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In-Situ Bitumen To Remain Canada’s Top Industrial NatGas Burner, Says CAPP

The biggest Canadian source of new oil supplies will continue to be the nation’s top industrial natural gas burner, predicted the Canadian Association of Petroleum Producers (CAPP).

Underground in-situ bitumen extraction, using natural gas-fired steam injections, will pump out an estimated 800,000 b/d, or 62% of 1.3 million b/d in currently foreseeable oilsands production growth, according to CAPP’s annual supply forecast.

The new oilsands output -- raising the northern Alberta bitumen belt total to 3.7 million b/d – is expected to account for 95% of all Canadian production growth by 1.5 million b/d to 5 million b/d.

Increases in light oil output, from Canada’s east coast offshore wells and western shale formations tapped by horizontal drilling and hydraulic fracturing, will be largely offset by aging, depleted conventional reserves, the forecast indicated.

The trade association’s oil supply report does not dwell on natural gas use. But the issue is a hot study topic for industry-supported agencies such as the Canadian Energy Research Institute (CERI), as both a cost item and source of greenhouse gas emissions.

Natural gas burned per bbl of oilsands output ranges from 0.33 GJ (0.31 MMBtu) for a mine digging out non-upgraded bitumen to 2.58 GJ (2.45 MMBtu) for an integrated plant using in-situ steam extraction and a synthetic crude upgrader, CERI calculated.

The lowest-cost, fastest-growing method, steam-assisted gravity drainage, or SAGD, with horizontal well pairs for in-situ heat injection and production flows, averages gas use of 1.18 GJ/bbl (1.12 MMBtu per bbl) of non-upgraded bitumen.

“Mining production grows from 1.0 million b/d in 2016 to reach 1.5 million b/d in 2030,” CAPP’s forecast said. “In-situ development is the primary driver of growth, expanding from 1.4 million b/d currently and reaching 2.2 million b/d.”

The producer group explained that “In situ projects require less upfront capital than mining projects and incremental production can be added in smaller phases.”

The production growth is expected to be concentrated over the next four years, as projects begun before the 2014 oil price crash reach completion. Output increases are expected to continue after 2020 but only at a modest annual average rate of 2%.

Annual oilsands investment has dropped off to C$15 billion ($11.2 billion) this year from C$34 billion ($25.5 billion) in 2014 as current projects are finished and new ones are deferred until prices increase, CAPP said.

The IHS Markit consulting firm echoed CAPP’s outlook in forecast released Thursday, which predicted “large production additions” over the next three years followed by a slow growth pace as long as oil prices stay low.

The consulting firm pointed to “decreasing costs in existing operations and higher [plant] utilization rates as well as the completion of the projects being constructed at the time of the price collapse. A lack of material production declines from oil sands facilities – unlike other sources of supply – also makes growth more readily achieved than other forms of oil production.”

Effects on natural gas consumption are monitored by Canadian regulatory agencies. The National Energy Board (NEB) has estimated that oilsands gas demand averaged 2.4 Bcf/d last year or about one-quarter of total Canadian consumption. But the full size of the bitumen belt gas appetite, as measured by the Alberta Energy Regulator (AER), was even bigger.

The NEB only counts purchased gas. The AER calculated 2016 consumption as 2.9 Bcf/d by also counting byproduct gas of oilsands operations, which the plants immediately consume and do not put on the market.

The latest edition of the AER’s annual state-of-the-industry reserves report projected that gas use by oilsands complexes, including built-in heat and power cogeneration stations, will grow by 62% to 4.7 Bcf/d as of the mid-2020s.

CAPP presented its production growth forecast as a case for regulatory approvals of export pipeline projects to Canada’s Pacific and Atlantic coasts. The producer group estimated total Canadian oil delivery capacity needs to increase by about 1.5 million b/d.

The Canadian regulatory and industry jury remains out on when the growth will run into an Alberta government cap on oilsands carbon emissions of 100 million tons/year, largely owed to high gas consumption by thermal plants. Emissions are currently 70 million tons.

CERI calculated the climate change policy wall will be hit in the next eight to 11 years unless projects significantly improve fuel efficiency.

But at the Global Petroleum Show in Calgary, Alberta Premier Rachel Notley described the day of reckoning as still far down the road. A provincially appointed technical advisory group is due to report soon on an implementation strategy for the emissions cap.

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