Low: -15% to -30% High: +20% to +50% Table 21: Cost estimate assumptions Source: Wood and GHD (2024) Parameter Value/Description General Normal economic and industry circumstances Q2 2023 real terms; escalation allowances excluded A$ to US$ 0.67 Growth 0% Contingency 30% The estimate was based on the reference equipment costs from analogous projects, and included the following cost structure: * design and project management * major equipment procurement * bulk procurement * site construction and commissioning. Both the 3 Mtpa base case and the 6 Mtpa expansion case will use the same components, the only difference being the quantity. A large amount of the process equipment for the 3 Mtpa case will be sized to handle the requirements of the 6 Mtpa case where modular expansion is required. The capital cost estimate for the base case is presented in the Table 22. It should be noted that the storage tank spheres constitute more than half of the cost estimates in both the initial and expansion stages. Table 22. Base-case CapEx estimate for LCO2 import facility. Increase to 6 Mtpa at additional $10 million Source: Wood and GHD (2024) Parameter Total cost ($Ő000s) 3 Mtpa LCO2 system total $478,677 Expansion to 5 Mtpa Đ additional plant at common user facility $366,483 5 Mtpa LCO2 system total $845,160 Table 23 shows the CapEx summary for the alternative CO2 vaporisation option. The initial 3 Mtpa phase is estimated to cost $555.8 million, 16% more than the base case CO2 pumping and heating option. The full alternative 5 Mtpa development is estimated to cost $991.1 million, 17% more than the base case. Table 23. Alternative CO2 vaporisation option (gas export from common user facility) CapEx estimate Source: Wood and GHD (2024) Parameter Total cost ($Ő000s) 3 Mtpa LCO2 system total $555,832 Expansion to 5 Mtpa Đ additional plant at common user facility $435,317 5 Mtpa LCO2 system total $991,149 6.2.1 Increase operational capacity from 5 Mtpa to 6 Mtpa The CapEx required to increase throughput from 5 Mtpa to 6 Mtpa is estimated at $10 million. To achieve the 6 Mtpa throughput capacity, the export pipeline needs to be increased in size and the handling facilities at the common user facility require some modification. The import pipelines, tank storage and boil-off gas facilities remain unchanged. At the common user facility, the 3 Mtpa equipment can be duplicated, which avoids the need for brownfield adjustments to the high-pressure export pumps and other equipment. The high-pressure export pumps are rated at 1,722 kWe for the 3 Mtpa and 6 Mtpa cases, and 1,433 kWe for the 5 Mtpa case. 6.3 Operating cost estimate Operating expense (OpEx) estimates are taken from the two GHG Wood Group (2023) and Wood and GHD (2024) studies and follow the AACE International class 5 cost for the CCUS hub and class 4 cost for LCO2 receiving and storage terminal. As such, OpEx is estimated based on a percentage of the capital costs using benchmarking analysis. 6.3.1 CCUS hub For a processing plant, the OpEx is estimated at ~6% of the capital cost. For pipelines, the OPEX is lower at ~3% of the capital cost. However, for simplification purposes GHG Wood Group (2023) assumed the whole of the CCUS hub to have an OpEx calculated at 5% of overall CapEx, or $324 million/year when fully developed. 6.3.2 LCO2 import and storage facility For the LCO2 import and storage facility, the OpEx is adjusted lower, as there is an overweight investment cost in the storage tank spheres. The OpEx allowances are: * General facilities 6% (base case option) 7% (alternative option) * Storage tank spheres 3% * Pipelines 3% The OpEx for the base case option is estimated at $21.0 million/year for the 3 Mtpa initial case and $36 million/year for the 5 Mtpa or 6 Mtpa development. For the alternative option, the OpEx is estimated to be $28.3 million/year for the 3 Mtpa initial phase, an increase of 35% over the base case, and $49.1 million/year for the 6 Mtpa full development. The alternative option operating costs are materially higher as there is more equipment across two locations. For example, power demand increases from 5.6 MW for the base case to 13.7 MW for the alternative option (option 5) (3 Mtpa throughput) and from 10.7 MW to 31.8 MW (6 Mtpa throughput). 6.4 Proportional breakdown of costs When the costs are collated across the MASDP capture, compression, LCO2 import and CO2 export line elements of the CCUS system, they total $7.315 billion for the base option LCO2 and $7.940 billion for the alternative option for the LCO2 import facilities (Table 24). More than 70% of these costs are associated with the MASDP industry capture facility costs, with a further 8% associated with the conditioning and first-stage compression within the battery limits of these facilities (Figure 27). As described above, it is anticipated that much of the cost of the capture facility will already be a realised cost associated with the industrial processes within those industries. However, this represents a major uncertainty in understanding the additional costs that will be encountered by industry through the implementation of CCUS in the MASDP. The MASDP gather, compression and CO2 export lines represent less than 8% of total costs, whereas the LCO2 and the LCO2 import elements of the system represent 12?13% of total costs (Table 24, Figure 27). Consolidated operational costs amount to $360?$373 million/year assuming a full Balanced Scenario development (Table 25), noting that most of these operating costs are associated with the CO2 capture plants. Table 24: Capital costs of the MASDP CCUS system assuming full Balanced Scenario development Item Total costs ($Ő000s) Percentage of whole (base/alternative LCO2) MASDP CO2 capture facilities (industries)1 $5,283,228 72/71 MASDP CO2 compression (industries) $620,042 8/8 MASDP collection header pipeline $95,169 1/1 MASDP CO2 compression hub (inc. buildings) $443,175 6/6 MASDP CO2 export pipeline2 $28,660 <1/<1 LCO2 import facility 3 Mtpa (base option) $478,677 7/NA LCO2 import facility increment to 5 Mtpa (base option)3 $366,483 5/NA Subtotal (base option) $7,315,434 LCO2 import facility 3 Mtpa (alternative option) $555,832 NA/7 LCO2 import facility increment to 5 Mtpa (alternative option)3 $435,317 NA/6 Subtotal (alternative option) $7,461,423 1Total cost of CO2 capture without discount for CO2 capture costs realised as part of the processes. 2Assumes 4 km export pipeline only (see tie-in facility discussion above). 3Note that expanding the LCO2 import capacity to 6 Mtpa is estimated to cost $10 million. Table 25: Operating costs of the MASDP CCUS system assuming full Balanced Scenario development Item Total costs ($Ő000s) per year MASDP CO2 capture facilities (industries)1 $324,000 MASDP CO2 compression (industries)1 MASDP collection header pipeline MASDP CO2 compression hub (inc. buildings) MASDP CO2 export pipeline2 LCO2 import facility 3 Mtpa (base option) $21,000 LCO2 import facility increment to 5 Mtpa (base option) $15,000 Subtotal (base option) $360,000 LCO2 import facility 3 Mtpa (alternative option) $28,300 LCO2 import facility increment to 5 Mtpa (alternative option) $20,800 Subtotal (alternative option) $373,100 1Total cost of CO2 capture without discount for CO2 capture costs realised as part of the processes. 2Assumes 4 km export pipeline only (see tie-in facility discussion above). Figure 27: Proportional capital cost breakdown for the MASDP CCUS system assuming full Balanced Scenario development, using the base option LCO2 import facility costs 6.5 Development cost phasing It is assumed that not all phases of the MASDP development will occur simultaneously. As each industry is developed and CO2 capture facilities are required, then the capture, conditioning and low-pressure compression systems for each industry will be developed and the costs will be incurred. The phased development of the MASDP will also allow phased development of the associated CCUS system. Figure 28 and Table 26 illustrate potential phased development options for the MASDP CCUS hub system, excluding the costs of industry capture, conditioning and low-pressure compression. The lowest cost hub development option contemplates the installation of the 800 mm OD header pipeline and one compression train (estimated at 47% of the total cost of the compression facility). This would enable the transport and compression to dense phase of up to 3 Mtpa of CO2 with a total estimated cost of $307 million. To minimise cost-of-regret in a scenario where industry was yet to be developed but a future capacity for CO2 transport was to be enabled, these costs could be further reduced through the installation of the header pipelines and early works on the compression station being completed without the compressor procurement occurring (Figure 28 and Table 26). CSIRO estimates the compressor cost to be $47.2 million and as such this least cost option be reduced to $259.8 million. The 6 Mtpa hub development option contemplates the installation of all header pipelines and two of the compression trains (estimated at 73% of the total cost of the compression facility). This would enable the transport and compression to dense phase of up to 6 Mtpa of CO2 with a total estimated cost of $452 million. These costs increase to 9 Mtpa and $567 million with the three-compression train configuration (Figure 28 and Table 26). If the 3 Mtpa LCO2 import facility (12 Mtpa total capacity) is added, this increases the capital cost to just over $1 billion, and with the full LCO2 5 Mtpa import facility capacity (14 Mtpa total capacity) it brings the total cost to $1.4 billion, noting that for an additional $10 million this can become a 6 Mtpa import facility capacity (15 Mtpa total capacity) (Figure 28 and Table 26). The options outlined can be adapted to the predicted demand; for example, the first stage of the LCO2 import facility could be developed initially with further MASDP CCUS system being subsequently developed. Figure 28: Phased MASDP CCUS hub development capital cost options. White hatched area is the compressor cost for the lowest cost option. Note: As these are concept design costs they are subject to significant uncertainty Table 26: Phased MASDP CCUS hub development capital cost options Item ($000s) 800 mm OD headers 1 train compression All headers 2 train compression All headers 3 train compression All headers 3 train compression LCO2 3 Mtpa All headers 3 train compression LCO2 5 Mtpa Collection headers (Areas B, C, D and E) 800 mm OD $65,509 $65,509 $65,509 $65,509 $65,509 Collection headers (Areas A, H and I) 400 mm OD $ - $29,834 $29,834 $29,834 $29,834 CCUS export pipeline $28,660 $28,660 $28,660 $28,660 $28,660 Compression facility $202,4971 $317,3502 $432,202 $432,202 $432,202 CCUS hub buildings $10,973 $10,973 $10,973 $10,973 $10,973 LCO2 import facility 3 Mtpa (base option) $ - $ - $ - $478,677 $478,677 LCO2 import facility 5 Mtpa (base option)3 $ - $ - $ - $ - $366,483 Total ($Ő000s) $307,639 $452,326 $567,178 $1,045,855 $1,412,338 CO2 capacity 3 Mtpa 6 Mtpa 9 Mtpa 12 Mtpa 14 Mtpa 1CSIRO estimate of 47% of total compression facility cost. 2CSIRO estimate of 73% of total compression facility cost. 3To expand the LCO2 import capacity to 6 Mtpa is estimated to cost $10 million. 7 Conclusions This report provides a summary of the concept-level design and costing of the MASDP CCUS system and LCO2 receiving and storage terminal associated with the NT-DIPL Balanced Scenario. The report has relied heavily on the two studies from GHG Wood Group (2023) and Wood and GHD (2024), which have formed the majority of inputs. Further inputs have come from INPEX and from publicly released information. Concept-level designs and costings have inherent uncertainties as they represent the initial design before commencing more intensive analyses where risks and costs are evaluated in more detail. The report should be considered in this context, providing a high-level basis for a future detailed design. As this design matures and becomes more detailed, it will evolve. While the total system (i.e. including the offshore and Darwin and Ichthys LNG facilities) costs and detailed designs are not available at this time, design and development work is progressing collaboratively across all components of the NT LEH CCUS system. The interface pipeline systems, offshore pipelines and subsurface storage systems are being designed to carry and store the volumes of CO2 that may be available from the MASDP CCUS system and imported via a LCO2 receiving and storage terminal. Within the two GHG Wood Group (2023) and Wood and GHD (2024) studies no technical showstoppers have been identified for systems within the MASDP and global examples of each element of the system have been identified to establish the technical and cost basis. The cost estimates include both capital costs and operating costs derived as a proportion of the capital costs. Nearly three-quarters of the estimated capital costs of the MASDP CCUS system are associated with capture facilities. What proportion of these costs are embedded costs within the industry processes, versus additional costs, is a critical consideration in the overall development of the CCUS system. For example, CO2 capture occurs as part of the thermochemical reduction of methane to produce hydrogen, so this is an embedded cost. Conversely, the capture of CO2 from spodumene processing to lithium hydroxide is an additional cost compared with current industry practice. Further design and attribution of costs would be a logical next step to further understand overall system costs. It is assumed by CSIRO that in the GHG Wood Group (2023) study of the MASDP CCUS system, each industry generates its own products separately. While this approach reduces risk for individual proponents, it does not contemplate efficiencies that may be gained through sector coupling (see the Task 5 report (Czapla et al., 2024)), and therefore the number of emissions locations and estimated capital infrastructure costs may be conservative if sector coupling can be implemented. The capital costs of gas conditioning and low-pressure compression within the battery limits (the footprint of each MASDP industry) represent an additional cost beyond ÔunabatedŐ operations (over and above any capture costs). Further investigation of the models regarding who would own and operate these facilities is warranted. The capital costs of the MASDP CCUS hub (header pipelines, compression facility and export pipeline) represent (at $567 million) less than 8% of the total MASDP CCUS system cost assuming full development of the MASDP Balanced Scenario. The capital costs of the full development of the LCO2 (base option, 5 Mtpa) receiving and storage terminal taken from the Wood and GHD (2024) study is $845 million. Within both from GHG Wood Group (2023) and Wood and GHD (2024) studies, options and flexibility in the design of the MASDP precinct CCUS system and LCO2 receiving and storage terminal have been identified. These have flow-on effects to the costs associated with development of the precinct. CSIRO has used these options to explore phased development costs associated with the MASDP CCUS hub (header pipelines, compression facility and export pipeline to the INPEX/Santos pipelines) and LCO2 receiving and storage terminal. The least cost of the development providing up to 3 Mtpa of capacity is estimated at $307 million. Further reduction in costs could be achieved through installation of the header pipelines and early works on the compression station being completed without the compressor procurement occurring. References Carbon Storage Taskforce (2009) National Carbon Mapping and Infrastructure Plan - Australia: Full Report. In: Department of Resources EaT (ed.). CO2CRC (2024) Home Page. . Consoli C, Nguyen V, Morris R, Lescinsky D, Khider K, Jorgensen D and Higgins KL (2014) Regional assessment of the CO2 storage potential of the Mesozoic succession in the Petrel Sub-basin, Northern Territory, Australia: summary report. Geoscience Australia. CSIRO (2023) Opportunities for CO2 Utilisation in the Northern Territory. Australia. CSIRO (2024) A business case for a low-emissions CCUS hub in the Northern Territory. . Czapla J, Josh M, Clennell B, Ross A and Squiers I (2024) Northern Territory Low Emissions Carbon Capture Storage and Utilisation Hub: Sector Coupling Opportunities Đ Task 5 Report. CSIRO, Australia. DISR (2021) Bonaparte Basin: Petrel Sub-Basin. Department of Industry Science and Resources, Australian Government. . Dym C, Little P, Orwin E and Spjut R (2009) Engineering Design: A Project Based Introduction. New York. Geoscience Australia (2014) Understanding Northern Australia's Carbon Capture and Storage Potential: An Integrated Regional CO2 storage study. . GHG Wood Group (2023) MASDP WP26 - Carbon Dioxide Capture, Utilisation and Storage Report (CCUS). Grainger P and Ovenden S (2023) Success factors in the creation of a CCS Hub. The APPEA Journal 63(2), S379-S381. DOI: 10.1071/AJ22203. Green D, Graham P, Havas L, Browne G, Foster J, Hayward J, Reedman L, Khandoker T, Ross A and Rogers J (2024) Northern Territory Low Emissions Carbon Capture Storage and Utilisation Hub, Power Generation Options AnalysisĐ Task 7 Report. CSIRO, Australia. Herzog H, Caldeira K and Reilly J (2003) An Issue of Permanence: Assessing the Effectiveness of Temporary Carbon Storage. Climatic Change 59(3), 293-310. DOI: 10.1023/A:1024801618900. IEA (2024) IEA Home Page. . INPEX (2022a) Ichthys Project Offshore Facility (Operation); Environment Plan. . INPEX (2022b) INPEX-led Bonaparte CCS Assessment Joint Venture awarded acreage offshore Northern Territory in Australia. INPEX (2023) Integrated Report 2023. . IPCC (2023a) AR6 Synthesis Report: Climate Change 2023. Intergovernmental Panel on Climate Change. . IPCC (2023b) Climate Change 2023: Synthesis Report. Intergovernmental Panel on Climate Change. . Johnstone R and Stalker L (2022) The Petrel Sub-basin: a world-class CO2 storeĐmapping and modelling of a scalable and commercially viable CCS development. The APPEA Journal 62(1), 263-280. DOI: 10.1071/AJ21092. Lim N, Green B and Thomson Z (2024) Requalification of pipelines for CO2 transport Đ giving new life to the Bayu-Undan and Reindeer pipelines. Australian Energy Producers Journal 64(2), S270-S274. DOI: https://doi.org/10.1071/EP23111. Metz B, Davidson O, De Coninck HC, Loos M and Meyer L (2005) IPCC Special Report on Carbon Dioxide Capture and Storage. Cambridge. . NZA (2024) About Net Zero Australia. Net Zero Australia. . Ringrose P (2020) How to Store CO2 Underground: Insights from early-mover CCS Projects. Springer Cham. Rogers JL, Gee R, Ross A, Ironside M and Squiers I (2024) Northern Territory Low Emissions Carbon Capture Storage and Utilisation Hub. Northern Territory Economy, Industries and Emissions Đ Task 1 Report. CSIRO, Australia. Ross A, Ironside M and Gee R (2023a) The Northern Territory low-emissions carbon capture, utilisation and storage hub development Đ the collaborative business case development. The APPEA Journal 63. DOI: https://doi.org/10.1071/AJ22210. Ross A, Stewart M and Clifford A (2023b) Northern Territory Low Emission Carbon Capture Storage and Utilisation Hub, CCUS hub vison setting Đ Task 0 Report. CSIRO, Australia. Ross A, Stewart M, Richardson C and Clifford A (2022) Collaborative development of the Northern Territory low-emissions carbon capture, utilisation and storage hub Đ a blueprint for the rapid decarbonisation of Northern Australia. The APPEA Journal 62. DOI: https://doi.org/10.1071/AJ21185. Santos (2021) MOU signed on Bayu-Undan Carbon Capture and Storage. . Santos (2022a) Carbon Capture and Storage; Fact Sheet. . Santos (2022b) Santos and SK E&S sign MOU to develop CCS projects in Australia. . Santos (2022c) Santos awarded CO2 storage permits for more CCS opportunities. Santos (2023a) Bayu-Undan joint venture and TIMOR GAP sign MOU to cooperate on carbon capture and storage. . Santos (2023b) Darwin Pipeline Duplication Project; Supplementary Environmental Report Đ Executive Summary. Santos (2023c) MOUs executed for potential CO2 supply to underpin SantosŐ Bayu-Undan CCS project. . Santos (2024) G-11-AP CCS Appraisal Drilling Environment Plan. . Stalker L, Ross A, Gee R, Jenkins C and Squiers I (2024) Northern Territory Low Emissions Carbon Capture Storage and Utilisation Hub. International Hub Examples ? Task 4 Report. CSIRO, Australia. Talukder A, Dance T, Michael K, Clennell B, Ryan G, Northover S, Stalker L and Ross A (2024) CO2, H2 and compressed air energy storage site screening study Đ selected onshore basins in the Northern Territory. 186. Tocock M, Ross A and Rogers J (2024) Northern Territory Low Emissions Carbon Capture Storage and Utilisation Hub. Transnational Co2 Shipping Logistics and Technoeconomic Model Đ Task 8 Report. CSIRO, Australia. Tucker O and Tinios L (2017) Experience in Developing the Goldeneye Storage Permit Application. Energy Procedia 114, 7466-7479. DOI: https://doi.org/10.1016/j.egypro.2017.03.1880. Walspurger S and Dijk vHAJ (2012) EDGAR CO2 purity. Type and quantities of impurities related to CO2 point source and capture technology. A Literature study. . Wilson C (2022) Japan CCUS and Hydrogen Symposium. . Wood and GHD (2024) Work Package 35 Đ Marine Liquid CO2 Receiving and Storage Terminal Planning. As AustraliaŐs national science agency and innovation catalyst, CSIRO is solving the greatest challenges through innovative science and technology. CSIRO. Unlocking a better future for everyone. Contact us 1300 363 400 +61 3 9545 2176 csiro.au/contact csiro.au For further information CSIRO Energy Andrew Ross +61 8 6436 8790 Andrew.Ross@csiro.au csiro.au/Energy 1 Pipeline inspection is normally achieved with pigging Đ inserting a specialised device known as a pig into the pipe and using pipeline pressure to push it along (https://www.woodplc.com/news/latest-news-articles/2018/an-inside-view) 2 A ÔbulletŐ is the common name for a cylindrical pressure storage vessel with domed ends. 3 A joint venture is a legal agreement between two or more parties to work together on a specific project or purpose. 4 The Lang factor is one of the estimating techniques recommended by AACE International for class 4 and class 5 cost estimates. It is a reliable method, using a set of factors to adjust the total equipment cost to obtain the total plant cost. --------------- ------------------------------------------------------------ --------------- ------------------------------------------------------------ ii | CSIRO AustraliaŐs National Science Agency Northern Territory Low Emissions Carbon Capture Storage and Utilisation Hub | i