East Coast Gas Research Articles

Rethinking the theory of quiet politics: bad corporate behavior and the failure of quiet politics in the east coast gas crisis in Australia, 2022

Abstract The theory of quiet politics has two propositions; first, that business interests prefer to engage with governments in ‘quiet’ arenas shielded from the media and the day-to-day political fray, and second that business interests exert power over governments in quiet politics. We counter the second proposition, arguing that business generally exercises influence rather than power in quiet politics. One precondition for the successful exercise of influence is the acceptance by business of certain protocols of behavior in interactions with governments. In this paper we underline the importance of such protocols by exploring the dynamics of a conflict between the east coast gas industry and the federal government in Australia amidst steep rises in domestic gas prices and supply restrictions in 2022. The gas industry behaved badly in the economy and in politics and did not abide by the relevant protocols of engagement with the government. The government responded aggressively and quiet politics failed. The paper underlines the importance of the behavioral pre-conditions for business influence in quiet politics and what can go wrong if this fails.

An uneasy truce: a post-intervention gas market in Eastern Australia

We present our analysis of the East Coast fundamentals and our long-term gas price assumptions through 2033 in Wallumbilla and the southern states. The paper concludes that the market has a chance to return from the brink of dysfunction. The replacement of lower-cost legacy supply near demand centres with higher-cost coal seam gas (CSG) from a remote region in another state through limited infrastructure – or liquefied natural gas (LNG) imports – fundamentally signals higher prices even as domestic demand declines from 520 PJ in 2023 to 425 PJ in 2033 with possible intermittent increases during coal retirements. Added to the mix is long-term demand and policy uncertainty, the current era of monetary tightening and vanishing finance for fossil fuel projects. The relationship between East Coast gas producers in Australia and the federal government appears to have de-escalated following the inclusion of potential price cap exemptions in the recently released mandatory code of conduct for the domestic wholesale gas market. Gas remains a crucial long-term input in the manufacturing sector and will continue to support gas intensive industries if price alignment can be achieved, which is what will be needed to ensure the gas sector’s longevity in the energy transition. We also discuss the role of gas in the National Electricity Market which is headed for an increasingly chaotic coal exit, keeping gas extremely relevant to support system resilience.

Beetaloo’s gas bounty: potential for LNG exports and domestic supply

Recent drilling in the Beetaloo Basin has yielded promising results for the emerging shale gas play, enabling the explorers to secure funding and establish a range of non-binding commercial agreements. Notably, Beetaloo wells have exhibited initial production rates over 30 days (IP30), spanning from 1.1 to 5.2 mmcf/day, and there is an evident trend of increasing frac stages with each new well as operators continuously optimise stimulation. This research paper presents comprehensive Beetaloo modelling results, encompassing well type curves, a comparative analysis with the renowned Marcellus shale play in the United States (frequently used as a reference point for Beetaloo), production forecasts, economic assessments, and an examination of potential commercialisation pathways. Based on our modelling findings, Beetaloo’s estimated ultimate recovery (EUR) per well ranges from 7 to 14 bcf, with deeper wells into the Velkerri B Shale demonstrating relatively higher productivity. We anticipate that, with full-scale development, Beetaloo could attain peak production rates of 1 bcf/day, supported by a peak annual drilling rate averaging 50–60 wells. Overall, the Beetaloo Basin possesses the potential to recover close to 8 tcf of low reservoir CO2 gas, opening doors to the possibility of liquefied natural gas (LNG) exports reaching up to 4.5 mtpa and domestic gas supplies of around 94 mmcf/day, limited to the existing infrastructure capacity connecting to the east coast gas markets.

The Walloon Coal Measures resource density: how low can we go?

Coal seam gas (CSG) production began from the Walloon Coal Measures of the Surat Basin in 2005. Initial field developments were located within a high production fairway where resource densities are >3.5 PJ/km2. The majority of the Surat Basin CSG is produced by four major consortia with tens of billions of dollars invested in infrastructure. As a result, the industry directly contributes to >30 000 jobs within Queensland and is forecast to contribute >A$5.5 billion in royalties over the next 5 years. Gas offtake is dominated by the export LNG market with a consistent daily throughput of 3–4 PJ. Gross Queensland gas production exceeded 1500 PJ in 2020 with ~80% coming from the Walloon Coal Measures. Historical breakeven wellhead gas prices in high resource density areas in the Surat Basin have been reported as <$5/GJ for undeveloped 2P Reserves with access to infrastructure. Moderate resource density CSG potential in the Surat Basin which is commonly in the shallower margins was historically considered marginal or sub-commercial if the requirement for in-situ standalone infrastructure capital expenditure is factored into economical modelling. Therefore, the potential of these developments will require stakeholder cooperation via existing infrastructure. Accounting for natural decline in current fields, available capacity at existing facilities and pipelines, and the forecast impending east coast gas supply imbalance, the landscape and economics of Queensland CSG production is predicted to transform. The paper explores the lower limit of gas rates and recoveries, on a single well basis, in shallow, moderate resource density underdeveloped areas of the Walloon Coal Measures.

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

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 14. Presentation for: West Barracouta – 50 years in the making

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

West Barracouta – 50 years in the making

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.

The story of Esso Australia’s push to explore the frontier Gippsland Basin with the ultra-deep water Sculpin-1 exploration well

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.

Intellectual Capital for Exploration is Running on Fumes

The Federal Government’s acknowledgement of ever encroaching east coast gas shortages, compounded with a looming supply squeeze confronting future LNG export delivery and the scarcity of skilled explorationists to reverse the decline, has produced a near-perfect storm for the Australian hydrocarbon industry.

Geological and Bioregional Assessments: assessing the prospectivity for tight, shale and deep-coal resources in the Cooper Basin, Beetaloo Subbasin and Isa Superbasin

The Geological and Bioregional Assessment Program is a series of independent scientific studies undertaken by Geoscience Australia and the CSIRO, supported by the Bureau of Meteorology, and managed by the Department of Agriculture, Water and the Environment. The program consists of three stages across three regions with potential to deliver gas to the East Coast Gas Market. Stage 1 was a rapid regional prioritisation conducted by Geoscience Australia, to identify those sedimentary basins with the greatest potential to deliver shale and/or tight gas to the East Coast Gas Market within the next 5–10 years. This prioritisation process assessed 27 onshore eastern and northern Australian basins with shale and/or tight gas potential. Further screening reduced this to a shortlist of nine basins where exploration was underway. The shortlisted basins were ranked on a number of criteria. The Cooper Basin, the Beetaloo Subbasin and the Isa Superbasin were selected for more detailed assessment. Stage 2 of the program involved establishing a baseline understanding of the identified regions. Geoscience Australia produced regional geological evaluations and conceptualisations that informed the assessment of shale and/or tight gas prospectivity, ground- and surface-water impacts and hydraulic fracturing models. Geoscience Australia’s relative prospectivity assessments provide an indication of where viable petroleum plays are most likely to be present. These data indicate areal and stratigraphic constraints that support the program’s further work in Stage 3, on understanding likely development scenarios, impact assessments and causal pathways.

Geological and Bioregional Assessments: a program to encourage industry development and improve regulatory efficiency while maintaining the highest possible environmental standards

The Australian Government’s $35.4 million Geological and Bioregional Assessment (GBA) Program provides independent scientific information and baseline data to governments, the community and regional industries on the potential impacts of shale, tight and deep coal gas development on water and the environment. The program aims to encourage industry development and growth by improving the understanding of upstream operations and their potential impacts to drive regulatory efficiency while maintaining the highest environmental standards. The GBA program comprises a series of independent scientific studies undertaken by CSIRO and Geoscience Australia, supported by the Bureau of Meteorology and managed by the Department of Agriculture, Water and the Environment. The program was conducted in three stages and focuses on where industry is currently exploring, conducting assessments across three regions; the Cooper Basin, Beetaloo Sub-basin and the Isa Superbasin, each with potential to supply gas to the East Coast Gas Market. The GBA program brings together a range of disciplines to collect, aggregate and analyse environmental baseline data to conceptualise the geologic, hydrologic, ecologic and anthropogenic features of these regions. This robust ‘conceptual’ understanding of the regions combined with rigorous hazard identification enables the program to prioritise potential impacts on water and the environment, improving regulatory efficiency by focusing regulators towards managing those activities where the potential impacts can’t be avoided. Additional papers and presentations from our partners in the GBA program tell the story of how the Program was developed and delivered. The Program leaves a legacy of publicly available baseline data, information and assessment tools that will make regulation of the industry more efficient in the regions assessed.

Evaluating the sources and impact of new east coast gas supply

Rystad Energy has conducted a well level supply side study for the Australian east coast gas market, quantifying the widely expected supply shortfall and its timing. This paper presents these findings, along with an economic and technical evaluation of new sources of supply relief and their potential impacts on the market balance. The study suggests the east coast has adequate gas supply to meet demand until 2024, with an average excess of 73 billion cubic feet (Bcf) per annum over this period. However, in 2025 the market will shift to under-supply, starting at 93 Bcf in 2025 and increasing to over half a trillion cubic feet by 2030. Sufficient supply in the short term does not warrant complacency. With the average duration between discovery and first gas for the region being 7.1 years since 1990, even if new (traditional) supply is discovered in 2020, the market will still be undersupplied for at least 3 years. We have identified the four most likely sources of supply relief for the market, each with their own merits, difficulties and development timelines. These new sources include the Beetaloo Sub-basin shales of the Northern Territory, undeveloped coal seam gas acreage, electrifying liquefied natural gas (LNG) export facilities to preserve in-field usage, and finally, LNG importation. A combination of at least two of these sources is required to balance the east coast gas market to 2030. Of the options, LNG importation is the most viable to stave off undersupply in the medium term (3 to 7 years). While Beetaloo Sub-basin shale gas appears the most viable option for secure, long-term supply relief.

Making upstream infrastructure collaboration happen

Major upstream and midstream developments are required in Australia to sustainably address the east coast gas price challenge and enable a new wave of liquefied natural gas (LNG) projects in Western Australia (WA) and the Northern Territory. Until now, each project in the WA offshore and Queensland coal seam gas systems has had its own midstream infrastructure, which is suboptimal for costs. Major players, including Chevron and Woodside, have expressed interest in a more optimal, shared ownership model, similar to others around the world. In the US Gulf of Mexico, pipeline owners established master limited partnerships to take advantage of tax benefits and to share cost with institutional investors. In Norway, high infrastructure costs led to government-mandated shared ownership. The momentum for change in Australia is gathering and includes increasing investor pressure on capital discipline for upstream companies, strong competition for final investment decisions across global LNG projects, stakeholder expectations to minimise the environmental footprint of energy projects, a strong appetite of infrastructure and pension funds for energy infrastructure assets and pipeline companies looking to expand their portfolios to realise synergies in view of increasing regulatory scrutiny and margin restrictions. This paper describes international benchmarks, identifies blockers and proposes action steps that will enable this crucial industry development.

East coast gas – finding balance

There is not an abstract available for this presentation. To view the video, click the link on the right.

East coast gas: resource potential at different gas price scenarios (Part 2: commercialisation of unconventional gas resources)

Rising gas prices in the eastern Australian gas market, as well as forecast supply shortages in years to come, are driving speculation about LNG import requirements for the market. There are significant similarities with the gas market experience in the USA in the early 2000s which led to the construction of many LNG import terminals, the parallel rise of unconventional gas production and the subsequent mothballing of the LNG import facilities at huge economic cost. A comprehensive east coast gas market study has been carried out based on the 2P reserves positions for domestic gas producers. This data has been paired with a range of gas demand forecasts to identify the probable supply gap on the east coast over the next 10 years. A market response to the high gas pricing in the form of new developments is already underway. In a separate paper (Part 1) all potential domestic sources of unconventional gas to fill that gap were analysed to determine likely gas supply rates, development schedules and breakeven supply costs for each of the major demand centres. This paper (Part 2) illustrates the required gas prices to drive unconventional gas development in Australia, the subsequent scale of new unconventional gas supplies to the forecast gaps in the market and describes how those developments can reverse the trend of rising prices over time.

Meeting demand in a new era of east coast gas supply

Historically LNG projects have been established to monetise large gas finds in remote areas with little existing gas demand. The development of gas supply to the LNG project generally stimulated demand growth in the domestic gas market. As the supplying fields depleted, the LNG projects faced competition with domestic producers for declining gas supplies, but this was late in the project life when LNG plant capital had already been recovered. Recently, LNG export projects have been established within existing mature gas markets, most notably in Australia and North America. These plants now face competition with domestic gas consumers for access to feed gas from the beginning of their operational life when strong revenue has the greatest impact on the return earned on capital invested, with the greatest stress felt in Australia. This paper considers the underlying causes of domestic price rises experienced in Australia following the start-up of LNG export supplied from gas fields linked to the domestic market and the response by both plant developers/operators and the government. This historical view is used to inform forecasts of how the east coast gas market will react to the interplay between domestic and LNG plant demand, declining Bass Strait production, maturing CSG operations, LNG imports and completion of the Northern Gas Pipeline. In particular the ability of gas supply and pipeline capacity to meet the strongly seasonal domestic demand in Victoria and to a lesser extent NSW will be examined, together with the linkage to counter-cyclical seasonal demand for LNG from the Queensland LNG export plants in the key north Asian markets.

East coast gas: resource potential at different gas price scenarios (Part 1: quantification of unconventional gas resource potential)

A qualitative ranking of the remaining gas potential of Australian east coast basins was undertaken using a spatial analysis methodology of play fairway sweet-spot mapping. Play components considered important for the presence and recovery of unconventional gas were mapped across the plays of interest in Australian east coast basins. Modelled horizontal well type curves and development plans from North American analogues for unconventional gas production were used to quantify the sweet-spot mapping using a methodology we developed called common recovery segment mapping. A range of potential resource numbers were calculated for each play, leading to a quantification of the potential resource across the entire area of interest. Part 2 of this paper will show how these undeveloped unconventional gas resources may ultimately contribute to the east coast Australia energy mix.

Moomba reset – breathing new life into a 50 year old asset

Santos has big ambitions for the asset that started it all. We are setting up Moomba for the next 50 years. Moomba is more than just a gas plant, it is a township. Its primary industry is processing oil and gas, it operates off the grid by generating its own power, produces its own water, and provides accommodation to many businesses and hundreds of workers each night. The gas plant had received the most attention, in a structured program of maintenance and rejuvenation, generating high levels of safety and reliability that will extend the life of the facility for many years. However, Santos has now adopted an integrated town-plan approach towards Moomba to restore this nationally vital asset as a state of the art processing, storage and transportation hub, servicing east coast and southern gas markets. Whereas Santos has been successful in reducing its field-based resources footprint through technology and efficiency, Moomba’s physical footprint had not kept pace. Through consolidation of working places and delivery locations, reduction in physical footprints for warehousing, yards and accommodation, and a major renovation of the camp facilities, Santos is breathing new life into an aging asset. At the same time, Santos is keeping costs down through cooperative and sustainable arrangements with existing suppliers and contractors. It has also identified real value through the opportunity to provide Cooper Basin-wide services to maintenance, operations and projects from the Moomba Township.

State of the east coast gas industry

There is not an abstract available for this presentation. To view the video, click the link on the right.

Opening comments from facilitator - Staying the course – east coast gas market challenges and opportunities

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