Depleted natural gas reservoirs are key for large-scale hydrogen storage and production, where fluid interactions at interfaces and within rock formations are vital for effective gas containment. While progress has been made in understanding structural and residual trapping, further insights are needed into how pore size affects column height estimation. So far, column height estimates in UHS often considers seal rock potential, yet there's a growing argument for including the capillary contribution from reservoir rock pore for structural trapping capacity assessment.
This study explores the influence of pore size on column height in hydrogen storage by measuring contact angle and interfacial tension on shale substrates above a reservoir rock. It then calculates column height estimates based on the equilibrium between capillary entry pressure and buoyancy force, considering contributions from the caprock alone and both the caprock and reservoir rock, to evaluate the structural capacity of the sealing layer.
The results indicate that there were noticeable differences in column heights, underscoring the influence of capillary reservoir effects on the trapped gas beneath the seal rock. Notably, the height (h_seal) above the seal was greater than the height (h_(seal-reservoir)) solely from the seal-rock interface, indicating the significance of reservoir pore characteristics. This study highlights that the observed difference has a substantial impact on the structural trapping capacity of hydrogen storage formations. The insights gained herein provide a valuable foundation for improving hydrogen storage strategies in depleted gas reservoirs by considering the fair capillary contribution from the underlying reservoir's rock pore size.

The global energy landscape is transforming towards a carbon-neutral future, necessitating strategic and systematic approaches to address the energy trilemma of security, affordability, and sustainability.
Two critical elements of this transformation include the large-scale global adoption of hydrogen for energy use and carbon capture, usage, and storage (CCUS), including carbon sequestration.
These efforts require effective management from a lifecycle perspective, considering net emissions and economics, including the levelised cost of energy (LCOE), and a risk-based process safety management approach that ensures public safety.
Embracing asset management principles, which encompass lifecycle management, risk management, and performance optimization, will be key in facilitating this transition. By analysing energy generation, demand patterns, and storage capacity, optimising the use of renewable energy, systematically, and dynamically monitoring asset performance, and process safety assurance metrics, operators can optimise resource allocation, reduce costs, and improve sustainability and public safety. Furthermore, adopting good risk engineering practices, including risk-based process safety (RBPS) management, will manage risks to as low as reasonably practicable, ensuring a tolerable residual public risk level.
This article highlights some key challenges and suggests practical strategies for operators to manage these major changes by integrating principles of asset management and risk-based process safety management, from the policy level through to tactical implementation. It emphasises the necessity of a holistic approach, synthesising asset management and risk-based safety principles, as crucial for handling these shifts in global energy systems, including the widespread adoption of hydrogen and CCUS, to guarantee a sustainable and resilient energy future for upcoming generations.

The Offshore Petroleum and Greenhouse Gas Storage Act 2006 provides the legal framework for CO2 storage projects in Australian Commonwealth waters, with the associated Regulations and Guidelines requiring that applicants for a “declaration of an identified storage formation” consider “all migration pathways of which the probability of occurrence is greater than 10%”. The overseas Society of Petroleum Engineer’s Carbon Dioxide Storage Management System (SPE-SRMS) goes further and discusses the concept of modelling not only the sub-surface CO2 plume itself but also the attendant pressure effects and displaced formation water, which, in that scheme, comprise part of a wider “containment area”. These collective requirements necessitate that the eligible carbon storage resources be assessed probabilistically, a requirement that can result in sizable static and dynamic models that are computationally heavy to simulate. This computational complexity places inherent, practical limitations on using “conventional” probabilistic workflows, such as Monte Carlo simulation or Latin hypercube sampling. To address this limitation, factorial experimental designs were employed in the modelling workflow. Factorial designs are widely used in settings where individual experiments are costly or require prolonged periods and, when implemented correctly, can uncover underlying uncertainty distributions using a minimum number of simulation cases. The efficacy and power of this approach is demonstrated using CO2 injection and migration models for a carbon storage project located in offshore Western Australia, which is in the early development stage. The ability to test potential sensitivities rapidly has proven to be critical in refining and defining the project’s ultimate CCS development plan.

Pivotree™ represents a technology paradigm shift in offshore oil field development, reducing cost and providing a route to market for the operators of stranded resources. Conventional standalone projects, characterised by substantial upfront capital expenditures with complex equipment and high installation costs, are juxtaposed against the Pivotree™ solution, with a markedly reduced capital outlay that retains all the requisite safety and operational features associated with larger systems.
A comparative study of activities, materials, and risks concomitant with different field development concepts are analysed for a range of reservoir characteristics, highlighting the financial advantages of the Pivotree™ technology. A set of economic scenarios with the costs of different development concepts are compared over the life-cycle phases from Drilling to Abandonment and the Net Present Value (NPV) and Internal Rate of Return (IRR) calculated against a range of oil prices, and operating expenditures.
Multiple-Criteria Decision Analysis (MCDA) allows a systematic assessment and comparison of a broad spectrum of qualitative factors including safety, environmental impact, operability, maintainability, time to deploy, water depth, independence, and abandonment burden. A “Concept Select” activity is performed using MCDA to evaluate the range of development options against the listed set of project and technology attributes. A set of weightings is provided for the purpose of analysis by the author equating to the corporate values and strategy of a fictional energy company.
The paper underscores the potency of the Pivotree™ technology within the sphere of offshore field development and can unlock production from the global store of stranded discovered resources.

Australia has in the order of 3,500 km of offshore pipelines currently operating in Commonwealth waters which will require either re-use or decommissioning at the end of hydrocarbon service. Santos is currently working to develop the Bayu-Undan and Reindeer Carbon Capture and Storage (CCS) Projects, making use of the depleted hydrocarbon reservoirs to sequester CO2 via the existing offshore infrastructure. A key aspect of these projects is the re-use of existing offshore hydrocarbon pipelines to transport CO2, both of which have been in operation for 10-20 years. The Bayu-Undan and Reindeer pipelines were designed and operated for distinctly different hydrocarbon services, which has presented two unique technical starting points in the delivery of safe and robust conversion to CO2 service. Using the knowledge gained from these pipeline conversions, this paper will provide an outline of the key technical considerations to re-qualification of pipelines for CO2 service, including operational, material, technical safety, fracture and mechanical aspects unique to the combination of life extension and CO2 service. These aspects will be discussed and framed in the context of existing industry codes and known technical challenges with CO2 pipelines. Finally, the outcomes of this discussion will be structured against typical phases in the project lifecycle. Potential opportunities for optimisation of future CO2 re-purposing projects will also be proposed.