Presented on Tuesday 16 May: Session 2 This paper reviews and summarises the work that has been conducted and the technology used in exploring and developing the Northern Bowen and Galilee basins in Queensland. It examines the methods operators have used in drilling, completing and testing wells through the varying stages of exploration, appraisal and development in the different parts of the basins. It examines all the work conducted in the Betts Creek Beds and Aramac Coal Measures throughout the Galilee Basin; the Moranbah Coal Measures, Rangal Coal Measures and Fort Cooper Coal Measures in the Moranbah area of the Bowen Basin; the Rangal Coal Measures, Burngrove Formation and Fairhill Formation in the Blackwater area; the conventional and coal seam gas developments in the Rolleston area, including the Bandanna Formation plays near Injune; and the Baralaba Coal Measures in the Moura area. Wells have been completed both open and cased hole with techniques including vertical wells, both with and without hydraulic fracturing and cavitation, as well as a variety of horizontal well designs including surface to inseam wells with vertical intercept wells and multiple lateral sections, chevron wells and both heel and toe intercepts. Operators have also implemented multiple wells on one pad. Throughout the Northern Bowen Basin, horizontal well drilling has been a key technology in commercial development. Generally, activities within the Galilee Basin have not progressed as far as the Bowen Basin, but nevertheless, horizontal wells are also emerging as a key technology. To access the Oral Presentation click the link on the right. To read the full paper click here
Presented on Tuesday 16 May: Session 8 It is an appalling reality that about 50 million people worldwide live under the constraints of modern slavery conditions, such as forced labour, worst form of child labour, debt bondage, servitude and deceptive recruitment and so on. In Australia, the federal government has launched the Modern Slavery Act 2018 (Cth), which sets mandatory criteria for an applicable entity to issue a modern slavery statement. However, there is a clear absence of actionable guidelines for companies to follow, in order to assess and address risks of modern slavery within their value chain. Ambiguous legislative requirements have resulted in poor monitoring that, ultimately, does not effectively help eradicate modern slavery from Australian supply chains. In order to address this gap and provide a practical tool for organisations to combat modern slavery, this article employs a case study to demonstrate how to conduct effective on-site audits to mitigate modern slavery risks through the supply chain. A set of critical factors and potential solutions to remove barriers are discussed. To access the Oral Presentation click the link on the right. To read the full paper click here
Presented on Tuesday 16 May: Session 4 The world’s need for sustainable energy requires the upstream industry to utilise and deliver renewables and carbon capture and storage (CCS) at scale. To do that we must focus on where the synergies with low-carbon technologies are greatest. We define these as the energy ‘super basins’ of the future – where large hydrocarbon resources are co-located with plentiful clean electricity and CCS potential. These basins provide a viable pathway for industry to become sustainable. Basins without these attributes are disadvantaged, and face being left behind. This paper will focus on where Australian basins sit on this scale – which are the most advantaged through to disadvantaged? Which have the most viable renewables and CCS/CCUS (carbon capture, utilisation and storage) potential? Advantage also depends on cost – renewable energy must be abundant and affordable. In Australia today, upstream resources are plentiful but advantaged resources are not. But that perspective is not fixed, and there is much industry can do to strengthen its outlook. The average upstream emissions intensity of Australian projects is significantly above the global average – due to remote locations, high energy intensity and contaminants. Using renewables and CCUS to cut emissions is a logical step. Government policy, new technologies and exploration can also make a difference. But what of smaller basins without scale? Can Australian operators create ‘boutique’ basins with niche advantages – such as copious wind or solar power – that enable them to extend their longevity? Making Australia’s upstream sector resilient and sustainable is a huge challenge and will require ambitious, innovative basin-level thinking. To access the Oral Presentation click the link on the right. To read the full paper click here
Visual Presentation L4 The Karratha Gas Plant (KGP) is one of the most advanced, integrated gas production systems in the world, producing liquefied natural gas (LNG), domestic gas, condensate and liquefied petroleum gas (LPG). The KGP has an export capacity of 16.9 Mtpa, with five LNG processing trains, two domestic gas trains, six condensate stabilisation units and three LPG fractionation units. Following more than 35 years of production from North West Shelf (NWS) fields, the KGP has entered an operating phase where it is more frequently operating in turndown operation. The energy intensity of an LNG production train is often the lowest at maximum production capacity. Should the LNG train become feed gas constrained for extended periods of time, energy intensity increases due to baseload energy required to run the process equipment and physical constraints on equipment turndown. A structured approach has been applied at the KGP to realise improvements in energy intensity in turndown operation through building a strategy, identifying focus areas, energy accounting and benchmarking, data presentation, review and improve cycles, and leadership. The strategy and focus areas are linked to specific actions across different operating timeframes. Review and improve cycles, and leadership help to cultivate an energy efficiency-focused culture and continuous identification of opportunities and barriers to the strategy. Central to all pillars of the strategy is energy accounting, benchmarking and data visualisation which provide value, performance and materiality insights. The benefits can often be realised with limited financial and resource investment, can provide high value return on both emissions performance and reduced fuel consumption. To access the Visual Presentation click the link on the right. To read the full paper click here
Presented on Wednesday 17 May: Session 23 The Taroom Trough in Queensland is the main synclinal depression and southern extent of the Bowen Basin. Both the Bowen Basin and the overlying Surat Basin have been the focus of Australia’s coal seam gas (CSG) liquefied natural gas (LNG) export industry since 2014, but with CSG production now in decline and with a greater focus on domestic gas, it is timely to review the potential of new plays in this region. Although exploration and development in the Taroom Trough over the past decade have focussed on shallow Permian and Jurassic CSG resources, the early hydrocarbon potential of the trough was realised through conventional discoveries. Regardless of the reservoir, all conventional hydrocarbons in the trough have been typed to the same prolific Permian coals. These source rocks produce enormous volumes of oil and gas, yet only a small percentage of those volumes have been trapped in known conventional structures. This implies that a significant volume of oil and gas could remain trapped in tight reservoirs, including Fractured Thermally Mature Coals. Elixir Energy Limited plans to commence a drilling program in 2023 in ATP2044 (Grandis Gas Project) to unlock the gas potential of the Taroom Trough. The project will investigate the potential of Permian coals and sandstones at >3700 m depth using new understandings developed from recent studies into the critical role of elastic rock properties and stress anisotropy on coal fracture growth. This paper describes the opportunity that Elixir has identified and details the legacy technical work in the area and new research and ideas which have since evolved. To access the Oral Presentation click the link on the right. To read the full paper click here
Presented on Thursday 18 May: Session 26 Capturing the ubiquitous distribution and properties of igneous rocks is necessary to succeed in hydrocarbon exploration, field development and underground gas storage when dealing with magma-rich rift margins. In recent years, numerous researches have revealed detailed morphologies of intrusive and extrusive rock units embedded within sedimentary basins owing to advances in 3D seismic data. Outcrop studies have also provided deeper understandings of their occurrence and geometries. However, there has been comparatively little focus on the rock physics of igneous bodies and their relationships to seismic expression. To bridge this gap between the outcrop and the seismic information, we undertook a well-log-based petrophysical study of igneous rocks using subsurface dataset from the Browse Basin located in the Australian North West Shelf. In this contribution, we describe a classification of volcanic facies (e.g. lava flows, volcaniclastics, intrusive sills) based on well log motifs and textures apparent in borehole image data. Statistics of the petrophysical properties of each volcanic facies are also analysed in order to examine their correlation to seismic patterns. Our study implies the importance of detailed characterisation of igneous petrophysical properties of igneous rock units where concentrated within a sedimentary basin, which will help reconcile interpretations of seismic data. To access the Oral Presentation click the link on the right. To read the full paper click here
Presented on Wednesday 17 May: Session 19 Offshore oil and gas infrastructure must be decommissioned at the end of its operational life. The base case approach for decommissioning under Australia’s regulatory framework is the complete removal of all infrastructure. However, alternative decommissioning approaches, such as leaving some infrastructure in situ, may deliver better environmental, economic, and health and safety outcomes. Derogation from complete removal requirements is possible if alternative approaches have acceptable environment impacts and deliver equal or better environmental outcomes. Potential environmental contaminants are present in all offshore infrastructure and if decommissioned in situ could pose unacceptable risks to marine ecosystems. Contaminants may accumulate in infrastructure as a result of oil and gas production, such as scales of mercury and naturally occurring radioactive materials, or arise from the degradation of infrastructure itself, such as plastics and steel corrosion products. The unique behaviour and interactions of contaminants with local ecosystems makes assessing their potential impacts challenging. This presentation reports on the contaminants likely to be present in offshore oil and gas infrastructure proposed to be decommissioned in situ. The expected behaviour of these contaminants in the marine environment is discussed to give context to measures of their potential hazards (i.e. guideline values). This paper is intended to start a conversation and serve as a useful guide for titleholders and regulators about some data needs to assess potential contaminant impacts from in-situ decommissioning. To access the Oral Presentation click the link on the right. To read the full paper click here
Presented on Tuesday 16 May: Session 10 Greenhouse gas (GHG) emissions occur throughout the value chain of petroleum developments, including scope 3 emissions, which occur because of activities related to a development but not controlled or owned by that facility’s business. Scope 3 emissions are created predominately by using hydrocarbon products produced by Australia’s petroleum industry. The Australian petroleum industry is subject to a structured and robust regulatory framework to manage environmental impacts. Recently, scope 3 emissions from Australia’s petroleum sector are facing greater regulatory scrutiny. There are a number of drivers for scope 3 emissions regulation, including: Environment Protection and Biodiversity Conservation Act 1999 (Cth) section 527E indirect consequences of an action. Western Australian Draft revised Environmental Factor Guideline – Greenhouse Gas Emissions. These mechanisms provide Australian regulators the ability to enforce project proponents to manage their scope 3 emissions. Some measures that project proponents use to meet these requirements are: Assist the upstream supply network (e.g. regasification and distribution) to implement fugitive methane emissions reduction measures such as the Methane Guiding Principles; Undertake an annual review of indirect emissions; and Collaboratively work with customers to reduce emissions. This creates a project-centric approach to scope 3 emissions management. This paper explores regulation of scope 3 emissions, the impacts this regulatory approach has on project proponents and customers, whilst also considering alternative mechanisms to manage these emissions and meet regulatory requirements and climate goals. To access the Oral Presentation click the link on the right. To read the full paper click here
Presented on Wednesday 17 May: Session 21 Mental health is a hot topic right now. As is well-being, psychological safety, diversity and inclusivity, respect@work, and psychosocial risk. Recent changes in Work Health and Safety (WHS) Laws have created a buzz around these words. They have caused organisations to scramble to understand their legal obligations and implement strategies to satisfy their obligations. Often these terms are interchanged, implying they mean the same thing. Often, there is a tussle between two or more parts of the business – where does psychosocial safety sit? Human Resources, Health, Safety or Operations? The confusion and ambiguity in definition, approach and responsibility can lead to reactive strategies which whilst they intend to ‘fix’ the problem, inadvertently lead to an increased likelihood of psychosocial risk. Having clear definitions, accountabilities and a simple strategy are key to success. Culture gets created in conversation. If the conversation is murky, the culture is murky. This paper provides a simple framework to help organisations navigate the perceived complexity in this space and create their own blueprint. To access the Oral Presentation click the link on the right. To read the full paper click here
Presented on Wednesday 17 May: Session 18 This paper presents the results of a techno-economics analysis to quantify the potential for storing CO2 and producing lower carbon intensity oil from mature, onshore Australian oil fields located in the Cooper/Eromanga and Surat/Bowen Basins. The work explores the impact of incentivisation, identifies possible sources of CO2 to support CO2-EOR (enhanced oil recovery) deployment, and discusses global CO2-EOR policy. The hypothetical ‘carbon incentive’ assessed in this study resulted in unlocking an additional 40 million metric tons (Mt) of CO2 storage and 73 million barrels (MMBO) of domestic oil production compared to the base case scenario that most closely represent Australia’s current policy and economic settings. Further, the results of this study indicated that, with incentivisation, net-negative carbon dioxide emissions could be achieved by deploying CO2-EOR practices in certain mature oil fields. The study found that there are currently sufficient industrial sources of CO2, particularly from black coal-fired power generation and hard-to-abate industries such as cement and steel production, to support this deployment. An opportunity to explore the co-development of ‘stacked storage’ using both CO2-EOR and concurrent geologic storage of CO2 in adjacent, unconnected reservoirs is proposed. This may significantly reduce development costs compared to stand-alone geologic storage projects, providing more favourable techno-economics, and accelerating the physical connection of CO2 sources and sinks. To access the Oral Presentation click the link on the right. To read the full paper click here
Presented on Thursday 18 May: Session 29 The Moomba Gas Plant in northeast South Australia processes natural gas produced from the Cooper Basin. CO2 in the natural gas is separated and has historically been vented to atmosphere. The Moomba Carbon Capture and Storage (CCS) Project aims to reduce these greenhouse gas emissions from the Moomba Gas Plant by 1.7 Mtpa CO2-e starting from 2024. The CO2 will be captured, processed and transported by pipeline to the depleted Strzelecki and Marabooka Gas Fields where it will be permanently stored. Designing a CCS system is similar to traditional hydrocarbon systems but there are important differences due to the nature of CO2. This paper discusses some of the key considerations in the design and integration of the capture, processing, transport and storage systems for the Moomba CCS Project. The composition of the CO2 stream, including minor impurities and water content, is a major factor that affects all systems. The phase behaviour of CO2 and the associated low temperatures are also important, particularly when injecting into low-pressure storage reservoirs. To access the Oral Presentation click the link on the right. To read the full paper click here
Presented on Wednesday 17 May: Session 25 Electricity and gas prices in the Australian east coast markets reached unprecedented levels from April to July 2022. The following report will investigate the root cause of the market prices with consideration of (a) reference to the international energy market scarcity, (b) government intervention, (c) assessment of availability and behaviour of coal generators and (d) role of gas generators in the east coast of Australia. To access the Oral Presentation click the link on the right. To read the full paper click here
Presented on Thursday 18 May: Session 26 The Turrum Field in the offshore Gippsland Basin has been a significant gas contributor since first development in 2004 and remains a keystone gas resource in the basin. Much work continues to be done to both optimally deplete the current accessible reserves, and to evaluate reserves capture opportunities through additional drilling. A multidisciplinary team of geoscientists and reservoir, production and wells engineers was formed to re-evaluate how to maximise production from the Turrum Field. New seismic data, wireline surveillance, production and surface monitoring parameters were integrated with existing geological models. An enhanced understanding of the Turrum reservoir has emerged with a more informed view of future well work requirements for optimal depletion of the field. The integration of this new information along with enhanced seismic over the greater Turrum area has not only helped to optimise production from the existing wells, it is also supporting efforts to evaluate the potential to fund additional opportunities to optimise production from Turrum, increasing current and future gas supply to the domestic market. The key to success for this work was the integration of many disparate subsurface datasets and the willingness to test biases and challenge previous field development recommendations based on new data and ideas. To access the Oral Presentation click the link on the right. To read the full paper click here
Visual Presentation B1 The offshore oil and gas industry is facing a significant transition period in the coming decades due to the evolving energy market and aging oil and gas infrastructure. Industry has over 1000 offshore wells to plug and abandon, 57 fixed facilities and over 8000 km of subsea lines to decommission over the coming decades. Most of this significant portfolio is regulated by NOPSEMA (National Offshore Petroleum Safety and Environmental Management Authority) with the expectation that decommissioning involves the full removal of equipment as per Section 572 of the Offshore Petroleum and Greenhouse Gas Storage Act 2006 (Cth) (OPGGS Act). However, other options may be considered if the titleholder can demonstrate that an alternative decommissioning approach delivers equal or better environmental and safety outcomes compared to complete removal. Integration of environment and engineering functions primarily occurs during the process of developing an Environment Plan (EP) and, specifically, the process of identifying environmental hazards (Environmental Hazards Identification, ENVID) and mitigation measures. This paper proposes that improved stakeholder, regulatory, cost and environmental outcomes could be achieved through an earlier integrated approach to planning decommissioning activities. Specifically, co-designing an approach to decommissioning at the earliest stages would inform, for example, approvals strategy and equipment selection. This would ultimately result in improved outcomes without the application of mitigating control measures. The paper will discuss some of the current challenges and outline the value of early identification and understanding of key environmental values and sensitivities to ensure site-specific information is considered during planning stages, later streamlining EP development. A multi-disciplinary decommissioning team in the early stages of project development enhances problem-solving capabilities and ultimately improves environmental and safety outcomes. To access the Visual Presentation click the link on the right. To read the full paper click here
Presented on Tuesday 16 May: Session 7 Top of line corrosion (TOLC) is typically a concern in the first few kilometres of wet gas pipelines where water in the warm gas condenses on the cold pipe walls. With the introduction of a subsea tieback to existing infrastructure, the changing fluid composition and temperature profiles may increase condensation in sections not previously expected to have condensation. Accurate prediction of the water condensation rate (WCR) becomes essential to support reliable corrosion modelling. Transient flow simulation of pipeline operating conditions and detailed heat transfer modelling is required to calculate the WCR. This calculation is complicated because the mass of water condensation is very small compared to the fluid mass in the pipeline, and sensitive to glycol that is often present in the aqueous phase for hydrate management purposes. This paper introduces a method to calculate WCR by using detailed transient modelling of the pipeline operating conditions. The fluid thermal hydraulic behaviour and hydraulic pressure drop in the pipeline are considered in the model. The fluid composition in the pipeline and glycol component in the aqueous phase are calculated by using a PVT software package. A few sensitivity studies will also be presented. The implications of Equation of State (EoS) and transient flow module on WCR calculation will be quantified. The WCR sensitivity results will be analysed based on varying inlet temperatures, glycol concentrations, and pipeline heat transfer coefficients. A WCR calculation method will be recommended for TOLC modelling. To access the Oral Presentation click the link on the right. To read the full paper click here
Presented on Wednesday 17 May: Session 22 This paper demonstrates the workflow of an integrated petrophysical, geomechanical sanding assessment and cement bond log evaluation to define a simple cut-off for reliable sand production assessments and well completion decisions. This workflow provides valuable insights for timely and fit-for-purpose sand management strategies particularly at early field life where the commonly used sanding prediction methodologies cannot be calibrated with field data because of the lack of sanding observations. The successful application of this methodology is shown in the Ichthys gas field, Browse Basin, with high rate and long high-angle producers with subsea wellheads and a long pipeline to an onshore plant. Advanced geomechanical analysis combing analytical and numerical sanding methodologies are used to define a single property cut-off for well-life sand-free production. The availability of such a simple cut-off has assisted the well construction engineers to follow a quick, cost-effective, simplified but thorough approach for sand production assessment and completion selection as opposed to being empirical, or too time consuming. The field first came on stream in July 2018. The workflow has been used in development wells and its validity and sand control decisions are confirmed, as to date all wells are producing sand-free. A similar workflow is being developed for the secondary target at some 400–500 m deeper for the subsequent phases of field development. To access the Oral Presentation click the link on the right. To read the full paper click here
Visual Presentation E3 The Orphan Well project evolved from the recommendations in the Final Report of the NT Hydraulic Fracturing Inquiry (HFI). The purpose is to assess wells that were drilled under petroleum permits or licences, and which have subsequently been surrendered by the titleholder and are now the responsibility of the NT Government. The project’s objective is to confirm the current status of these wells and to put forward recommendations for remedial works and/or monitoring for wells assessed to have an integrity risk. The assessment primarily focusses on the risk of fugitive methane gas. Two petroleum engineers were employed to undertake the project of assessing 113 orphan wells scattered over 1.4 million km2 of the NT. As it is a requirement to rehabilitate the land after petroleum activities have ceased, access to orphan wells is often not maintained; therefore, logistical consideration is undertaken. The project involved an initial desktop study of well history (construction) followed by a field site inspection. The drilling of these wells can date as far back as the 1960s. These older wells can have less detail in the well records and their survey location, and being pre-GPS, can have location errors of several kilometres. Remote helicopter travel is used to undertake fieldwork and locate these wells. The site inspections commenced in February 2022 and as at 31 December 2022 there have been on ground field inspections at 96 wellsites. This paper provides insight as to how the Orphan Well team developed its processes in both desktop study and site investigations. To access the Visual Presentation click the link on the right. To read the full paper click here
Visual Presentation G3 Mafic volcanic rocks, typically basalts of mainly late Cretaceous age, have been intersected by Gippsland Basin wells. Intersections of volcanic rocks primarily occur along the basin-bounding Rosedale Fault System in the northern part of the basin, where they exhibit a close spatial correspondence with high-CO2 content gas accumulations. Though petrographic data indicates that the basalts have been variably altered to clays and carbonates, they provide the top seals to numerous hydrocarbon accumulations, most notably at the Kipper Field. Despite the widespread distribution of these volcanics and their relevance to petroleum systems, they have received only sporadic attention over the past few decades. Here we combine petrophysical, geomechanical, geophysical and geochemical datasets to elucidate the origin of the volcanic record of the Gippsland Basin, and to evaluate their potential role in the decarbonisation of the basin, for example through providing opportunities for intra and sub-basaltic storage of CO2. To access the Visual Presentation click the link on the right. To read the full paper click here
Presented on Wednesday 17 May: Session 25 War in Europe has transformed the global geopolitical landscape and Russia has weaponised its commodities. Europe’s energy market is now out of control. Europe will never rely on Russia for anything again. But, can Europe live with no gas supply from Russia at all? This has had far-reaching consequences for the global liquefied natural gas (LNG) industry. Volatility and sky-high prices are now an enormous risk to gas demand. Long hailed the ‘transition fuel’. Record gas prices pose a dilemma for governments who must balance climate change goals with mounting energy security concerns. Affordability is particularly pressing in the booming Asian markets that are underpinning much of the next wave of supply. It is in these markets that gas should play a critical role to facilitate the power sector transition from coal to renewables. In addition, about half of gas demand is in non-power sectors, contributing as industrial feedstock and heating fuel. In many of these sectors, gas simply cannot be replaced by renewables, and despite all eyes on Europe for now, the longer-term LNG story will remain centred around Asia. In this paper, Wood Mackenzie will argue that Asian gas demand can rebound and will remain robust as new supply emerges, reinforcing the longevity of LNG investments. But the race is on. Australian LNG must reduce its emissions and ensure contractual attractiveness to remain competitive against a wave of new low-cost, low-emission projects that are rapidly moving forwards around the world. To access the Oral Presentation click the link on the right. To read the full paper click here
Presented on Tuesday 16 May: Session 1 The Proterozoic succession in the National Drilling Initiative Carrara 1 drill hole, Northern Territory, is dominated by tight shales, siltstones and calcareous clastic rocks. As part of Geoscience Australia’s Exploring for the Future program, this study aimed to improve the Proterozoic shale gas reservoir characterisation by derivation of porosity, permeability and gas content from laboratory testing and machine learning approaches to wireline log interpretation. The Proterozoic Lawn Hill Formation is divided into four chemostratigraphic packages. The middle two packages are further divided into seven internal units according to principal component analysis and self-organising map clustering on well logs and inorganic geochemical properties. Artificial neural networks were then applied to interpret the mineral compositions, porosity and permeability from well logs, density and neutron-density crossplot interpretations. Gas content was estimated from the interpreted porosity, gas saturation, total organic carbon and clay contents. Petrophysical interpretation results are summarised for all chemostratigraphic packages and units. P2 (1126.3–1430.1 m) has the highest potential among the four chemostratigraphic packages. P2U1 (1126.3–1271 m) and P2U3 (1335.5–1430.1 m) units have the most favourable petrophysical properties for organic-rich shales, with average total gas contents of 1.213 and 1.315 cm3/g, geometric mean permeability of 6.6 and 25.31 µD and net shale thickness of 53.5 and 83.3 m, respectively. P3U4 (687.9–697.9 m) has high gas content and permeability, with a net shale thickness of 35.9 m. The tight non-organic-rich siltstone and shale reservoirs in package P1 (below 1430.1 m) have an average gas saturation of 17.4% and a geometric mean permeability of 0.48 µD. To access the Oral Presentation click the link on the right. To read the full paper click here
