Unconventional Reservoirs: Australian Exploration Experts Weigh In on Rosy Reserves Estimates
A new dose of constraint may just be the best prescription for those making reserves estimates on prospective unconventional resources.
The early days of a new shale play can be exciting, but they can also come with inflated expectations. This is a familiar theme in the unconventional sector which has delivered a myriad of discoveries over the past decade that have failed to achieve commerciality.
It’s especially familiar for those involved in Australia’s unconventional projects where big hopes have been pinned on the tight-gas potential of places called the Beetaloo, Canning, and Cooper Basin. Instead, the only long-term success to be found on the Australian unconventional landscape is a mature coal-seam gas sector which, not to be discounted, helped the country claim the status of the world’s top exporter of liquefied natural gas in 2020.
For Duncan Lockhart, one of the chief reasons that Australia’s tight-gas ambitions have yet to materialize likewise lies in the fact that tight-rock plays extend for vast areas compared with even the largest conventional systems. As a result, the general manager of exploration with Brisbane-based Central Petroleum said some of the estimates on unconventional prospective resources are “verging on fantasy.”
Lockhart issued his critique as a co-chair of a resource valuation panel hosted by the Asia Pacific Unconventional Resources Technology Conference in November 2021 The discussion between several exploration experts tried to identify the biggest missteps in Australia’s tight-gas adventure thus far. At the highest level, the industry depended on the promising results of too few appraisal wells to formulate reserves estimates on areas covering hundreds and sometimes thousands of square kilometers.
Lockhart emphasized in trying to evaluate such “massive areas,” operators and appraisers have been pushed into a corner.
“We need to make a whole bunch of major assumptions about a whole bunch of inputs,” he said, adding that left out of the initial estimates all too often is “the amount of heterogeneity that we will be experiencing in these rocks over these large areas.”
Lockhart was not alone in his concerns.
With hindsight, it has become easier to see that the highest-performing wells tend to be drilled in isolated sweet spots and along narrow fairways—not across the entirety of a play’s geographic boundaries as shown on the map. The risk facing every operator in this situation is that it will burn through its capital on the wrong slivers of shale and, in turn, see its investors run for the exit.
Martin Wilkes, the managing director of international energy consulting firm RISC Advisory headquartered in Perth, took aim at what he characterized as the “sales message” approach that tends to ignore such facts of life during the early promotion of tight-gas plays.
“[Operators] talk up total organic compound content and use it to develop these large numbers, which then get transferred into a continued resource using standard recovery factors,” he said.
Wilkes also highlighted the remote nature of unconventional projects in Australia and said many of them were proposed without a full understanding of transportation challenges or the number of wells required to achieve profitable scale. There’s also a tendency to use US shale-gas projects as analogues, which is a red flag for Wilkes in part because so much of Australia’s tight-gas exploration is taking place in areas where there are no conventional hydrocarbons.
What the initial promoters are not saying is that “in all the successful plays in America, unconventional hydrocarbons have followed the production of conventional hydrocarbons,” he said.
In defense of those who have missed the mark using off-the-shelf statistical approaches, it needs to be said that all unconventional plays are unique and come with learning curves of varying severity.
“And therefore, it makes it almost impossible to come up with a set of rules and boxes that you can neatly fit everything into,” said John Hattner, senior vice president of the Houston-based reserves consultancy Netherland, Sewell & Associates. “They’re not spreadsheet exercises—you’ve got to do your science and engineering up front.”
A Different Role Model
Another problem raised by the panelists involves the overreliance on the North American experience as a template for what may come half a world away in the Northern Territory or in Queensland.
Wilkes singled out the routine comparisons of the undeveloped Beetaloo Basin in the Northern Territory to the highly developed Marcellus Shale in Pennsylvania. “Whilst there may be some geological comparisons, I think there’s a lot more things that are different here,” he said.
Lockhart also spoke about how preliminary estimates of Australian unconventional resources are most often based on models tuned for North American shale plays. He asked, “Is it inappropriate to continue using these models” given that the stress regimes of the two continents are “vastly different?”
Unfortunately, Lockhart said he wasn’t able to provide an answer on what the best alternative might be. But whatever it is, it won’t be easy to come by.
To help launch the US shale revolution, operators were aided by the 20,000 wells that were ultimately drilled in the first major gas play, the Barnett Shale.
“You don’t have a lot of geological risk at that stage,” quipped Hattner. With Australia lacking any comparable legacy data sets, he added that “making large assumptions over hundreds of square kilometers seems a bit risky.”
Some of this indicates that what Australia may need is plenty of time. • It’s for that reason that instead of drawing comparisons to the Marcellus Shale in the US, Wilkes believes a closer, yet still imperfect, comparison to the Beetaloo may be the Vaca Muerta Shale in Argentina which has become a major center of activity over the past decade.
The Beetaloo earned a place on the global shale radar in 2016 with the drilling of a successful multistage horizontal well by Origin Energy. With an average initial production rate of more than 1 MMscf/D, the well in the Northern Territory led to a preliminary estimate that the target, the dry-gas Velkerri formation, holds some 6.6 Tcf of gross contingent gas resources across an area spanning nearly 2000 km2.
Then a nearly 2-year moratorium on hydraulic fracturing put any chance of development on hold until it was lifted by the territorial government in 2018. As a sign of how immature the Beetaloo remains, the first appraisal well was not put back on production for further testing until August 2020. • “The results were positive for the operator, but as Wilkes underscored, the next 4 or 5 years are likely to see just about a dozen wells drilled in the basin, compared with over 1,000 drilled in the first 7 years of the Vaca Muerta development.
“And they’re all appraisal wells—none of them are targeting actual development and production of hydrocarbons” he said, adding that this is where comparisons with the Vaca Muerta look optimistic as it may mean the Beetaloo is a decade way from commercial production.
More Clarifications Coming
There are established methods to account for the uncertainty that looms large over unconventional resource estimates. However, the general consensus amongst the panelists is that more is needed. Less clear is just how much more.
“While there has been some improvement in recent times, a bias toward optimism in unconventional projects appears to persist. This has, and still can, result in poor project decision making,” said Barbara Pribyl.
Pribyl is an independent consultant in Brisbane who was previously the reserves and resources manager at Australian independent Santos. She was addressing the SPE Petroleum Resources Management System (PRMS) that was updated in 2018 in large part to reflect the challenges of evaluating unconventional projects.
Pribyl was a member of the SPE Oil and Gas Reserves Committee that helped draft the updates and said more guidance and clarifications are to be released in the near future “to help companies and evaluators navigate some of these changes.”
Used globally and as the regulatory standard in Australia, the PRMS is a tool to define, classify, and estimate the volume of hydrocarbon resources.
Some of the 2018 updates Pribyl keyed in on included a greater emphasis on spatial sampling density and a limitation on how far outside of the discovery area operators should extrapolate their initial results. Both of these new constraints are aimed at helping address the heterogeneity problem.
She also expects to see further changes to the PRMS related to the criteria around environmental, social, and governance (ESG) issues. The need to curb emissions dominates the narrative around the investor-led ESG movement when it comes to oil and gas companies. But along with that, Pribyl said greater transparency on reserve calculations is also part of the deal and failing to meet this new standard means “companies face reputational, financial, and litigation risk.”
Contingent Resources: More Reliable or More Risky?
Simon Smith, a chief petroleum engineer with Origin Energy, noted as one of the panel’s co-chairs that as the PRMS evolves into a “more granular” evaluation tool, operators are being presented with new questions.
One of them is whether they have properly characterized contingent resources, which are those quantities of oil and gas that are potentially recoverable but fall short of meeting the requirements to be considered commercial.
In the updated PRMS, operators can classify contingent resources as “Development on Hold” or label them as the notably less certain “Development Unclarified.” These are, however, discretionary classifications.
Raymond Johnson, a professor of well engineering at the University of Queensland, called particular attention to the technology requirements for holding noncommercial assets as contingent resources. He noted that Australian unconventional targets are challenged by a strike-slip to reverse stress regime which makes creating transverse fractures (i.e., the ideal for multistage completions) an “impossibility” with commercially available technology.
With that he raised the idea that perhaps while well-intentioned, contingent resources may have “devolved from the problematic child” of 3P reserves, which quantify a best-case scenario comprising proved-plus-probable-plus‑possible reserves.
“Now we’re just touting these contingent resources that may or may not be realistically recoverable by a project,” added Johnson.
Nevertheless, the updated PRMS has tried to tackle the quandary.
Pribyl pointed out the reserves estimation guidelines now require “a defined development project that can be reasonably expected to be implemented on a reasonable forecast of commercial conditions.”
Also required is currently available recovery technology that was designed for the project at hand. For technology still under development, Pribyl said ample justification is needed to show it has a chance of succeeding.
“If it doesn’t meet these standards, then in fact, you are not contingent resources even if you have past discovery. You are in fact discovered unrecoverable,” she added.