With the increasing number of aging subsea wells, and a tightening of global regulations for safe well management, the challenge of assuring well integrity is a key feature of risk management for oil and gas operators. Baker Hughes, working with Sentinel Subsea can provide a remote passive well monitoring solution for oil and gas operators and, upon the completion of testing, CCUS applications placed on the mudline to monitor fully abandoned wells.
The innovative mix of hardware and software in the well monitoring system provides reliable and continuous integrity monitoring, uniquely without the use of active subsea power or data communication. These easy to deploy agnostic systems can be fitted to any wellhead or XTs or adjacent to subsea systems and adapted as to radius covered and access required, providing an optimised approach to subsea risk. The system works by gathering and chemically detecting materials in the subsea environment. When the specific fluid has been chemically detected, a coded alert beacon is released to the ocean surface. Once installed, an operator can remotely monitor the status of subsea equipment through a cloud-based platform. Should an alert beacon surface, an alarm is generated, and the operator automatically contacted, allowing for a rapid and coordinated response.
Following field trials in the North Sea, this collaboration has already seen successful international deployments of remote passive monitoring solutions by two operators, in Brazil and The Gulf of Mexico. Further developments are going through testing to enable a CO2 monitoring solution for CCUS projects.

Reducing emissions from the industrial and fossil fuel-based power sectors is crucial to achieving the net zero emissions. These sectors contribute to about 60% of global CO2 emissions. However, there are several technical challenges that current CO2 capture technology faces. The use of coal in steel and cement industries produces flue gases with high CO2 content, but also contain NOx and SOx as impurities. These impurities cause faster degradation of amine-based solvents in the current CO2 capture system. Additionally, capturing CO2 from flue gases with low CO2 concentrations, such as natural gas-fired power stations, results in higher operating costs, greater energy requirements, and larger equipment for the CO2 capture processes.
CO2CRC’s HyCaps process, a hybrid of solvent absorption and membrane technology, can overcome some of these challenges. It takes advantage of the capture efficiency of the solvent system, controlled flow regime and high surface-to-volume ratio of membrane technology. Therefore, the HyCaps process is more efficient and compact. The mode of interaction between gas and liquid in HyCaps limits solvent exposure to NOx and SOx, reducing solvent degradation. In HyCaps, as solvent is regenerated at a lower temperature, the low-quality, low-cost waste heat can be effectively utilised to reduce OPEX significantly.
Results of successful trials at three different industrial setups and preliminary techno-economic analysis from test trial data show the HyCaps process has the potential to offer very competitive capture solutions for various industrial settings.
The paper explores HyCaps process and its applications in various industrial sectors like oil, gas, hard-to-abate, and more.

Carbon capture and storage (CCS) is central to the clean energy transition. Globally, potential aggregated CO2 storage resource capacity is ~13,000 billion tonnes. Assuming global greenhouse gas emissions of 51 billion tonnes per annum, the CO2 storage capacity equates to 250 years of global emissions reduction.
While there is significant momentum to deploy CCS technology for meeting Paris Agreement targets, the key challenge for offering CCS to all industrial sectors is that many major CO2 emission sources are located hundreds of kilometres away from geological storage sites. To address this key challenge, the author highlights the need to develop a long-distance and large-scale CCS value chain that utilises liquefied CO2 ship transportation.
In this paper, the author will discuss the key technical, commercial, and regulatory considerations that must be addressed in parallel for developing such CCS value chain. More specifically, the author will cover the following:
1) Technical: CO2 liquefaction condition, CO2 supply specification and liquefied CO2 ship parcel size;
2) Commercial: business model (ownership of CO2 retained by emitters or transferred to CCS project proponent), CO2 supply or CCS facility lease terms & conditions; and
3) Regulatory: Domestic versus transboundary projects and associated needs for policy and legislative underpinning.

Carbon capture, sequestration, and utilisation (CCUS) is widely considered to be one of the key enablers to decarbonising the economy. It is currently being globally implemented in a number of projects in the gas, power, chemicals, cement, steel, and other industries. In the Asia-Pacific region, shipping of liquid carbon dioxide (CO2) is widely seen to be a key component of the CCUS value chain. Shipping allows the emitter industries located in the industrial centres such as Japan, Korea, and Singapore to access the distant injection locations. The repurposing of the Bayu-Undan platform and pipeline from gas production to CO2 injection presents a regional opportunity for disposal of shipped CO2. Multiple liquid CO2 development concepts were assessed for unloading and storage of imported CO2. Unloading can be ship-to-shore, ship-to-ship, or ship-to-platform; storage can be onshore, nearshore, offshore or no storage at all. These concepts required evaluation for technical functionality, maturity, complexity, operability, and availability. Imported liquid CO2 is generally too cold and low pressure to be injected at the carrier conditions. The pressure needs to be boosted and temperature increased to meet the requirements of the injection system. This requires sources of power and heat. An evaluation of existing facilities, their condition, space and spare capacity, and their constructability considerations all present important opportunities and constraints. A study was carried out, which evaluated options for the Bayu Undan liquid CO2 import using key evaluation criteria to select the most appropriate concept. This paper explores the challenges involved.

Extensive geological knowledge, operational experience and potentially reusable infrastructure makes depleted hydrocarbon fields attractive, early-opportunity candidates for CO2 storage. As the storage resource of depleted fields can be limited, we investigated whether additional, co-located storage potential exists in the water-saturated residual oil zones (ROZs) that are sometimes associated with conventional Australian hydrocarbon plays.
Our petrophysical study of central-eastern Australian basins demonstrates that ROZs occur in Australia’s hydrocarbon-rich regions, particularly in the Cooper-Eromanga basins. ROZs with more than 10% residual oil content are uncommon, likely due to small original oil columns and lower residual saturations retained in sandstone reservoirs than in classic, carbonate-hosted North American ROZs. Extensive, reservoir-quality rock is found below the deepest occurring conventional oil in many of the fields in the Eromanga Basin, implying that the rock volumes available for CO2 storage are much larger than conventional depleted fields.
Multiphase compositional flow modelling was used to estimate the CO2 storage efficiency of ROZs. As correct initialisation of the model is essential for achieving a realistic distribution and quantity of residual oil in place, we developed a novel modelling methodology that captures oil migration events leading to the formation of ROZs. Modelling CO2 storage over a 20-year injection period demonstrates that CO2-oil interactions increase the density and viscosity of CO2, enhancing CO2 sweep efficiency and lateral flow, thereby improving storage efficiency. The extent of these effects depends on the quantity and spatial distribution of residual oil in place and whether CO2 at reservoir conditions is miscible with residual oil.

Australia continues to fall behind other countries on hydrogen and CCUS because of an absence of adequate policy support for the emerging industry.
This presentation will discuss the range of policy, regulatory and market interventions that could be introduced to support hydrogen and CCUS sectors, as well as considering the role of bilateral and international partnerships. It will propose what is most suited to the Australian context to ensure the country’s exceptional potential can be realised.
Policy targeted to demand, supply or fiscal measures is important for scaling hydrogen. Hydrogen production incentives for hydrogen are being introduced in the European Union, India, Japan, and the United Kingdom. The USA’s Inflation Reduction Act offers tax credits that are attracting business to the North American market from around the world.
A carbon Contracts for Difference styled on the UK approach or a Canadian style carbon tax may be suitable options for scaling hydrogen production in Australia. Could such policy make Australia the leading place to develop projects and what investment would be required?
Against a review of international policy this presentation argues that Australia’s Hydrogen Headstart needs to be but a precursor to a more comprehensive and competitive package of measures, one that signals a long term commitment to reducing greenhouse gas emissions.
The presentation will conclude by proposing a package of policy interventions for Australia, phased over time. The impact of these will be discussed.