The last barrel
As I was visiting various display booths at the SPE’s ATCE in Dallas, I was impressed at how many relatively new service providers have created innovative technologies designed to increase efficiencies in U.S. shale fields. Companies were showcasing perforating tools/techniques that deliver angled openings and new methods to divert frac fluids in horizontal wells to lower costs and maximize ROI.
Eggs in one basket? But with all this energy directed at creating value from formations that have no intrinsic porosity or permeability, will the industry be ready to capitalize on conventional and/or alternative opportunities to fill the supply gap once the unconventional fields reach a breaking point? Despite the hyper-intensity on developing mudrock “reservoirs,” several operators have the foresight to work on projects outside the play du-jour.
Oil-sands revival. Although recent logistical difficulties have driven the price of Canadian crude benchmarks lower, Calgary-based Suncor Energy opened its new Fort Hills oil sands mine in northern Alberta in September, after spending $13 billion on the project. The massive undertaking indicated some operators are visualizing life after shale and moving forward in an industry many believed would never see new investments. The sprawling complex in Canada’s freezing wilderness, cut out of a forest clearing roughly the size of Cleveland, Ohio, was thought to mark the end of an era for big projects of its kind. But with its lower carbon emissions, combined with a reduced cost structure, Fort Hills may offer a blueprint for new mines.
The future of oil sands projects was in serious doubt, when oil prices dropped to less than $30/bbl in early 2016 and triggered a mass exodus of multinationals from the region. The bust forced Canadian producers to cut costs dramatically. However, “we are starting to see a return to big projects,” says Wood Mackenzie’s Mark Oberstoetter, thanks to new technologies and froth-treatments that eliminate the need for multibillion-dollar upgraders. This, combined with U.S. crude prices hovering around $75/bbl, are helping to make the industry profitable again.
While the upfront cost of a mine is higher than developing oil sand wells, their decades-long lifespans can make them lucrative for companies willing to wait, said Kevin Birn, IHS Markit. “The trick is getting over the upfront cost.” If companies are patient, the return on a mining operation is good. And Fort Hills is operating better than planned, producing 150,000 bopd. It should hit 194,000 bopd by the fourth quarter.
African deepwater safari. The Saudis’ 2015 oil price manipulation strategy worked to perfection and successfully drove a stake in the heart of deepwater activity. When crude slumped, spending dropped, because the best African prospects are in deep waters. But cost-cutting initiatives, combined with revised subsea methods and updated technologies, have enabled deep water to compete with onshore tight oil plays.
Armed with stronger balance sheets and higher crude prices, ExxonMobil, Shell and BP plan to double drilling in African waters this year. “The majors moving back into these areas for exploration is the first sign of recovery,” said Adam Pollard, a consultant at Wood MacKenzie. “Africa is one of the first regions to suffer when benchmarks go down, but it’s a good place for exploration when the price is supportive.”
According to Tracey Henderson, V.P. at Dallas-based Kosmos Energy, “the more troughs and crests you endure, the less you tend to get fussed about it.” Kosmos used the downturn to buy licenses, and last year it acquired five offshore blocks in Ivory Coast. At the same time, it also sold stakes in Mauritania and Senegal to BP, as the company builds its natural gas business in anticipation of rising demand.
And there are other signs of a recovery. Rigs working offshore Africa have increased to the highest level in two years, according to Baker Hughes data, and consultants expect 30 offshore exploration wells to be drilled this year, compared with 17 in 2017. Acquisitions along the west coast also have accelerated. Shell secured its first exploration acreage offshore Mauritania in July, and ExxonMobil bought stakes in Namibian fields in August. For companies willing to take the risk, the prize could be significant. The U.S. Geological Survey estimates that there are 41 Bbbl of oil and 319 Tcfg yet to be discovered in sub-Saharan Africa.
With prices steady, unlocking new reservoirs becomes paramount in the region. “The sense of optimism has definitely taken hold at this point,” Kosmos’s Henderson concluded.
Alaska North Slope is poised to re-emerge as a major source of U.S. energy production, with crude output potentially increasing as much as 40% during the next eight years, according to IHS Markit. Based on recent discoveries, IHS estimates that the ANS basin holds 38 Bboe in remaining recoverable resources. The company says that the ANS is a late-emerging super-basin, rather than a mature basin based on recent discoveries in the shallow Nanushuk and Torok formations. The new finds indicate there is significant growth potential beyond the Endicott and Ivishak reservoirs in the Prudhoe Bay and Endicott fields.
Furthermore, IHS Markit said there is an estimated 9.5 Bboe yet to be discovered in the Alaska National Wildlife Refuge (ANWR) and central slope combined. Aside from the new discoveries, the basin warrants attention from prospective operators, because the Alaska North Slope now has fewer barriers to entry for operators, making it more competitive.
Wisdom for today. Australian musician Peter Allen—with his partner Carole Bayer—created a song that was popular in the 1970s. Among the lyrics is a timeless truth: Don’t throw the past away; You might need it some rainy day; When everything old is new again. 
