A Petrobras executive speaking at the Offshore Technology Conference (OTC) proclaimed that Brazil’s deepwater plays are cost-competitive with the plays in the rest of the world.
The break-even price is “more competitive and doing very well compared to anyone in deep water or tight oil plays,” said Rudimar Lorenzatto, production and technology development director for Petrobras.
While the cost and engineering challenges that come with producing oil in ultra-deepwater fields are both high, he said the prolific production combined with cost-reducing innovations allow profitable production as low as $35/bbl.
That number does represent the break-even target price for the Libra development in Brazil, and falls around the middle of a range of Brazilian break-even production prices, that run from $20/bbl to $42/bbl, said Laura Rodriquez, managing consultant Americas, for Wood Mackenzie.
That is competitive with the Permian Basin, where break-even price vary widely. A recent chart on break-even production prices for the Permian by the Federal Reserve Bank of Dallas, based on a survey of 87 oil and gas companies, puts the average price needed to drill a new well in the Permian at $48/bbl.
Comparing fundamentally different plays using break-even estimates, which are calculated many ways, sometimes with iffy data, can be a slippery cost comparison. Averages do not reflect the wide range of break-even prices among specific operators and locations in Brazil and the US.
The fact that majors such as ExxonMobil and Chevron are investing huge sums offshore Brazil and the Permian suggest that both plays can pass the investment hurdles needed to become a large line item in the budgets of those majors.
Each has different plusses and minuses. The US onshore comes with less political risk and the ability to rapidly adjust production to changing economics. Brazil offers some of the largest offshore reservoirs and the promise of decades of growth. In the US, there are debates about when the Permian will peak during the next decade. The engineering challenges are different as well, though both are daunting in their own way.
Ultimately, the financial measure that matters is rate of return. There is no set formula for calculating break-even prices, and the results can vary depending on the data chosen. Nonetheless, since oil prices crashed in 2014, break-even has often been the way used to track the pace of cost cutting.
Brazil was stressing lower-cost barrels during its OTC presentations as it gears up for three upcoming offshore auctions this fall. One of those stands out from the rest: The Transfer of Rights offering, which involves four blocks with proven reserves totaling of 6-15 billion bbl of oil, according to the ANP, the Brazilian offshore regulator that manages rights sales.
This auction was described by Marcio Felix, executive secretary of the Ministry of Mines and Energy, as “an opportunity without precedent in the history of the offshore industry.” One block within that collection, Buzios, will need to live up to that promise, because it comes with a price tag that is likely without precedent—the minimum bonus alone is $17.3 billion. The profit-sharing payment exceeds 20%.
“One of the key components of enhancing commerciality of discoveries is by avoiding high fees,” said Julie Wilson, director of research at Wood Mackenzie. Competition for leases in the prolific pre-salt Brazil led to some really high bids, but the potential was so great it could justify those amounts, she said, adding, “avoiding high fiscal terms were not always possible.”
Value Creation or Destruction?
Break-even estimates for deepwater fields includes a big question: How will production and technology evolve in the decades to come?
Buzios carries a high break-even price of $42/bbl according to Wood Mackenzie, which expects total producible barrels from the Transfer of Rights block to be about 10 billion bbl.
“Geological favorability and prospectivity, which I am convinced are unsurpassed in the world, are maybe even too good to be grasped or believed,” said Cleveland M. Jones, researcher at INOG, the Brazilian acronym for the National Oil and Gas Institute.
Jones warns against excessive optimism by pointing to the country’s many long-term onshore risks. In recent years, the Brazilian oil business has struggled through a massive corruption scandal, regulations that stifled international investment, major management problems at Petrobras, and a deep recession.
Still, the reserves could justify the cost. Estimates assume that 25-35% of the oil will be ultimately recovered. “Given the long production history expected for those fields, and continuously evolving technology that is successfully reducing costs and increasing recovery factors, it is very likely that the actual recovery factors achieved will be significantly higher, maybe well into the 40% range,” he said.
Over time, Brazilian project managers have also found ways to lower the cost per barrel. Since 2015, Petrobras and four international partners found more than 100 ways to grind down the break-even price for the Libra project, reducing it from $50/bbl to $35/bbl.
One of the first problems facing the Libra partners was agreeing on a formula to calculate the break-even price so they could track their progress. “All the different companies have different criteria. We created a common ground,” Osmond Coelho Jr., general manager for project design and implementation for Petrobras, said during a technical paper presentation on that effort (OTC 29336).
Pricing the Future
The drive to lower the cost of first phase of Libra development, known as Mero, touched nearly every aspect of the project, which was summarized in six papers on “well testing” during an afternoon-long session at OTC. Accomplishments included a well that produced 60,000 BOE in a day—40,000 of which were light oil—during the production test (OTC 29533).
But that was not a typical well test. Rather than simply analyzing how the reservoir reacted after formation flows, staff created a testing method designed to simulate a development plan that required reinjecting the large volume of natural gas and carbon dioxide flow with the oil.
Production wells were paired with injection wells several miles away to test how the combination would perform. The FPSO doing the work moved from well to well in an area that will eventually be covered by four such vessels.
Reports from the series of short tests were positive. The complex formation proved widely permeable. During the short tests they did not observe breakthroughs—growing volumes of reinjected gas increasing the gas cut in the production. Rising gas cuts could max out the separation system, limiting oil output.
Gas injection is expected to enhance oil production over time, but the tests were too short to test that effect. When production begins, the plan is to alternately inject water and gas. To reduce the cost of pipes running to wells in water that is about 7,000 ft deep, they plan to use a single line, that will be flushed out between cycles, rather than the usual two lines.
Experiments are being done with composite materials rather than steel pipe, which often develops cracks when exposed to carbon dioxide. And a subsea separator is under development to remove gas at the seafloor.
The partners need to compress the time it usually takes to put a megaproject into service, and at the same time find innovative ways to reduce the cost of doing so. Design decisions made now will define the limits of what can be produced in the future. But the project will be limited by its contract of 35 years.
Project teams need to “do all that for a low cost and do it fast enough to get the oil out before the contract time runs out,” said Paulo Sergio Rovina, Libra general manager for Petrobras.
No one knows if Mero will produce oil with a $35/bbl break-even price as planned. Coelho is already looking for ways to reduce it further. “In the future I would like to come back to this to produce Libra at $30” he said.
