Chairman address delivered by CO2CRC Chairman, Martin Ferguson AM.

Welcome address delivered by CO2CRC Chief Executive Officer, Dr Matthias Raab.

Professor Cook is one of Australia’s most distinguished earth scientists and a pioneer and visionary of CCS research and deployment.

CO2CRC welcomes Minister for Resources and Minister for Northern Australia, the Hon Madeleine King MP, to deliver the government keynote.

David is the director of our Energy Transition Practice. He began his career with Wood Mackenzie in 2011 as an analyst covering European markets. From 2014-2016, he was posted in the Beijing office, where he led the integration of their China energy research. He presented regularly on China’s macroeconomic outlook, gas and LNG markets and coal-to-gas switching goals.

Leveraging his global experience across multiple areas of the energy industry, David moved to the Houston office in 2016. He is a key author of their Energy Transition Outlook, Accelerated Energy Transition Scenarios and emerging technology coverage. He regularly advises strategy groups, company leadership teams, and investors on major long-term questions facing energy markets.

Significant progress towards a low carbon world has been made, but the rate of change has to increase, just as the low hanging fruit has been captured. This is an opportunity for CCS. 

Not all CCS projects are likely to be successful. This session considers the drivers for CCS, the necessary conditions for a successful project, and competitive alternatives in pursuing net zero carbon outcomes.

Community support for CCS cannot be taken for granted. Already onshore CCS has been challenged, and this is limiting project options. 

This session reviews the strategic future of CCS with both its opportunities and traps.

INPEX Senior Vice President Corporate, Bill Townsend, will share his insights into the energy trilemma and Australia’s vital contribution to Asia-Pacific energy security and decarbonisation. 

He will articulate INPEX’s CCS ambitions detailed in the company’s Vision 2035 strategy, and champion enabling policy settings to unlock Australia’s potential. 

INPEX delivered the largest ever overseas investment by a Japanese company with the sanctioning of Ichthys LNG in northern Australia.

This Panel session will explore how energy security, power demand and technology choices mean the use of oil, gas (LNG) and coal for longer, how CCS can become commercially viable in Australia, and the opportunities and challenges of large-scale CCS deployment. 

The panel will consist of senior energy, oil, and gas executives and it will be chaired by Perry Wilson, Head of Advisory ANZ at Rystad Energy.

As carbon capture and carbon dioxide removal (CDR) technologies advance toward deployment, the key challenges are no longer purely technical but increasingly practical — involving cost, scalability, integration, and verification. This talk will explore the deployment pathway for both point-source and direct air capture systems, drawing on current experience from the ARC ReCarb Hub and Woodside Monash Energy Partnership. It will highlight lessons learned in progressing from lab to pilot and field demonstration, address barriers to scale-up and investment, and outline realistic timelines for achieving material impact through CCU and DAC deployment in Australia and beyond. 

Carbon management technologies deal with the overall challenge of limiting the CO₂-concentration increase in the atmosphere. They encompass CCS, CCU and CDR, and as a result a wide variety of decarbonisation routes. Nearly all have CO₂-capture as the first and often most expensive step. The presentation will give an overview of carbon management technologies seen through the capture angle, providing a perspective on how cost could be reduced by integrating capture into the various decarbonisation routes. The findings from CSIRO’s work on roadmaps for CDR and CCU will also be included.

Airhive is a direct air capture company, based in London and founded in 2022. This talk will discuss the deployment of Airhive’s Storm One commercial demonstration (1,000 tonnes per annum), one of the world's largest Direct Air Capture (DAC) facilities. Located at the Deep Sky Alpha site Alberta, Canada, the system is now under commissioning and is set for full operation with CO2 transport and storage in a nearby saline aquifer in Q1 2026.

Airhive’s DAC technology harnesses “fluidization,” an industrial process that uses gas flows to suspend solid particles in a fluid-like state. Fluidization enables faster gas-solid interface, allowing an otherwise slow-reacting mineral-based sorbent to capture CO₂ from the passing air at very high velocities and capture efficiencies. The process captures close to 100% of the CO₂ in the air that moves through the system in less than 1/10^th of a second. The result is a low cost and energy system, void of toxic substances and powered entirely by electricity.

The UNO MK3 technology is a novel and unique capture process that KC8 has found to be an attractive offering for those looking for a non-amine capture process. The technology is applicable for all applications across the CCUS space and two major demonstrations projects (in Australia and the US) in both the energy and industrial sectors attest to that. New research is investigating opportunities in the product and DAC space.An update on the technology will be provided.

 This presentation will recap the journey from the early days of development of what became the UNO MK3 process in the CO2CRC through to the latest results from commissioning the KC8 UNOGAS project at the National Carbon Capture Centre in Alabama.

 From the initial learnings in the laboratory through various pilot facilities in Victoria and then commercial demonstrations there have been many technical lessons along what has been close to a twenty-year journey. Add to that the commercial realties of generating customer buy in and raising the necessary investment capital and you have a heady mix for all those involved. 

Carbon Capture, Utilisation and/or Storage (CCUS) is expected to have a role in the net-zero transition of high temperature industrial processes, such as cement/lime, iron/steel and alumina/aluminium, due to the long-term need for limestone in these processes, the challenges of entirely eliminating carbon-based fuels and the potential to introduce a CO₂ negative component into these processes. Mineral carbonation is among the particularly prospective re-use pathways due to its synergistic nature with the processing of ores. Nevertheless, the extent of the role of the various CCUS options in this transition will depend both on the relative cost and timelines at which they can be made available at scale relative to other options, including electrification, hydrogen and alternative fuels. The presentation will give an overview of the key opportunities, research challenges and pathways for CCUS in these industries being evaluated by the HILT CRC, including scenario analyses and mineral carbonation.

Facilitated Q&A 

Conventional reservoir models often overlook micro-scale heterogeneity because standard well logs and core plug data lack the resolution to capture fine-scale features. This omission reduces the precision of reservoir characterization, particularly in thin sandstone layers where reservoir quality is critical for CO₂ sequestration. To address this limitation, high-resolution micro-CT imaging and digital core analysis (DCA) were combined with upscaling algorithms to bridge the gap between pore-scale properties and field-scale reservoir simulations. This study applied the upscaled data from digital core analysis to improve reservoir characterisation and modelling for CO₂ injection projects in the Otway formation. Micro-CT imaging provided detailed three-dimensional pore structures, and pore network modelling was used to generate relative permeability and capillary pressure functions. Then, these properties were upscaled to reservoir scale and incorporated into simulation models. History matching was performed using multiple field datasets, including seismic CO₂ plume shapes, CO₂ saturations from neutron logs, and pressure buildup from a single-phase water injection test. The results demonstrated three key advantages of DCA over conventional laboratory core experiments. First, DCA significantly reduced uncertainty in the measurement of rock properties, leading to more accurate predictions of CO₂ plume behaviour. Second, DCA enabled the testing of individual rock types within facies associations, and their effects were captured in upscaled properties for large-scale simulations. Third, plume simulations based on upscaled DCA data reproduced the observed seismic plume, with a more accurate vertical profile and reduced lateral extent compared with earlier simulations using traditional SCAL data. Overall, this work highlights the value of integrating micro-CT imaging, DCA, and upscaling into reservoir modelling. The approach provides a more reliable representation of reservoir heterogeneity and improves the accuracy of CO₂ storage forecasts, offering a practical pathway for enhancing the safety and efficiency of geological sequestration projects.

 

Reliable estimation of CO₂–water relative permeability is essential for predicting injectivity and storage performance in saline aquifers. Yet, standard laboratory protocols are often complicated by mineral reactions and fines migration. In this study, we combine controlled coreflooding experiments, porous plate desaturation, and microscopic visualisation to evaluate how CO₂–water–rock interactions alter flow functions.

For Berea sandstone, the injection of CO₂-saturated water triggered mineral dissolution and fines mobilisation, confirmed by ICP–OES analysis (Ca²⁺, Fe³⁺, Mg²⁺ release) and SEM–EDS imaging of pore alteration and fines precipitation. These reactions produced a 21–48% reduction in CO₂ relative permeability and significant injectivity decline with increasing pore volumes of CO₂-saturated water injected. By contrast, experiments on sintered glass cores showed negligible changes, underscoring the mineralogical control. 

A porous plate method was applied to carefully desaturate cores at constant pressure, reducing water saturation in a controlled manner and enabling direct measurement of maximum CO₂ relative permeability under drainage conditions. This approach was coupled with conventional unsteady-state flooding. The porous plate desaturation technique also demonstrated that at water saturations below ~0.34, experimental limitations arise; however, it provides a more representative upper bound for CO₂ flow capacity than conventional extrapolations. Taken together, our results show that coupling visualisation with refined saturation control reveals how pore-scale reactions govern injectivity and relative permeability.

This integrated workflow advances laboratory protocols by mitigating artefacts, improving the reliability of relative permeability functions, and informing the design of CO₂ geostorage projects.

 

The Otway GeoCquest Field Validation experiment involved the injection of approximately 10,000 tonnes of supercritical CO₂-rich gas (80 mol% CO₂ and 20 mol% CH₄) into the lithologically heterogeneous Paaratte Formation Parasequence 2 within the onshore Otway Basin at a depth of approximately 1.5 kilometres. One of the major objectives of this field-scale test was to study the role of small-scale geological heterogeneities, such as petrophysical thin beds composed of low-permeability, low-porosity intraformational baffles. We assessed how these features control the vertical and lateral distribution of the CO₂ plume across different geological layers and influence overall plume-migration dynamics.

To monitor plume behaviour, a high-frequency pulsed-neutron logging (PNL) program was conducted in the dedicated passive monitoring well, CRC-8, over a five-month period, with multiple passes acquired daily during both injection and post-injection phases. A time-lapse differencing approach applied to baseline and monitoring datasets enabled detection of subtle changes in log responses and their spatiotemporal evolution with high fidelity. An integrated thermodynamics-based petrophysical framework was developed that combines different PNL measurements to quantify changes in saturation across the reservoir while accounting for measurement noise, depth mismatches, and borehole environmental effects.

Results indicate rapid migration and early gas breakthrough along preferential high-permeability streaks, together with clear evidence that small-scale heterogeneities strongly influence CO₂ plume distribution. Geological features such as heterolithic intervals and grain-size variability were found to control capillary entry pressures, resulting in capillary-heterogeneity-driven flow patterns and non-uniform saturation distributions at the field scale. Additionally, sedimentary structures including clay-rich thin beds, cross-bedding, and low-angle sandstone beds with carbonaceous laminae exerted further control on plume geometry during both injection and post-injection phases. Overall, these findings highlight the dominant role of small-scale heterogeneities in governing plume migration and provide critical insights for advancing carbon sequestration monitoring technologies and improving the reliability of predictive models.

The successful storage of CO2 in saline aquifers requires careful selection of injection scenarios that maximize storage capacity whilst minimizing leakage risks. The limited data on these fields means the challenge lies in optimizing development strategies whilst accounting for uncertainty. This study proposes an automated workflow to generate an ensemble of hydrodynamic-geomechanical models and optimize potential injection locations for efficient carbon storage.

The workflow was applied to the Smeaheia open dataset, creating multiple plausible models by varying key reservoir and geomechanical parameters. A neural network algorithm was then run across this ensemble to identify injection strategies that maximise CO₂ storage whilst maintaining geomechanical integrity. 

Results show that effective well location and perforation schemes can be identified across a wide range of possible scenarios. Compared to deterministic optimization, this uncertainty approach reduces the likelihood of selecting injection locations that appear optimal in one case but are high risk under alternative scenarios. 

This work demonstrates the value of combining automated optimization with uncertainty analysis in coupled fluid-geomechanical models. The methodology highlighted in this study offers a transferable framework for designing injection strategies that remain effective under geological and geomechanical uncertainty. 

CO₂ geological storage is a promising strategy for mitigating global carbon emissions, with reservoir porosity and permeability being key parameters for assessing storage potential. However, characterizing the spatial distribution of these properties at the field scale presents a major challenge due to data scarcity and heterogeneity. Conventional methods often struggle to effectively integrate discrete well-log and core measurements with continuous seismic data, while common machine learning approaches tend to neglect crucial geological controls like diagenetic processes. This limitation often leads to models with poor generalization beyond the training data.To overcome these challenges, we propose a novel multi-source, multi-scale data fusion approach for predicting porosity and permeability in tight sandstone reservoirs. Our method integrates high-precision core data with comprehensive well-log and seismic data, leveraging multiple machine learning algorithms to enhance the predictive power and generalization of the model. Taking the Upper Paleozoic Shiqianfeng Formation in the Ordos Basin as a case study, we demonstrate that this fusion approach significantly improves the accuracy of reservoir property prediction at the field scale.The results provide a more reliable foundation for evaluating storage potential and forecasting injection capacity in commercial-scale CO₂ geological storage projects. This study addresses the common issue of limited well and core data in seismic work areas, offering a robust and intelligent solution for reservoir characterization.

Understanding how geological heterogeneity influences CO₂ plume behaviour is critical for designing secure and efficient storage projects in saline aquifers. Features such as intraformational baffles, heterolithic intervals, and subtle facies transitions can significantly impact plume migration by slowing vertical rise, enhancing lateral spread, or promoting trapping mechanisms. Yet in low dip, low relief structural settings, a key challenge remains: to what extent can these small scale heterogeneities offset buoyancy driven migration?

This study presents a pre-injection geological modelling workflow for a small saline aquifer CO₂ storage site (<6 km²) targeting a thin reservoir (~50 m). With seismic data resolution insufficient to resolve internal architecture, we relied on high resolution core descriptions, image logs, and stratigraphic interpretation to characterize key depositional elements. Particular attention was given to low permeability features such as heterolithic baffles and sharp facies transitions that may affect vertical CO₂ movement.

These heterogeneities were incorporated into a 3D static model using stochastic methods to represent the variability in facies connectivity and lateral discontinuities. Dynamic simulations assessed the associated CO₂ plume behaviours, ranging from slow, fingering migration controlled by intraformational baffles to rapid channelised flow through connected high permeability streaks. 

Results highlight that in low-relief structural settings; even subtle heterogeneity can significantly influence plume architecture and migration pathways. This was validated through the correlation with high resolution saturation logs. Incorporating realistic geological complexity enhanced our ability to anticipate plume behaviour, guiding injection strategy, monitoring design, and contingency planning for uncertain migration outcomes. This work reinforces the value of integrating detailed sedimentological analysis with geological modelling to better constrain reservoir performance, reduce geological uncertainty, and support safer and more reliable CO₂ storage outcomes.

The secure storage of carbon dioxide (CO₂) in deep saline aquifers relies on efficient injection, distribution, and trapping within reservoir rocks. Residual trapping, where disconnected CO₂ clusters are immobilised by capillary forces, is considered one of the most reliable long-term storage mechanisms, but its effectiveness depends on sweep efficiency and pore accessibility. This study used Otway sandstone cores from the CRC-8 well to compare conventional supercritical CO₂ injection (CI) with microbubble (MB) injection under reservoir conditions. NMR T₁–T₂ mapping, T₂ distribution analysis, saturation profiling, and SCAL measurements were applied to assess fluid displacement, sweep efficiency, breakthrough timing, and storage capacity.

Results showed that MBs invaded both meso- and micropores more effectively than CI, displacing brine from regions unswept during conventional injection. After drainage, CO₂ saturation reached 39.4% for MBs compared to 23.1% for CI. Following imbibition, residual trapping was 22.5% for MBs versus 16% for CI. Pc–Sw curves indicated lower capillary pressures under MB injection, confirming easier CO₂ entry into smaller pores and a more uniform sweep. Moreover, MB injection delayed breakthrough and produced more uniform saturation profiles, reducing preferential flow through high-permeability zones.

Overall, MB injection provided superior pore-scale control, enabling deeper invasion, broader sweep, and enhanced capillary trapping. By increasing storage capacity and improving conformance in previously inaccessible pores, MB injection demonstrates strong potential as a safer and more reliable approach for large-scale geological CO₂ sequestration.

Keywords: CO₂ sequestration, microbubbles, breakthrough time, sweep efficiency, storage capacity, NMR.

Anthropogenic carbon dioxide (CO₂) emissions are widely recognized as a principal driver of global climate change, contributing to rising atmospheric temperatures and increasing environmental instability. Among various mitigation strategies, carbon capture and storage (CCS) has emerged as a vital approach to reducing emissions by injecting captured CO₂ into deep geological formations such as saline aquifers. However, maintaining injectivity during CO₂ storage remains a key challenge, particularly in sandstone formations with high clay content. Two major mechanisms responsible for injectivity decline are fines migration and salt precipitation. Fines migration involves the detachment and transport of clay minerals (e.g., kaolinite) from pore walls under the influence of viscous and capillary forces. The mobilized particles tend to accumulate at pore throats, leading to permeability reduction and impaired CO₂ injectivity.

This study investigates the potential of a commercial silica-based nanoparticles (NPs) to mitigate fines migration and enhance formation stability during CO₂ injection. A series of core flooding experiments were conducted using high-clay-content sandstone samples to evaluate the effect of nanoparticle treatment on fines stabilization. Results show that, in the absence of nanoparticles, fines migration led to at least 1.5-fold reduction in permeability. In contrast, cores pre-treated with silica nanoparticles exhibited stable permeability throughout the CO₂ injection process, indicating effective fines stabilization by NPs. Effluent analyses further confirmed a high concentration of detached particles in the untreated case, while negligible fines production was observed in the nanoparticle-treated samples.

These findings suggest that nanoparticle pre-treatment can effectively mitigate fines migration during CO₂ storage in saline aquifers, enhancing formation stability and maintaining injectivity. The outcomes of this research provide valuable insights for improving the efficiency and reliability of geological CO₂ storage operations.

Joule–Thomson (JT) cooling of injected CO₂ can significantly impair well injectivity through hydrate formation, salt precipitation, and viscosity increases. These risks impose operational constraints on injection rates during CO₂ storage projects. This study develops and analyses three analytical models that describe temperature evolution during CO₂ injection into porous media under different heat exchange regimes with surrounding formations. The models account for (i) steady-state heat exchange governed by Newton’s law, (ii) non-steady-state heat exchange initiated by the CO₂ front, and (iii) non-steady-state heat exchange initiated by the thermal front. Exact solutions were derived and validated against a quasi-two-dimensional benchmark solution.

The developed models capture temperature propagation for different reservoir boundary conditions, allowing for pressure–temperature trajectories to be mapped onto the CO₂–water phase diagram. This framework enables direct assessment of hydrate formation by evaluating which sections of the injection zone will enter the hydrate stability zone of the phase diagram. Results indicate that higher injection rates intensify JT cooling, giving rise to a maximum safe injection rate that avoids hydrate formation. Adjusting CO₂ injection temperature and rate can significantly alter the P-T trajectory of each well, either preventing hydrate formation entirely or ensuring that any hydrates form only at a sufficient distance from the injection well to avoid injectivity impairment.

The analytical framework provides practical guidance for assessing injection strategies under various geological conditions. By linking injection rate, temperature, and reservoir thermal architecture, the models allow operators to minimise hydrate-induced formation damage and permeability decline. The approach also offers a rapid and transparent method for selecting appropriate heat exchange models, reducing reliance on computer simulations. Application to the Sleipner and Gorgon CO₂ storage projects demonstrates practical relevance for field-scale CCS, supporting reliable and cost-effective planning of large-scale CO₂ storage.

This study investigates how CO₂ microbubble injection influences dissolution plume migration and trapping in porous media compared to conventional gas injection. Conventional CO₂ injection often leads to rapid buoyant rise and limited dissolution. Microbubble technology, with its enhanced interfacial area and reduced buoyancy, offers potential improvements in solubility and retention, reducing the buoyant CO₂ plume. The objective is to visualize and quantify these differences in a controlled sand tank setting, providing insights for subsurface carbon storage strategies.

The integrity of CO₂ transport infrastructure is a critical component of the carbon capture and storage (CCS) value chain. Appropriate material selection is essential to ensure safe containment of captured CO₂, particularly as large-scale CCS deployment is required to achieve meaningful progress toward net-zero targets. However, pre-treatment of CO₂ to meet stringent specifications remains both technically challenging and economically costly. The presence of moisture and other impurities can significantly exacerbate corrosion of metallic components, especially carbon steel, through the formation of carbonic acid and stronger acids such as sulfuric and nitric acids. Dense-phase CO₂ also affects the performance of non-metallic materials, including elastomers and polymers, through mechanisms distinct from metallic corrosion, such as plasticisation and rapid gas decompression.

In this study, semi-crystalline polymers were investigated following exposure to supercritical CO₂. Tensile testing and dynamic mechanical analysis (DMA) were used to evaluate changes in mechanical and thermal properties relative to pristine samples. Post-exposure the samples exhibited an increase in elongation at break of more than 67%, accompanied by a reduction in glass transition temperature from 53.3 °C to 19.7 °C, indicating significant plasticisation. Scanning electron microscopy revealed morphological damage in the polymer after exposure to supercritical CO₂. In parallel, carbon steel X56, commonly used as a pipeline material, was exposed to supercritical CO₂ under varying moisture contents to assess the severity of corrosion.

The findings highlight critical gaps in understanding the long-term performance of both metallic and non-metallic materials in CCS applications, particularly with respect to the role of CO₂ impurities. These insights are also directly relevant to the assessment and qualification of existing infrastructure for repurposing in CO₂ service, where legacy materials may exhibit behaviour distinct from that of pristine materials.

This research investigates how small-scale heterogeneities in rock formations affect CO2 storage in subsurface reservoirs, focusing on core samples from Australia’s Otway CO2 storage site. The study was motivated by observations of unexpected rapid CO2 plume migration at storage projects like Sleipner, which were not predicted by prior modelling efforts.Using medical CT scanning, we imaged steady-state CO2 injection in cores taken from the Otway site. A key finding was that porosity distribution alone couldn’t predict CO2 distribution patterns, as some influential features were smaller than the medical CT scanner’s 0.6mm resolution. The study identified various types of heterogeneities within a 15m interval of the Otway basin, including fine layers, thick layers, and more complex patterns. These different heterogeneities resulted in diverse CO2 distribution and trapping patterns. Importantly, these variations occurred at scales smaller than typical reservoir model grid sizes. The findings contribute to Special Core Analysis (SCAL) for modeling a 10,000-tonne CO2 injection project in the Otway basin, highlighting the importance of incorporating small-scale heterogeneities in reservoir models for accurate prediction of CO2 behaviour.