Beetaloo or bust: the route to commercial success for an Australian shale play

Introduction

The Beetaloo Basin lies in the Northern Territory of Australia, commonly classified as a sub-basin of the Greater McArthur Basin. It spans an area approximately 28,000 km² (6.9 million acres) (Williams 2019). The basin is Proterozoic in age and has numerous unconventional targets (Williams 2020). Formation thickness attenuates towards the margins of the basin.

Conventional hydrocarbon exploration in the McArthur Basin started in the 1960s, and revived in the late 1980s and early 1990s, but no commercial discoveries were made. Following the US shale revolution, exploration focussed on unconventional resources, particularly in the Mesoproterozoic Roper Group. Approximately 18 wells have been drilled in the last 10 years as unconventional-focussed exploration and appraisal work increased.

Most of the basin is covered by exploration licences, with two Beetaloo-focussed operators, Tamboran and Empire Energy, along with established operating companies Santos and INPEX. Both local and international companies have come and gone from the basin, most recently Origin Energy exiting the basin in 2022, but also Hess and Sasol.

Interest in the region is predominantly focussed on the ‘B shale’ in the Amungee Member of the Velkerri Formation. Previously the Kyalla Formation was targeted as a potential liquids-rich shale play by Origin Energy, but it has not subsequently been pursued.

The Velkerri Formation is Mesoproterozoic in age, dating at approximately 1.4 billion years old (Gorter and Grey 2012) making it one of the oldest source rocks in the world. Comparisons have arisen between the Velkerri source rocks and the Mississippian Barnett and Devonian Marcellus shale plays. These analogue comparisons are based on similar mineralogical content, in particular a lack of carbonate in the Velkerri source rocks.

The play faces both subsurface and above ground challenges. Below ground, the tight reservoirs require long lateral wells that are fracture stimulated. Current flow rate information realised by operators from appraisal wells does not compare favourably with US analogues, particularly without liquids to improve economics, as appears to be the case for much of the Beetaloo.

Above ground, the isolated nature of the Beetaloo makes commercialisation options difficult, and current work programs very costly to execute. There is almost no oil and gas infrastructure besides a single pipeline network. Operators cannot make use of existing gas or liquids processing plants, new export pipelines are required and even basic infrastructure, like roads and towns, is scarce in the area. All people and materials need to be transported long distances to the Beetaloo Basin either from Darwin or the East Coast, (likely Queensland), where there is a currently operating unconventional gas industry, but with a coal seam focus.

From a commercial perspective, the local Northern Territory market does not require the large volumes of gas that would need to be produced to sustain an unconventional play the size of the Beetaloo. But it is gas-short and needs smaller volumes as soon as possible (Fitzgerald 2023).

The East Coast of Australia is an attractive market, with high gas prices and a looming gas shortage (AEMO 2023). However, additional infrastructure would be required to deliver more than approximately 100 mmcfd of gas to the East Coast market. The Northern Gas Pipeline is the limiting factor here. Liquefied natural gas (LNG) export from Darwin, where there are currently two LNG facilities, may be an attractive option. This is an option operators have explored, with memorandum of understanding (MOUs) signed with global LNG players Shell and bp (Fowler 2023). Again, more infrastructure and a greenfield or brownfield LNG plant development would be required.

The requirement for additional infrastructure and the isolated nature of the play means that success in the Beetaloo isn’t a foregone conclusion. Costs, subsurface potential and markets all play a make-or-break roll in the success of the Beetaloo as a shale play. This work examines a range of factors that contribute to the success, or lack thereof, of this nascent shale play in the heart of northern Australia.

Methods

This work tests multiple Beetaloo production scenarios with varying well costs, subsurface deliverability (production profiles) and production scale. We view these as the key variables and drivers of success. Production profiles and well costs are all based on horizontal development wells with 3000 m (~9800 ft) lateral lengths, and assuming a formation depth of approxinately 2000–2500 m.

Well costs are currently in the region of US$20 million per 1000 m horizontal lateral well for appraisal wells. This will need to reduce significantly, and we model a range of DCET (drill, complete, equip, tie-in) well costs from US$15 to US$25 million per 3000 m lateral well.

Production profiles are analogues taken from US shale plays selected for dry gas production. They span a range of shale gas plays: Marcellus, Barnett and Haynesville, and a range of EURs (estimated ultimate recovery) per well.

Production scale is based on plateau production across a range of scenarios up to 1 bcf/day. The models assume plateau rates are reached by year 6 and the plateau is sustained for 6 years before production decline begins and no more wells are drilled. First production is modelled in 2026 and total production is modelled over 25 years.

Other parameters are kept mostly consistent across all the models on a per mcf basis, including opex/mcf, and pipeline tariffs, as well as sustaining capex and workover costs. We allow for efficiencies of scale in gas processing facilities by assuming a small discount on larger production scenarios.

We do expect some efficiencies of scale to become available, which this approach considers. However, the expansive nature of an unconventional play means that these will be limited compared to a conventional oil and gas operation. For example, additional roads will be required to exploit additional play area. Gas plants for larger production volumes may be larger and cheaper per mcf but are unlikely to be fully centralised in a single location. Instead, multiple smaller hubs will service different areas of the play, with analogues of this seen in both Australian coal seam gas unconventional plays in Queensland, and in US shale plays.

For model valuation, an assumption has been made that most of the gas will flow to the East Coast market, although some will likely also supply the Northern Territory market as well. We assume customers will pay East Coast gas prices for Beetaloo gas, however we include costs to deliver the gas to Ballera. Further transport costs could add significantly to the cost of Beetaloo gas, particularly if the gas is destined for the southern states where local supplies in the Otway and Gippsland basins will decline later this decade.

Results

The modelling highlights the critical importance of reducing well costs, whether through operational efficiencies, sourcing cheaper local products (frac sand for example), or synergies with other operators in the basin. In general, the highest well cost scenarios are uneconomic and if development well DCET costs are in the region of US$25 million per well the Beetaloo play will struggle to succeed.

The speed of development, the role of phasing and the number of wells required are also key parameters. Scale is key, and in many of our scenarios a smaller-sized Beetaloo development struggles to make a commercial return, dependent on EURs and well costs.

Finally, the subsurface will need to yield better returns than our low case EUR scenario to make the Beetaloo economic. Application of modern shale completion techniques may be key, however, in a novel and yet ancient source rock new techniques may need to be trialled and developed to produce the best possible results.

Summary

The Beetaloo Basin is an ancient shale play in the heart of the remote Northern Territory. The play has huge potential to relieve supply shortages in the East Coast gas market, supply the Northern Territory and even produce gas for LNG export. However, our analysis shows that operators will need to be savvy to make Beetaloo production economically viable. Well performance and well costs must be optimised for the play, and Beetaloo players, to succeed.