bluuebunny/crossref_metadata_2025 huggingface dataset:
Concurrent 2. Presentation for: Techno-economic evaluation of blue hydrogen production with carbon capture and storage for onshore Eastern Australia
Authors: Owen J. Gregory
Published: June 2022

Presented on Tuesday 17 May: Session 2 This techno-economic assessment models the feasibility of a greenfield blue hydrogen development with production capacity of 400 tons of hydrogen per day (TH2/day). At an assumed 85% CO2 recovery rate, the 400 TH2/day production scale equates to a need for approximately 1.241 million tons of CO2 per year (MtCO2/year) of subsurface CO2 storage capacity over an assumed project life of 25 years (approximately 31 Mt of total CO2 sequestered). The blue hydrogen production technology applied to the assessment is a Steam Methane Reformer (SMR) with two points of CO2 recovery (pre-combustion process stream amine scrubbing and post-combustion flue gas capture). The remaining key scope components are the CO2 compression and dehydration system, 65 km of CO2 distribution pipeline and a CO2 injection and storage hub comprised of three injection wells, three deep observation wells and three groundwater monitoring wells. The study includes the screening process applied to identify five high-grade depleted gas reservoirs in the Cooper Basin that are the CO2 storage candidates, and which ultimately define the project location. The economic evaluation of the project includes the definition of cost and operations estimates to determine a mean project case and then applies a Palisade @Risk probabilistic distribution model to key project inputs as to risk the project under various scenarios. The analysis concludes that the economic viability of large-scale, greenfield blue hydrogen projects in Australia is highly dependent on hydrogen sale price, Australian Carbon Credit Unit (ACCU) value, wholesale natural gas prices and capital cost efficiency. To access the presentation click the link on the right. To read the full paper click here
Concurrent 5. Presentation for: Pluto 4D Monitor Two – a second outstanding success
Authors: Mann Sandra
Published: June 2022

Presented on Tuesday 17 May: Session 5 A second 4D seismic monitor survey acquired over the Pluto gas field has been an outstanding success despite three tropical cyclones, the start of a global pandemic, and technical subsurface risks. At the time of the Pluto 4D Monitor Two (M2) survey (December 2019 till February 2020), the Pluto field had been in production for 7 years and 9 months and had produced approximately 2 Tcf of gas. The M2 4D survey was acquired between December 2019 and February 2020 over a 20 × 30 km area, on a 12.5 m square grid. Data was processed by CGG to pre-stack depth migration, took 6 months to deliver, and required considerable collaboration with Woodside geoscientists. Use of modern processing technologies, including least squares migration, full waveform inversion and wave equation based amplitude versus offset inversion facilitated a high quality interpretation. On the 4D difference volumes, hardening responses were interpreted as water ingress. Hardening responses were seen in multiple Triassic reservoirs. A pronounced response was seen in a large Triassic valley within a predominantly mudstone background unit, which showed continued water ingress into the valley, upwards from the gas water contact towards the producing well. This confined hardening response contrasted with unconfined, water flood front responses seen in other reservoirs. Both responses enabled detailed interpretation of geological features and provided useful control points for history matching. Interpreted water ingress also gave additional depth control. To access the presentation click the link on the right. To read the full paper click here
Concurrent 5. Presentation for: Seamless in seam – new geosteering technology delivered challenging coal seam gas project with success
Authors: Wang Haifeng
Published: June 2022

Presented on Tuesday 17 May: Session 5 A recent coal seam gas (CSG) appraisal project posed several challenges. The target reserve area had limited seismic data available and yet had complex structure with several faults of variable orientations and throws between 2 and 25 m. Dual-lateral extended-reach drilling (ERD) wells needed to be drilled in order to access this reserve, with a 1000 m in-seam section for each lateral planned to maximise production. Conventional technologies for CSG projects included motor bottom hole assembly with a boundary mapping tool for geosteering in the coal seams. However, for drilling ERD wells in this unknown area, these methods were insufficient to deliver success, due to the limited mapping capabilities and drilling efficiencies. Recently there has been significant development on the directional resistivity-based mapping tool, on both the measurements and processing. The operator adopted a new mapping-while-drilling technology which has the first-in-industry tool with axial, tilted and transverse antennas integrated in one module. This new technology can provide high-resolution multilayer mapping with doubled depth of investigation, even when drilling out of the coal seam. The results from utilising this new tool, together with a rotary steerable system for directional control, were very encouraging. The new multilayer mapping-while-drilling tool mapped both the top and base of the coal seam throughout horizontal sections in-seam. In addition, it detected the coal seams during landing and after fault-crossing from up to 4 m true vertical depth away, enabling the team to navigate through complex fault zones confidently, and to deliver the project with success. To access the presentation click the link on the right. To read the full paper click here
Concurrent 10. Presentation for: Embracing technology to deliver an intelligent Scarborough offshore facility
Authors: Pritchard Thomas
Published: June 2022

Presented on Wednesday 18 May: Session 10 The Scarborough gas field is located approximately 375 km offshore the Burrup Peninsula in approximately 900 m water depth. The Scarborough Project will process gas from the field through a new semisubmersible Floating Production Unit (FPU), then through an onshore LNG facility. Woodside’s Operations and Project teams have focussed on enabling safe, reliable, and efficient operations to be realised throughout the facility operating life. Woodside has adopted a justify in, design out, embrace technology approach to meet this requirement. At the heart of this approach is the requirement to minimise the time required for personnel to be present on the facility. This is being achieved by utilising technology in design and innovative equipment and material selection. The FPU will be remotely controlled from an Integrated Remote Operations Centre located in Perth. Critical equipment located offshore will be constantly monitored for condition and performance with data able to be analysed efficiently, enabling effective and timely decisions. An extensive digital environment will be utilised to capture information and allow for intelligent solutions to aid this analysis. Materials and coatings have been selected to meet the design life and reduce maintenance-intensive refurbishment requirements. Offshore equipment can be remotely reset and restarted and includes appropriate sparing to maximise availability. Maintenance and environmental benefits have been realised by selecting electrical alternatives for lifeboats and cranes with a large installed battery system enabling a reduction in spinning reserves. This strategy will result in a lower emissions facility with reduced operating costs and offshore exposure hours. To access the presentation click the link on the right. To read the full paper click here
Concurrent 10. Presentation for: Collaborating to bring new technology on developments
Authors: Witton Ben , Tachoires Vincent
Published: June 2022

Presented on Wednesday 18 May: Session 10 Project delivery certainty is a key a success factor for positive business outcomes. Taking on world first applications across multiple delivery streams comes with risk that requires significant risk reduction to meeting business requirements. The Julimar Development completed this successfully across both drilling and completions, and subsea. Reliable multizone completions with robust sand control have traditionally been a challenge in high-rate gas wells. Cased hole stacked gravel packs can leave high mechanical skin, require multiple trips and are complex operations. While Open Hole Gravel Packs (OHGPs) have provided reliable sand control in such wells, multizone applications have been limited due to the tradeoff between effective gravel placement and zonal isolation. Recent developments in technology have enabled reliable gravel placement and complete zonal isolation. The collaboration between Woodside and Subsea 7 has delivered an ‘industry first’ on the Julimar Project, with the completion of an 18″ Corrosion-Resistant Alloy (CRA) gas transmission flowline installed via reel-lay – the largest diameter insulated CRA pipeline ever reeled. For background, most projects have traditionally used the ‘S-Lay’ method for installing pipe in Australia – the reel-lay method is less common. A key benefit of the reel-lay method is it removes thousands of welds from the offshore installation vessel critical path, transferring them onshore into a safer, quality-controlled environment earlier in the schedule. Pipe joints are welded into ‘stalks’ which are then spooled onto purpose-built reel-lay vessels. Woodside and Subsea 7 were able to jointly demonstrate the safety, quality, technical and cost advantages of this innovative but field-proven reeled pipe-lay technology. The 18″ CRA flowline is a tangible example of the performance that can be delivered through early collaborative engagement and strategic investment in technology and is a step change in Australia and the industry. This joint presentation discusses contracting, design, execution and evaluation of technologies on the Julimar Development. It includes the method followed for reel-lay technology selection, engineering development, post project evaluation and the health and safety benefits. The presentation provides both the Operator and Contractor perspectives on the challenges of implementing new technology in developments in Australia. To access the presentation click the link on the right. To read the full paper click here and also here.
Concurrent 11. Presentation for: A seismic shift in engagement with the fishing industry? A case study of the Prion 3D marine seismic survey in Bass Strait
Authors: French Linda , Sullivan Andrew
Published: June 2022

Presented on Wednesday 18 May: Session 11 The relationship between the oil and gas and commercial fishing industries could be described as strained and at times highly combative. The source of much of the conflict has been conjecture around the impacts of seismic surveys on the marine environment, and of course impacts to commercially targeted species. These relationships exacerbate the challenges for oil and gas proponents in progressing new exploration activities and the relevant environmental approvals. We provide an example of how genuine engagement and collaboration between the two industries, and their broader networks, can lead to a better understanding of the needs of each sector. In turn, this can lead to investment into research to address shortfall in knowledge around impact and technical advances to mitigate potential impacts. Directed research to address key knowledge gaps is a critical component for coexistence of industry in the marine domain. Investment in research that reduces uncertainty for all sectors is critical for future petroleum exploration and exploitation. Researcher studies undertaken during the Prion 3D marine seismic survey include: (1) whether novel seismic survey sources mitigate potential impacts to fisheries; (2) before after control impact (BACI) assessment and biomass studies of scallops; and (3) validation of sound modelling. We examine some of the key decisions taken during the Prion 3D marine seismic survey development process and discuss how these were taken and how things may have otherwise ended without genuine engagement by both parties. To access the presentation click the link on the right. To read the full paper click here
Concurrent 11. Presentation for: INPEX-led Ichthys Joint Venture – proudly partnering with Indigenous Groups in the Northern Territory
Authors: Corbett Joshua J.
Published: June 2022

Presented on Wednesday 18 May: Session 11 The INPEX-led Ichthys Joint Venture has established strong partnerships with the Northern Territory Government (NTG), cultural organisations and Traditional Owner groups in the Northern Territory to deliver social and environmental offset programs. The key governance model for delivery of the offset programs is the Ichthys Project Voluntary Offset Agreement (IPVOA), which commits $91 M AUD over a 40-year period through a suite of offset programs. This paper focuses on the journey to partner with the NTG-run Aboriginal Ranger Grants Program (ARGP). Through the IPVOA, INPEX and its Ichthys Joint Venture participants will contribute $24 M AUD over 22 years, to the ARGP, for Aboriginal Ranger programs addressing specific species and their associated habitat throughout the Top End. This is the first time where industry has contributed to the ARGP to deliver positive outcomes in the NT. This has been achieved by fostering collaborative, engaging and trustworthy relationships with the Commonwealth and NT governments; engaging with the Aboriginal Land Management Advisory Group; and meeting with Aboriginal Ranger groups. The key has been finding a common ground between the perspectives and the priorities of all stakeholders for how best to deliver conservation management on country in the NT. This common ground is likely to evolve over the next 22 years as the INPEX-led Ichthys Joint Venture and NTG deliver environmental outcomes, promote a connection to country and empower Aboriginal Ranger groups to better manage their country for future generations. To access the presentation click the link on the right. To read the full paper click here
Concurrent 14. Presentation for: West Barracouta – 50 years in the making
Authors: Chigwidden Daniel
Published: June 2022

Presented on Wednesday 18 May: Session 14 This paper presents a case study on the value of combining existing ideas with new data to evaluate and determine the most effective way to extend the producing life of one of the first offshore gas discoveries in the Gippsland Basin. The holistic work approach resulted in the development of West Barracouta Top Latrobe gas by two dual-zone, subsea intelligent wells with sand control, tied back to an operating pipeline to minimise brownfields interface. Located in the Gippsland Basin, the Barracouta gas field was Australia’s first discovery, by the first offshore well, and soon after the first operating offshore facility. After more than 50 years of oil and gas production, new data gives further insight to support continuous improvement in reservoir management to optimise the resource to end of field life. Originally discovered in 1969, West Barracouta is separated from the main field by a fault-induced saddle point that left a substantial volume without an active completion. With the Gippsland legacy gas fields declining, the West Barracouta development is well timed to supply the Australian East Coast gas market with one of the last remaining low-CO2 gas sources and ensure additional security of supply. Incorporating reprocessed seismic data into the workflow delivered improved confidence in field definition, providing a foundation for a technology-driven development plan. This paper addresses the technical workflow that was implemented to support a fast-paced subsea development, robust against the range of possible geological scenarios. To access the presentation click the link on the right. To read the full paper click here
Concurrent 14. Presentation for: The transformation of Australia’s first commercial CSG field into a major gas project: how innovation and subsurface understanding has driven its success
Authors: Martin Mike
Published: June 2022

Presented on Wednesday 18 May: Session 14 Mount Isa Mines Limited discovered coal seam gas (CSG) in the ‘Dawson Valley’ in 1991. It was the first commercial coal seam gas field in Australia, with production and sales of gas commencing circa 1994, then operated by Conoco and known as Meridian SeamGas. In 2010, Westside Corporation acquired a 51% operating interest in Meridian SeamGas from Anglo American (Anglo) and Mitsui Moura Investment Pty Ltd (MMI). Over the last 10 years, Westside has increased sales by 466% from 9 terajoules per day (TJ/d) to 42 TJ/d with gas being sold to both domestic and export markets. Further acreage acquisition to the north and south increased the asset area by 264%; now known as the Greater Meridian Fields (GMF). The steep rise in gas demand, complex market dynamics, regulatory environment, and competition from large global oil and gas operators makes it a challenging environment for smaller gas producers in Australia. Remaining agile and employing innovative approaches to optimise field development are key factors for Westside’s growth. In particular, the pad-based drilling of up dip multi-lateral wells has reduced cost and surface footprint, while enabling more efficient gas drainage. To support this field development, a more robust subsurface framework was required. Adequate knowledge of the distribution and variability of coal thickness, gas content/composition, structure, and geohazards forms the basis of the static model. It is used for resource definition and for the optimal planning and execution of multi-lateral wells, reducing drilling risks. To access the presentation click the link on the right. To read the full paper click here
Concurrent 15. Presentation for: Technological advances in biosecurity monitoring
Authors: Marks Barbara A.
Published: June 2022

Presented on Wednesday 18 May: Session 15 Biosecurity tools are a key aspect of an effective biosecurity system, however, existing surveillance and monitoring programs are often expensive, resource intense, reliant on special expertise, long-term and deliver variable results. Advances in innovation and technology provide opportunity to improve program efficiency, reliability and cost-effectiveness. Chevron Australia developed and deployed tools to help monitor and identify non-indigenous species on Barrow Island, a Class A Nature Reserve and home to the Gorgon Natural Gas Project, operated by Chevron Australia and a joint venture of the Australian subsidiaries of Chevron (47.3%), ExxonMobil (25%), Shell (25%), Osaka Gas (1.25%), Tokyo Gas (1%) and JERA (0.417%). Tools include: The PAWS® (Print Acquisition for Wildlife Sensors) pest identification sensor pad and PAWS® live capture devices for rodent detection and monitoring, EARS (Environmental Acoustic Recognition Sensor) devices that record the male Asian house gecko’s call and can be adapted to incorporate other species if required, LAMP (Loop Mediated Isothermal Amplification) assay to identify Asian house gecko scats or tissue samples with an in situ molecular tool, Gecko identification application (app) enabling the workforce to participate in citizen science programs. These technological advances have helped to improve surveillance and biosecurity programs on Barrow Island, realising benefits including: longer monitoring periods for lower costs, resulting in greater confidence in surveillance outcomes, in situ diagnostics providing more rapid identification to enact an immediate response; deployment of live capture devices, reducing non-target captures (consequently, a more ethical tool); wider workforce participation. While these innovative tools target species likely to threaten Barrow Island’s unique biodiversity, the technology can be adapted for other environmental monitoring programs. To access the presentation click the link on the right. To read the full paper click here
Concurrent 15. Presentation for: Impacts of exposure to a seismic source survey on silverlip pearl oysters (
Authors: Meekan Mark G.
Published: June 2022

Presented on Wednesday 18 May: Session 15 Between 2018 and 2021, AIMS and its partners conducted a large-scale experiment to investigate the effect of exposure to a 3D seismic survey on pearl oysters. In August 2018, ≈11 000 adult wild silverlip pearl oysters (Pinctada maxima) were collected and attached to bottom culture lines to acclimatise for 1 month at a holding lease site, 40 km off Broome, WA. These oysters were split across rows configured parallel to each other at seven horizontal distances up to 6000 m from a ‘zero line’. In September 2018, we sailed a commercial seismic vessel along one 20 km-long inactive (vessel control) sail line along the zero line, followed by six operational (exposure) sail lines, at increasing distances from the zero line, with each line separated in time by either 12 or 24 h. This design resulted in groups of pearl oysters with 35 different exposure histories (seven distances, five exposure distances) that were then transferred to undergo either lethal biophysical sampling or pearl seeding for a ‘grow-out’ study of pearl production. Biophysical sampling included immunology tests, primarily using flow cytometry and gene expression changes in nacre- and stress-associated genes. Audits of oyster growth and condition were conducted at various time points between the exposure period and harvesting of the seeded oysters. The number and quality of pearls produced by each exposure group was assessed 2 years after exposure (December 2020). The results of these analyses are being finalised for presentation. To access the presentation click the link on the right. To read the full paper click here
Concurrent 15. Presentation for: Guidance document: Incident Management Teams – Knowledge requirements for responding to marine oil spills
Authors: Hazell Daniel
Published: June 2022

Presented on Wednesday 18 May: Session 15 The National Offshore Petroleum Safety and Environmental Authority undertakes the assessment of environmental plans and oil pollution emergency plans for petroleum activities in Australian Commonwealth waters. In 2019, the Australian Petroleum Production and Exploration Association’s Oil Spill Preparedness and Response Working Group (OSPRWG) developed a work program to address identified Incident Management Team (IMT) training issues, with an aim to develop industry good practice guidance in relation to IMT skills, competencies and oil spill training. The OSPRWG has now produced a guidance document on IMT oil spill training, that was developed in collaboration with the Australian Marine Oil Spill Centre and peer reviewed by Oil Spill Response Limited. The guideline should facilitate a greater and more coordinated mutual aid IMT oil spill capability within the Australian offshore petroleum industry. To access the presentation click the link on the right. To read the full paper click here
Concurrent 17. Presentation for: The story of Esso Australia’s push to explore the frontier Gippsland Basin with the ultra-deep water Sculpin-1 exploration well
Authors: Spencer Steven
Published: June 2022

Presented on Wednesday 18 May: Session 17 In late 2018, Esso Australia embarked on the drilling of Sculpin-1. Drilled in 2278 m of water, this is Australia’s deepest water exploration well and the first ultra-deep water well in the Gippsland Basin. Drilling of this well was the culmination of a bold exploration campaign in the VIC/P70 permit at the southeastern margin of the prolific hydrocarbon producing Gippsland Basin, which also saw the drilling of Baldfish-1 and Hairtail-1 in 2018. An east coast gas market with a high demand for additional gas resources combined with Esso Australia’s renewed technical focus on the deep and ultra-deep water sectors of the VIC/P70 exploration permit led to the identification of the Sculpin prospect, a stratigraphic lead premised on a late Cretaceous deep water reservoir system flowing into the south east Gippsland Basin depocentre from southern hinterlands. Technical analysis including integrated seismic toolkits, spectral decomposition and colour-blend imaging, rock properties and amplitude versus offset/direct hydrocarbon indicator modelling were key to Esso’s decision to test the new play with the Sculpin-1 well. Although the well did not encounter hydrocarbons, it did provide insights into reservoir quality, source and migration in the previously untested southeastern margin of the basin. To access the presentation click the link on the right. To read the full paper click here
Concurrent 17. Presentation for: Petroleum supersystems in the greater McArthur Basin, Northern Territory, Australia: prospectivity of the world’s oldest stacked systems with emphasis on the McArthur Supersystem
Authors: Jarrett Amber J. M.
Published: June 2022

Presented on Wednesday 18 May: Session 17 This study assesses the prospectivity of the world’s oldest known stacked petroleum systems from the Proterozoic greater McArthur Basin (Northern Territory, Australia), which has immense potential to host both conventional natural gas and oil, in addition to shale-gas accumulations. The Mesoproterozoic succession of the Beetaloo Sub-basin and surrounding region hosts the Territory’s premier shale-gas play and is at an advanced stage of exploration for shale hydrocarbon plays. However, there is also potential for natural gas in older sedimentary packages, with flows and shows reported in underlying Paleoproterozoic successions. At the continent-scale, four regional petroleum supersystems are identified and described in order to provide a platform for consistent nomenclature at the sedimentary package and group level; in ascending stratigraphic order; these are the Paleoproterozoic Redbank and McArthur supersystems, the Paleoproterozoic–Mesoproterozoic Lawn Supersystem, and the Mesoproterozoic Beetaloo Supersystem. The Redbank and Lawn supersystems are newly named and defined, and the Beetaloo Supersystem is renamed from the former Urapungan Supersystem. Eight possible conventional natural gas plays and six shale-gas plays are documented within the McArthur Supersystem, which incorporates Glyde Package successions of the McArthur Basin and the Birrindudu Basin. Petroleum play concepts are also described from this supersystem to assist with assessing the potential for gas resources. A better understanding of the petroleum systems of the greater McArthur Basin is critical to the targeting of areas for geoscience data acquisition in order to facilitate the reduction of exploration search space; and it enables a more rigorous assessment of the potential for conventional and unconventional hydrocarbon resources at local (play) and regional scales. To access the presentation click the link on the right. To read the full paper click here
Concurrent 18. Presentation for: Co-application of micro-proppant with horizontal well, multi-stage hydraulic fracturing treatments to improve productivity in the Permian coal measures, Bowen Basin, Australia
Authors: Ramanandraibe Honja Miharisoa
Published: June 2022

Presented on Wednesday 18 May: Session 18 Coal permeability is the key discriminator in well completion selection in coal wells. Low productivity is often attributed to compartmentalisation and pressure-dependent permeability (PDP) effects. Often, vertical well hydraulic fracturing is used to enhance productivity from lower-permeability coals, however, several authors have noted that coal fracture treatments can generate a large unpropped area of stimulated reservoir volume (SRV) that is generated from natural fracture activation and pressure-dependent leakoff. The result of this study confirms previous studies (using radial, cartesian, and enhanced SRV analytic models) that graded particle or micro-proppant injections in conjunction with hydraulic fracture treatments can be a means to enhance coal productivity in PDP-affected or low-permeability coals. In this work, data from the Bowen Basin will be used to investigate the implementation and benefits of micro-proppants in conjunction with horizontal well, multi-stage, hydraulic fracture treatments. The calibrated model will be based on a Bowen Basin case incorporating petrophysical, diagnostic fracture injection test (DFIT), hydraulic fracture, and can utilise production data to constrain modelling parameters. To better understand and provide guidance on co-application of horizontal, multi-stage hydraulic fracturing in conjunction with micro-proppant injections, a range of factors will be evaluated in this model including initial permeability, permeability anisotropy, fracture half-length, area and conductivity of the enhanced region between fractures, lateral length, and the number of fractures. This model will demonstrate the effectiveness, economic benefits, and optimal number of fracturing stages based on the reservoir parameters. To access the presentation click the link on the right. To read the full paper click here
Concurrent 18. Presentation for: Wireline packer remediation using novel bismuth technology
Authors: Hochberg Isaac , Dalianas Konstandinos
Published: June 2022

Presented on Wednesday 18 May: Session 18 Prior to the execution of this project, there were limited options for repairing a failed production packer. Conventional oilfield practice would default to a well workover to replace the failed component. In an offshore environment, this approach not only carries significant capital cost, but also material risk and health, safety and environment exposure associated with the large operational footprint and time requirement of the operation. An innovative solution was developed to remediate the failed packer without a workover while simultaneously significantly reducing cost and risk. A new packer was formed by melting a bismuth alloy plug into the annulus using wireline equipment, eliminating the requirement for a workover rig. Bismuth alloy pellets were deposited onto the packer via precisely drilled holes in the tubing before being melted into an annular plug, forming a gas-tight metal-to-metal seal. As this was an industry first, prototype testing of the annular bismuth plug was undertaken to demonstrate concept feasibility. After a series of iterative testing a viable concept was achieved, and the prototype was taken forward to qualification. The annular plug was qualified to industry standard ISO 14310 V0 for the well’s operating conditions which included both pressure differential and axial loads. After the bismuth annular plug was qualified, the deployment method for the bismuth pellets was optimised to ensure they reached targeted location without compromising well integrity. After 2 years of design, the industry-first wireline intervention was successfully executed in 2021 and the well was returned to production. To access the presentation click the link on the right. To read the full paper click here
Concurrent 19. Presentation for: Developing an in-depth understanding of PFAS to deliver an effective remediation strategy
Authors: Turner Lucas
Published: June 2022

Presented on Wednesday 18 May: Session 19 Esso Australia Resources Pty Ltd and BHP Petroleum (Bass Strait) Pty Ltd own a range of offshore and onshore hydrocarbon production facilities, which have been operated by Esso Australia Pty Ltd (Esso) for over 50 years. The Longford Fire Training Ground (FTG) is located adjacent to the Longford Plants and has been utilised by Esso for many years to train personnel in practical hydrocarbon firefighting skills, including applying firefighting foams to extinguish liquid hydrocarbon pool fires. In line with historical standard oil-field practices, per and polyfluoroalkyl substance (PFAS) containing firefighting foams were used at the Longford FTG. In response to the reported use of these foams and the potential for contamination associated with historical site operations, the Longford premises were the subject of recent environmental audit and clean-up plans with oversight by an EPA Victoria auditor. Esso engaged a broad range of experts to complete the environmental investigation and develop a remediation action plan that complied with the PFAS National Environmental Management Plan. Key aspects of this project included: understanding the location and setting, with respect to geological conditions and groundwater impacts; development of remediation objectives and strategy; identification of practical remediation methods including short-term and longer-term measures to mitigate priority PFAS sources within the FTG; and a planning framework for future management of the premises. This paper shares how a responsible operator applies a disciplined and scientifically based environmental approach to further the state of knowledge on practical PFAS remediation methods and achieve a sustainable environmental outcome in the communities that they operate in. To access the presentation click the link on the right. To read the full paper click here
Concurrent 20. Presentation for: Finding winners in the hydrogen hype
Authors: Sharma Prakash
Published: June 2022

Presented on Wednesday 18 May: Session 20 The global energy trade is set for its greatest transformation since the 1970s and the rise of OPEC (The Organization of the Petroleum Exporting Countries). Electrification is central to this as countries plough money into renewables to reduce emissions and enhance energy security. But electrification can take the world only so far. With higher carbon prices looming on the horizon, fossil fuel exporters and industrial sectors – as well as heavy-duty trucking, shipping and aviation – need alternatives to decarbonise. Most are looking to electricity-based fuels and feedstocks such as hydrogen, ammonia and methanol to replace hydrocarbons. This will revolutionise energy trade, with total trade declining by as much as 50% and virtually all remaining traded oil gas and coal being either completely decarbonised or backed by offsets. With 147 GWel (giga‐watts electrolyser capacity) in announced projects, green hydrogen produced from renewable electricity is ahead of the game. And while its export supply chains are complex, requiring conversion into a ‘product’ to allow delivery, there is no exploration risk as in oil and gas projects. Worldwide, national hydrogen roadmaps are being passed, with virtually all oil and gas companies, utilities and industrials backing at least one hydrogen project. Focus is now shifting to future sources of hydrogen supply. Lenders will be drawn to locations with a proven track record of exporting natural resources, suitable conditions for low-cost renewable electricity and the potential for large-scale carbon capture. A few countries already stand out, but none more so than Australia. Using our proprietary research, we will present a case study evaluating hydrogen supply options from Australia, Saudi Arabia and Canada – delivered into key markets like Japan for different applications. We will also assess when costs will fall across the value chain – production, midstream and downstream – and reach parity to incumbent fuels. To access the presentation click the link on the right. To read the full paper click here
Concurrent 20. Presentation for: Suitability of depleted gas fields for underground hydrogen storage in Australia
Authors: Michael Karsten
Published: June 2022

Presented on Wednesday 18 May: Session 20 If there is a significant adoption of hydrogen in Australia as an energy carrier, it will be necessary to have storage options to buffer the fluctuations in supply and demand, both for domestic use and for export. For large-scale storage in a single location, underground hydrogen storage (UHS) is the preferred option for reasons of both cost and safety. The search for suitable sites for UHS will depend on the proximity to potential hydrogen generation, ports, and processing infrastructure, as well as CO2 storage options for blue hydrogen. Although UHS in salt caverns is an established technology, most of the suitable salt deposits in Australia (in the Canning Basin in WA, the Adavale Basin in Qld, and the Amadeus Basin in the NT) are not always well-located for production and transport. Depleted gas fields have been used previously for storage of hydrogen-rich gas mixtures as well as natural gas storage and appear to be the most promising and widely available UHS option in Australia. There appears to be sufficient storage capacity in depleted gas fields in most of the geographic areas with hydrogen production potential. However, there are still technical challenges to be addressed, such as the extent of possible contamination of the stored hydrogen with residual hydrocarbons, and the possible effects of geochemical reactions and microbial processes. To access the presentation click the link on the right. To read the full paper click here
Concurrent 22. Presentation for: Extracting events from Daily Drilling Reports using Fuzzy String Matching
Authors: Duque Maria Clara
Published: June 2022

Presented on Thursday 19 May: Session 22 Continuous monitoring of oil drilling operations reduces process interruptions and equipment failure. It also contributes to the development of Key Performance Indicators, which leads to more efficient resource management. Daily Drilling Reports (DDRs) have long been the primary way of recording noticeable events, such as stuck pipe. DDRs came to constitute a valuable information base for most oil drilling companies. However, the task of extracting knowledge from DDRs can be costly and time-consuming. This work proposes an approach to recognise drilling events in DDRs using a rule-based language processing method called Fuzzy String Matching (FSM). We applied the FSM algorithm to search for a set of predefined keywords and key phrases to extract possible Invisible Lost Time (ILT) events from DDRs that may indicate risks or low operational efficiency. The fuzzy part of the algorithm allows the identification of terms or expressions that match the pre-established ones approximately rather than exactly, accounting for typos and different suffixes or prefixes. The proposed solution was applied on a data set of 392 real-world DDR records from a drilling company using a set of six ILT event’s key phrases annotated by Subject Matter Specialists. This process can be readily replicated to other events. The results show that in 116 reports tagged as normal, 92 records were identified as possible ILT events, which represents, in hours, 56% of the total drill normal time. Such promising results can lead to very significant improvements in identifying and extracting drilling events within DDRs. To access the presentation click the link on the right. To read the full paper click here
Concurrent 22. Presentation for: Central Queensland hydrogen project
Authors: Richardson Phil , Wauchope Antony
Published: June 2022

Presented on Thursday 19 May: Session 22 Renewable hydrogen is being heavily promoted around the world for energy storage, and to support the decarbonisation of energy systems. Queensland is well placed for hydrogen export to Asia and is actively working to make this a reality. Stanwell Corporation, together with its project partners Iwatani, APA Group, Kawasaki Heavy Industries, Marubeni and Kansai Electric Power Company, is working to develop a commercial world-scale project to produce and export hydrogen from Gladstone to Japan, supporting Japan’s Net Zero by 2050 commitment. The size of the hydrogen production system (3 GW) is significant and as a first of a kind in Queensland raises several technical, regulatory and social challenges. To highlight the scale of the project, the renewable power generation to be installed to support this project will have a capacity equivalent to the current Queensland daily power demand. There are several challenges, one being that solar and wind energy resources by their nature are variable. Identifying and defining the mix of renewable energy to achieve a reliable power supply, and integrating this with the electrolyser systems, will be key to the success of the project. The upgrades required to existing power transmission infrastructure are significant, while additional water supply in the Gladstone region will be required. Finally, recent developments in Gladstone have created a boom–bust cycle and the social acceptance of this development requires ongoing engagement to address community concerns. To access the presentation click the link on the right. To read the full paper click here
Concurrent 24. Presentation for: Net zero hero – five strategies for oil and gas producers
Authors: Farrell Bradley
Published: June 2022

Presented on Thursday 19 May: Session 24 In the last 12 months, Australian oil and gas producers have been busy announcing their ambition to become ‘net zero emissions’ businesses by 2050, or sooner. Achieving this will require a significant shift in strategy in how companies operate, and in what they produce. In pursuing these new net zero ambitions, we see five major strategies in play: reducing scope 1 and scope 2 emissions; deployment of carbon capture, utilisation and storage (CCUS) technologies; use of general and cargo-specific carbon offsets; pursuit of hydrogen production at scale; and displacing higher-emissions fuels in the global energy mix. This paper provides an overview and integrated programmatic approach to realise these strategies, including a case study from a recent global oil and gas producer. To access the presentation click the link on the right. To read the full paper click here
Concurrent 24. Presentation for: Looking down the (oil) barrel of a class action?
Authors: Freeman Anne
Published: June 2022

Presented on Thursday 19 May: Session 24 Class actions against oil and gas companies are nothing new. More than 15 years ago, Esso settled the action against it by businesses suffering property damage and economic loss from that damage following the Longford gas explosion for $A32.5 million. There have been other class actions following oil spills, and others by shareholders for alleged breaches of continuous disclosure obligations. With the focus of investors increasingly on climate change disclosure, and some courts now finding expanded duties of care owed in relation to climate change, oil and gas companies can expect to see more actions in the future, including claims of ‘greenwashing’, like the one issued by a shareholder against Santos in August 2021 relating to statements made in Santos’ 2020 annual report. This paper provides some practical tips for companies facing class action proceedings, including preparatory steps which can be taken, such as establishing internal and external teams, dealing with insurers, as well as preserving and locating relevant documents. It provides recommendations about appropriate internal and external communication about the claim so as to avoid issues like waiver of legal professional privilege and PR problems, and it addresses some enquiries which should be made about opponents, as well as the judge assigned to the matter. Specific considerations arise in funded class actions, in light of recent regulatory changes. Early checks should be made as to whether the litigation funder holds an Australian Financial Services Licence and whether the funding arrangement has been properly established as a managed investment scheme. To access the presentation click the link on the right. To read the full paper click here
Geoscience Poster G1: Origins of hydrogen sulfide (H
Authors: Chalmers Gareth R. L.
Published: June 2022

Poster G1 The distribution and origin of hydrogen sulfide (H2S) within gas reservoirs is an important issue due to its toxicity and ability to corrode metal infrastructure, even at low concentrations (i.e. 50 ppm). H2S gas is regarded as a high priority for health and safety at drilling sites. The distribution of H2S, in some basins, can be inexplicable with a mix of sweet (no H2S) and sour (contains H2S) wells within one multi-well pad. Sour gas is a concern in some gas and coal fields in Australia which include Gippsland, Bowen and Cooper-Eromanga basins as well as in the North West Shelf with typical concentrations below 10 000 ppm. For example, the German Creek Formation (Bowen Basin) contains up to 77 ppm of H2S gas and coal seam gas producers will need to perform a risk assessment while exploring and developing this resource. There are multiple sources of H2S gas sulfur and this includes sulfate minerals, pyrite, organic sulfur or from frack water. This research utilises the isotopic variation in the sulfur and oxygen of potential sources, coupled with petrological analyses to determine H2S gas generation. Data is used to predict the gas distribution within the reservoirs to reduce exploration risks. One initial study on the Triassic Montney Formation in western Canada produces H2S gas at concentrations up to 220 000 ppm. Isotopic analyses suggest that the H2S is generated from either Triassic sulfates or a mixture of Triassic and Devonian sources and not solely from Devonian rocks as first expected. To access the poster click the link on the right. To read the full paper click here
Geoscience Poster G3: Application of a probability model to detect unrecognised igneous intrusions in sedimentary basins
Authors: Holford Simon
Published: June 2022

Poster G3 Mafic igneous intrusions are a common feature in extensional sedimentary basins, particularly those located at volcanic rifted margins, and are important in both exploration and development contexts due to their range of interactions with the petroleum system and their role as potential drilling hazards. Experience from a range of basins containing mafic igneous intrusions suggests that seismically resolvable intrusions are typically accompanied by a large number of intrusions that are too thin to be confidently identified and interpreted from seismic reflection surveys. The increased vertical resolution of wireline log data affords an opportunity to identify such sub-seismic-scale intrusions, though in many wells with full wireline suites igneous intrusions are often misidentified as sedimentary units, including felsic intrusions whose physical properties are more similar to sedimentary rocks. Here we apply a wireline-log-based probability model to well data from a number of basins. In previous applications, the model has proven highly effective in predicting the occurrence of carbonate cementation zones in sandstones in comparison to neural network approaches. We demonstrate its ability to predict the presence of igneous intrusions that were not previously identified by either seismic interpretation, or through the analysis of well-derived datasets. The broader application of this model to large suites of legacy data could lead to improved knowledge of the occurrence of intrusions in basins with implications for basin modelling and well planning. To access the poster click the link on the right. To read the full paper click here