Canada’s crude oil production will rise 75 percent to 5.8 million barrels per day over the next 22 years, with the Alberta oil sands accounting for 86 percent, while natural gas output will rebound from several years of decline to reach 17.4 billion cubic feet per day over the same period, the National Energy Board said Nov. 21 in its long-range forecast.
The targets, using the NEB’s “most likely” case, are strongly tied to assumptions that Canada will enter offshore markets with crude bitumen and LNG.
Gaetan Caron, CEO of the federal regulatory agency, said in a statement that Canada’s energy resources are “more than enough” to meet its domestic demand, leaving “significant amounts” available for export, although growth in those markets and access to them remain “key uncertainties.”
The report said improvements in efficiency will mean that by 2035 the energy consumed per unit of economic output will be 20 percent lower than current levels, while new passenger vehicle emission standards will see a reversal in that sector’s long-term upward trend in energy use.
The NEB estimated that Canada has 171 billion barrels of remaining oil reserves, 98 percent attributed to oil sands bitumen, and 1,093 trillion cubic feet of marketable gas, with tight gas estimated at more than half that resource.
139% increase by 2035
The report said total light and heavy crude available for export is expected to rise 139 percent to 5.5 million bpd by 2035, although light crude exports are forecast to peak at 1.6 million bpd in 2025, then start a gradual decline to 1.4 million bpd in 2035, while heavy crude is projected to increase by 182 percent to 4.2 million
It said there is “considerable potential” to increase crude bitumen reserves, with Alberta’s Grosmont Carbonate formation accounting for 21 percent of oil sands resources and poised to be converted to reserves following Alberta government approval in July of the first commercial project.
The study said its projected increase in WTI prices to $110 per barrel in 2035 from $94.05 in 2012 is “sufficient to promote active growth in oil sands production,” which is expected to account for 86 percent of Canada’s crude output in 2035 compared with 57 percent in 2012.
The NEB said the Henry Hub gas price, used for its mid-range forecast, is expected to reach $6.20 per million British thermal units (in 2012 dollars) in 2035 from $3.94 in 2013.
Bitumen volumes are projected to climb over the next 22 years to 5 million bpd and could eventually reach 8.3 million bpd if the current proposed projects go ahead.
‘In-situ extraction’
The growth projection is bolstered by the fact that 80 percent of oil sands reserves are “well-suited to in-situ extraction” that generates “better economics” than mining projects, the NEB said in forecasting an average annual growth rate between 2012 and 2022 of 8 percent from in-situ operations and 6 percent from mines, followed in the 2025-35 period by 8 percent in-situ growth and less than 1 percent from mines.
The study expects growth in upgraded bitumen volumes in Alberta to yield 1.6 million bpd in 2035, lagging well behind the increase in production.
Conventional crude production in the Western Canada Sedimentary basin, spurred on by the use of horizontal drilling and multistage hydraulic fracturing in tight oil plays, is targeted at 406,000 bpd by 2015, while Eastern Canada’s offshore is seen as shrinking to about 100,000 bpd by 2035, or one-third of 2023 levels.
Increase in export availability
“Canadian crude oil available for export has been rising and will continue to respond to increases in supply from Alberta’s oil sands and changes in supply from conventional sources,” the study said, but added the potential to access markets beyond the U.S. and evolving rules and regulations covering oil sands development pose uncertainties.
On the gas front, tight production from sandstone, siltstone and carbonate reservoirs can draw from resources of 530 tcf, including a combined 449 tcf on the British Columbia and Alberta sides of the Montney play.
Frontier resources in Northern Canada and the offshore contained an estimated 116 tcf, with 66 percent in the Mackenzie Delta-Beaufort area and the remainder in the Arctic Islands, while the offshore East Coast has an estimated 91 tcf and offshore British Columbia has 17 tcf.
The NEB said it assumes 1 bcf per day of gas will be exported as LNG in 2019, growing to 2 bcf per day in 20121 and 3 bcf per day in 2023, while the number of gas wells drilled will rise to 3,200 in 2035 from 1,100 in 2012.
Price recovery, LNG exports
Marketable gas production is forecast to shrink to 11.2 bcf per day in 2018, then feed off a price recovery and LNG exports to reach 17.4 bcf per day in 2035, when gas consumption to power oil sands operations is expected to reach 3.4 bcf per day.
The report noted deeper wells generally produce at higher rates, reflected in average initial production rates in Western Canada, where technology has seen those per-well rates grow to 1.2 million cubic feet per day from 550,000 cubic feet in 2006.
The Montney formation in British Columbia is expected to contribute 6.1 bcf per day in 2035, quadrupling from 2013 levels, and 1.6 bcf per day in the Alberta sector in 2035, a five-fold rise from 2013.
Net gas available for export in 2035 is estimated to be 4.5 bcf per day in the NEB’s “most likely” case, but could be raised to 10.7 bcf per day.
The study said the timing and volume of LNG exports are “key uncertainties given the impact that this could have on exploration, production, prices and infrastructure development.”
It said potential labor, service or equipment shortages could impact the pace of gas drilling, especially over the next decade with the possible pressure to ramp up production for LNG.
