As the energy sector transitions, traditional geoscience occupations have been impacted by the decrease in upstream oil and gas activity. However, these roles are highly technical and innovative, and can benefit many sectors if re-deployed.
Net zero ambitions cannot be met without carbon offsetting. Woodside made the decision to create a carbon business and actively ‘originate’ offsets through carbon farming. Millions of seedlings have been planted on less productive farmland in WA. The success of the program has been enhanced through the transferrable skills that geoscientists provide.
Much like the petroleum geoscience discipline, carbon offset investment requires an assessment of a natural resource. There is uncertainty in the total volume, the future state, and the policy conditions impacting the resource. Geoscientists at Woodside have led initiatives to assess carbon yield, quantify and forecast uncertainty, and develop decision making frameworks for project investment. As a result, Woodside is an astute market participant and project developer in the nascent carbon market.
Geospatial analytics is critical throughout the value chain of a planting project, including site selection, project design, site execution, monitoring and reporting. Remote sensing and imagery analysis are required for monitoring growth and quantifying carbon sequestration. Geospatial mapping applications have increased project efficiency, providing accurate, real-time data to and from the field. Geospatial data integration with tractor GPS units optimises planting through precision agriculture.
Re-deploying geoscientists from in-house has provided Woodside with a competitive advantage, facilitating rapid growth to become a leader in the field.

In today’s climate-conscious world, companies across the globe continue to push to optimize energy use and reduce or eliminate their greenhouse gas emissions. Investments aimed at emission monitoring and reduction are driven by the need to optimize consumption of electricity, gas, oil, and water to meet emissions reduction targets and sustainability goals. Tracking and reducing emissions can improve process uptime through predictive maintenance and reduce product losses across the process.
Methane emissions are getting particular focus as it is more than 25 times as potent as carbon dioxide at trapping heat in the atmosphere. The Environmental Protection Agency stated that a third of methane emissions in North America come from the Industrial sector, and similar figures come from the European Commission. It is no wonder that the Government and industry are laser-focused on improving their approach to the reduction of methane emissions.
As companies drive their own corporate standards to achieve net zero emissions there is also a need to comply with existing and upcoming governmental emissions standards and regulations and report emissions on a periodic basis. The trend to move fugitive emissions monitoring from periodic to continuous provides operators with a greater insight into emissions sources which drives efficiencies through the reduction of lost product and a more predictive approach to maintenance. Investors are increasingly focused on environmental, social, and governance (ESG) reporting and favoring companies that can demonstrate strong ESG performance. Fugitive emission leaks can translate into billions of dollars of lost productivity annually, and serious occupational accidents.

Ammonia is critical for sustaining food production for more than half of the world’s population.
Across the world, there are many regional ammonia plants converting all ammonia to ammonium nitrate. This means that all energy-derived carbon input ends up as CO2, with around two tonnes of CO2 released per tonne of ammonia produced using natural gas-based plants. Note that ammonia plants produce pre-concentrated CO2 as part of their normal operation.
This paper outlines how to develop a 30% CO2 reduction (or bonus 43%) to extend the useful life of the asset while re-using much of the plant, with the ability to turn on/off the green energy with minimal disruption for stable operation.
The example plant is based on a typical 750tpd ammonia gas steam methane reforming (SMR) plant. The approach considers adding and integrating green power and biogas into this plant to reduce net reportable CO2 emissions.
While methanation of CO2 has been reported in several small-scale demonstration projects, the key is to develop a transition pathway for an existing gas-based plant, extending its operational life and flexibility to operate with varying degrees of variable green energy supply. This reduces the high capex of an entirely new plant and co-produces a ‘drop-in’ product.
Further, although SNG is used in this case, the approach can be beneficially applied with methanol, DME, and other Power-to-X opportunities, pending the regional markets near the facility.

The standards for companies reporting on the environmental impacts of their operations has changed drastically over the last decade and is about to become even more complex.
Initially, limited regulation or guidance available to companies in relation to climate disclosures led to widely diverging practice. This has led to many companies facing allegations of ‘greenwashing’ and in some cases litigation and shareholder activism.
However, the Australian Government has recently announced it will implement mandatory climate reporting commencing from 1 July 2024 for many Australian companies.
The additional climate disclosures – encouraged by pressure from stakeholders and required by the new reporting regulations – will obviously make environmental management more complex. They will also provide activists with opportunities to disrupt and interfere with the approval process for new projects, by finding inconsistencies between a company’s climate disclosures generally and what they have said in their project approval documents.
Our presentation would provide our views on the most effective strategies and mitigation steps that can be taken to reduce this risk of disruption and disincentivise activist interference more generally, drawing from our experience in acting for clients facing legal climate change actions and on advising energy and resources clients in relation to climate change and ESG issues more broadly.
In particular we will cover:
• common greenwashing ‘tips and traps’;
• the aspects of the new mandatory climate reporting regime that will be most difficult to comply with;
• stakeholder / activist engagement planning; and
• how Boards should approach these issues.

This paper explores the advantages of incorporating a Carbon Capture and Storage (CCS) application into your Hydrocarbon Data Management System, in addition to the commonly employed Hydrocarbon Accounting (HCA). The fundamental principles of data acquisition, validation, quantification, and reporting align seamlessly with the established processes employed for HCA. Therefore, leveraging a centralized and structured database for data importation, recording, compilation, and analysis offers distinct benefits to CCS projects, including Greenhouse Gas (GHG) emissions reporting.
All stages of the CCS process involve measurement, including capture, transportation, injection, and storage. The key information that can be stored in the system and used in consecutive calculations/ analyses are:
• Quantity (volume or mass) of CO2 across various parts of the network
• Composition - to determine that the purity of the CO2 remains within the contractual and safety limits.
• Physical properties (e.g. phase, density, compressibility) – to monitor the behaviour of the of the CO2 stream to enable effective control and measurement.
The National Greenhouse and Energy Reporting (Measurement) Determination 2008, defines the requirements in relation to carbon capture and storage as well as specifies the methodology to calculate the fugitive emissions from carbon capture and storage and enhanced oil recovery (under Part 3.4). These calculations will be carried out by the system using the already available data.
In summary, the CCS application within the Hydrocarbon Data Management System will provide a streamlined business process as well as ensure compliance with legislative requirements in a transparent and auditable manner.

Carbon capture and storage (CCS) is a critical component of proposed pathways to limit global warming, though considerable upscaling is required to meet the emissions reductions targets. Quantifying and managing the risks of fault reactivation is the leading barrier to scaling global CCS projects from current levels of ~40 MtCO2/yr to target levels of ~5-10 GtCO2/yr because CO2 injection into reservoirs results in increased pore fluid pressure, which can reduce the strength of rocks and faults, and induce brittle failure. This can result in induced seismicity whilst hydraulic fracturing of sealing formations can provide pathways for CO2 leakage. Consequently, identifying favourable geomechanical conditions (typically determined through data on pre-injection rock stress, strength and pore-fluid pressures) to avoid deformation of reservoirs and seals represents a key challenge in the selection and de-risking of safe and effective sites for CCS projects. Critically however, such geomechanical data are typically spatially limited (i.e. restricted to wells) and mainly consist of crustal stress orientation measurements, rather than a full 3D description of the stress tensor and related geomechanical properties. This paper will provide a state-of-the-art review of the key geomechanical issues and knowledge gaps that need to be understood to enable successful reservoir and seal management, and ultimately long-term storage efficacy, for CCS projects in an Australian context. It will also highlight recent advances in multi-scale and dimensional geomechanical modelling approaches that can be used to assess and derisk sites for the storage of CO2, and other gases including hydrogen.

Reliable local renewable power generation enables more environmentally and economically viable operations, to meet with the challenge of renewable energy intermittency and energy security. The Renewables for Subsea Power (RSP) project support targets towards net zero targets by providing a full solution to generate low carbon, cost-effective, power and communications to remote locations in the offshore energy industry. The development of the RSP system is a collaborative project led by three UK-based companies in partnership with wider industry engagement from operators and the Aberdeen-based Net Zero Technology Centre.
Carbon capture, utilization, and storage (CCUS) is set to play a key role in the energy transition. CCUS developments will incorporate all-electric subsea systems that can benefit from the Renewables for Subsea Power (RSP) solution.
This first of a kind integrated solution will contribute significantly to the generation of clean energy in the petroleum industry using a wave energy converter and seabed battery energy storage for production control applications. The various applications that would benefit from the cost and CO2 savings from deploying the system, compared to traditional methods, include umbilical remediation, brownfield expansion, long offsets, CCUS, and autonomous underwater vehicle residency. For CCUS projects key advantages are a specific design catered towards simplified controls architecture (e.g., electric controls), and the ability to offer an alternative to direct current fiber-optic from shore.
A full system demonstrator deployment commenced in Feb-23 and has demonstrated system capability to power subsea equipment and an Autonomous Underwater Vehicle (AUV). Trials continue through 2023.

The purpose of this paper is to discuss the existing company-owned constellation of satellites that is actively being used to identify methane emissions in the Oil and Gas Industry. This paper will show the utility of this remote sensing platform to help with emissions mitigation, regulatory compliance, and its role as an integral part of an emissions intensity improvement strategy.
This manuscript will provide an overview of the available and functional satellite constellation from GHGSat. The instrument on board each satellite uses spectroscopy principles to detect and further quantify methane emissions, exhibiting a spatial resolution of less than 30 meters. A discussion on how this constellation can be used as a key service system in the mitigation of emissions will be presented. Additionally, proposing the use of this constellation as a way of demonstrating regulatory compliance will be discussed.
Results presented in this manuscript will reflect observations taken with the existing constellation of satellites. Recent examples of Oil and Gas emitting facilities around the world will be presented followed by a discussion on how this constellation can serve three objectives: 1) emissions mitigation; 2) regulatory compliance; and 3) a system to achieve voluntary efforts such as OGMP 2.0. The intention for this article is to demonstrate that, knowing that no single solution can provide complete coverage at a manageable cost, the use of a satellite constellation is an efficient way of monitoring for large leaks with increased frequency, this as an integral part of a methane emissions management program.

The Australian Hydrogen Centre (AHC) was established to deliver Australian-first feasibility studies of how existing natural gas distribution networks could be used in a system to produce, store, and transport renewable hydrogen, decarbonising gas supply while still meeting the needs of millions of customers.
The AHC Reports show that it is technically and economically feasible to use existing gas infrastructure for scaled hydrogen distribution, delivering:
1. A net zero carbon emissions gas network;
2. Minimised customer disruption whilst retaining security and diversity of energy supply;
3. Services to the electricity grid through flexible electricity demand and frequency control;
4. 15 gigawatts (GW) of electrolysis supported by over 30 GW of new renewable electricity generation;
5. 30 petajoules (PJ) of hydrogen storage to harness the ability of gas to store vast amounts of energy, balancing renewable electricity supply and demand swings between colder and warmer months; and
6. Over $1.5 billion in additional economic value a year including more than 12,500 jobs during construction and more than 6,200 jobs during operation.
Supported by a range of independent technical studies, the Reports provide a better understanding of the opportunity to access Australia’s world-class gas distribution infrastructure to unlock its hydrogen opportunity whilst retaining energy security and affordability, and identifies a range of low-regret enablers that could trigger coordinated action by government and industry. They also share learnings from Hydrogen Park South Australia (HyP SA), an Australian-first demonstration of hydrogen blending in a gas distribution network.

The Karratha Gas Plant (KGP) is a complex integrated facility which produces Liquified Natural Gas (LNG), domestic gas (DOMGAS), condensate, propane, and butane products. The multi-train facility has been operating for over 40 years with several phases of expansion resulting in a range of gas turbine technology and energy efficiency levels across the facility. The challenge for the next phase of KGP operation is to manage declining NWS feed gas levels, and the addition of Other Resource Owners feed gas with a variety of compositions, all while reducing emissions and maintaining energy efficiency.
A flexible emissions forecasting tool has been developed which allows unit and whole of facility emissions reduction and energy efficiency options to be assessed. The tool builds on current quarterly timestep production forecasts and models ambient temperature, unit turndown and turn-off strategies, and potential brownfields modifications.
The ability to generate and compare life of field emissions profiles for extrapolated operating modes and proposed modifications allows unit strategies and phasing of emissions reduction modifications to be investigated and screened before further economic assessment and creation of marginal abatement cost curves (MACC).

The Karratha Gas Plant (KGP) is a complex integrated facility which produces Liquified Natural Gas (LNG), domestic gas (DOMGAS), condensate, propane, and butane products. The multi-train facility has been operating for over 40 years with several phases of expansion resulting in a range of gas turbine technology and energy efficiency levels across the facility. The challenge for the next phase of KGP operation is to manage declining NWS feed gas levels, and the addition of Other Resource Owners feed gas with a variety of compositions, all while reducing emissions and maintaining energy efficiency.
A flexible emissions forecasting tool has been developed which allows unit and whole of facility emissions reduction and energy efficiency options to be assessed. The tool builds on current quarterly timestep production forecasts and models ambient temperature, unit turndown and turn-off strategies, and potential brownfields modifications.
The ability to generate and compare life of field emissions profiles for extrapolated operating modes and proposed modifications allows unit strategies and phasing of emissions reduction modifications to be investigated and screened before further economic assessment and creation of marginal abatement cost curves (MACC).