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Canadian Oil Sands Facts and Information
According to the American Petroleum Institute, the majority of bitumen is produced through surface mining, but this is limited by the fact that only about 20% of oil sands resources are recoverable in this way. The remaining 80% are too deep to mine effectively and must be recovered through "in-situ" techniques, several of which have been pioneered by the industry. In-situ, Latin for "in position," involves drilling a well to extract bitumen and is often accompanied by a technique called Steam-Assisted Gravity Drainage (SAGD), which involves pumping steam through a horizontal well to liquefy the bitumen, so that it can flow down into a second horizontal well and be pumped to the surface. Another process similar to SAGD is called Cyclic Steam Stimulation (CSS), which differs from SAGD in that it uses only one well pipe for both the injection of steam and the extraction of bitumen. It does this by injecting steam and allowing the well to "soak" before reversing the flow to draw out the liquefied bitumen. In its annual report for 2014/15, the Alberta Energy Regulator (AER) said it regulated 50 thermal in-situ projects and nine oil sands mines.
Although ExxonMobil Corp. and Imperial Oil Ltd. both claim the first patents for both SAGD and CSS, a new generation of recovery techniques took the Canadian Heavy Oil Conference by storm in November 2015. N-Solv Corp. has developed a recovery method that substitutes steam heated to 200-220 C (390-430 F) with 40-60 C (100-140 F) baths of propane or butane. A pilot plant north of Fort McMurray has produced more than 60,000 bbl since 2Q2014, with operating costs of less than C$20/bbl (US$15). Meanwhile, a consortium of oil producers, pipelines and technology contractor Harris Corp. has started a two-year trial of a system called ESEIEH, pronounced "easy" and short for Enhanced Solvent Extraction Incorporating Electromagnetic Heating. Like N-Solv, ESEIEH uses pairs of horizontal wells drilled in close parallel across oilsands deposits. One well in each pair houses a long, low frequency microwave antenna. Propane warmed up to 70-80 C (160-175 F) serves as an underground heat conductor. In both new technologies the fluid is recycled, not lost in the production process. Experiments to date indicate that operating costs of an ESEIEH extraction network would only be C$10-14/bbl (US$7.50-10.50/bbl) of bitumen production. Finally, Imperial's 3Q2015 report to shareholders disclosed that a solvent extraction method will be incorporated into its next oil sands development. Imperial calls its variation on the new technology theme SA-SAGD, short for Solvent-assisted, Steam-assisted Gravity Drainage. The technique figures in a megaproject called Aspen, which would tap a 1.2 billion bbl deposit too deep to mine that is 45 kilometers (27 miles) north of Fort McMurray, for up to 162,000 b/d and forecast to cost C$11 billion (US$8.2 billion) over two stages of construction (see Daily GPI, Nov. 6, 2015).
The World Energy Council (WEC) reported in December 2014 that Canada has the largest deposits of oil sands, and holds about two-thirds of the world's total. Other substantial oil sands deposits can be found in Russia, Kazakhstan and the United States. According to the WEC, oil sands in Alberta hold 1.73 trillion bbl of oil, and Canada is the world's leading producer of oil from oil sands, with more than 40% of Canadian oil production originating from oil sands in 2008. The Government of Alberta reports that the province's oil sands hold the third-largest oil reserves in the world, after Venezuela and Saudi Arabia. AER added that at 841 million bbl (2.3 million b/d), raw crude bitumen production accounted for 80% of the province's total crude oil and bitumen production in 2014. Overall raw bitumen production increased 11% from 2013 to 2014, thanks to a 6% increase in mining projects and a 14% increase in in-situ projects. AER added that of total bitumen production, 47.4% was used as feedstock for upgraders, yielding 953,000 b/d in production. Refineries in Alberta processed 311,000 b/d of upgraded bitumen and 23,000 b/d of non-upgraded bitumen. The province also holds 166 billion barrels of bitumen in established reserves.
Canada's oil sands resources are located in three major deposits: 1) the Athabasca deposits in Northeast Alberta, 2) the Cold Lake deposits, also in Northeast Alberta, and 3) the Peace River deposits in Northwest Alberta. According to Albertan government, these areas collectively underlie 142,200 square kilometers (54,903 square miles) of territory, but reserves shallow enough to mine (up to 75 meters) are found only within the Athabasca area. The surface mineable area equals about 4,800 square kilometers (1,853 square miles) and accounts for just 3.4% of the total oil sands area. The provincial government said that between 1999 and 2013, approximately C$201 billion (US$150.6 billion) was invested in the oil sands industry, hitting a record high C$27.2 billion (US$20.4 billion) in 2012. According to the Canadian Energy Research Institute (CERI) -- which cited estimates from ARC Financial Corp. and the Canadian Association of Petroleum Producers -- investment in the oil sands reached a new record, C$30.8 billion (US$23.1 billion), in 2013.
Being at the forefront of oil sands development, operators in Canada are encountering many challenges related to resource intensity and transportation. Both surface mining and in-situ are water intensive processes and in-situ especially requires quite a bit of energy, often in the form of natural gas to turn the water into steam. Water is usually used to remove sand and mud from the extracted bitumen and, in order to recycle as much as possible, the used water is left to sit in tailing ponds so that mud and sand sink to the bottom and the top layer can then be reused. Natural gas use is also extremely high with oil sands projects. In August 2015, CERI reported that oil sands crude extraction accounted for 46.7% of Alberta's primary energy production in 2014, according to AER figures. Also in 2014, the oil sands industry accounted for 33.6% of end-use energy demand in the province. CERI projected that gas demand by the oil sands industry will increase from about 2.5 Bcf/d in 2014 to a peak of 4.9 Bcf/d in 2030, before slowly declining to 4.5 Bcf/d by 2050.
Oil sands operators must not only take water, natural gas and labor costs into consideration, but also the market price for the extracted oil because sufficient, sustained volatility in any of these key variables could result in a shift in the ultimate economic viability of what are already capital intensive projects. These and other factors, such as the political environment in both Canada and the United States, are important concerns for the future of Canadian oil sands development.
That said, 2015 was not a particularly good year. First, world oil prices remained stuck in low gear. According to data from the U.S. Energy Information Administration (EIA), the FOB spot price for West Texas Intermediate (WTI) crude at Cushing, OK, averaged $50.46/bbl for the first 10 months of the year, reaching a high of $59.82/bbl in June, but bottoming at $42.87/bbl two months later. And while analysts with Tudor, Pickering, Holt & Co. and Evercore ISI, as well as economists with the Bank of England, said in November that crude oil prices could climb as high as $80/bbl by late 2016, others aren't convinced; Goldman Sachs kept its WTI oil price forecast for 2016 at $45/bbl (see Daily GPI, Nov. 19, 2015).
Then there's the tortured saga of Keystone XL -- the controversial, 1,700-mile, 830,000 b/d crude oil pipeline that was to transport dilbit from Hardisty, Alberta to Steele City, Nebraska. After years of regulatory review and delays, the President Obama officially rejected the $8 billion project in November, denying TransCanada Corp. the necessary presidential cross border permit through the U.S. State Department (see Shale Daily, Nov. 6, 2015b). TransCanada also withdrew its application with the Nebraska Public Service Commission, but the company said it did so only because it lacked the federal permit; TransCanada maintains that it still has support from shippers and other stakeholders, and that the pipeline is the safest option to deliver both Canadian and U.S. crude to refineries in the Midwest and on the Gulf Coast (see Shale Daily, Nov. 18, 2015). The project could also receive new life if a Republican wins the White House in 2016, but all three Democratic candidates are opposed (see Shale Daily, Sept. 24, 2015).
On Oct. 19, 2015, the Liberal Party won the Canadian federal election and Justin Trudeau became the nation's new prime minister. During the campaign, Trudeau said he supported the Keystone XL pipeline. After Obama rejected the project, Trudeau said he was not surprised by the decision and voiced disappointment. Other reports, however, said he was relieved. Albertans also elected a new provincial government in May 2015. The new regime, led by Premier Rachel Notley and the New Democrats, pledged to craft economic policies on a more "diversified" footing, rather than one dependent on energy prices and exports of unprocessed bitumen, crude oil and natural gas (see Daily GPI, May 7, 2015).
Since the rejection of Keystone XL, TransCanada said it will continue growing its natural gas supply network in Alberta and neighboring British Columbia, but at a reduced rate (see Daily GPI, Nov. 16, 2015). Its subsidiary, Nova Gas Transmission Ltd. (NGTL), is currently building or waiting for regulatory approval of C$2.7 billion (US$2 billion) in facilities for up to 4 Bcf/d, with completion expected in late 2016 and the fall of 2017. A new round of projects estimated to cost C$570 million (US$428 million), with 2.7 Bcf/d of capacity, is expected to come online in 2018. An increase in the use of fuel by Alberta thermal oil sands operators was cited as one of the main drivers behind expanding the 25,000-kilometer (15,000-mile) NGTL system.
Analysts with IHS Energy reported in July 2015 that despite increasing costs, environmental concerns and delays in adding new takeaway pipeline capacity, oil sands production increased more than 128% (1.2 million b/d) between 2005 and 2014, putting Canada in third place in terms of global oil supply growth. They added despite low commodity prices, oil sands production remains on track to grow by another 800,000 b/d by 2020. IHS reiterated that its previous research had determined that construction and operation of the Keystone XL pipeline would not have a material impact on greenhouse gas emissions, since refiners on the U.S. Gulf Coast will continue to demand heavy crudes. But oil sands producers are increasingly relying on railroads to take crude to market. According to IHS, the movement of both oil sands and non-oil sands Canadian production, both exported and transported entirely within Canada, rose from negligible levels in 2010 to nearly 190,000 b/d toward the end of 2014. And Keystone XL isn't the only pipeline to generate controversy. Three pipelines located entirely within Canada – TransCanada's Energy East (1.1 million b/d) pipeline (see Daily GPI, April 24, 2015), Kinder Morgan's Trans Mountain Expansion (890,000 b/d) project (see Daily GPI, April 4, 2014) and Enbridge Inc.'s Northern Gateway (525,000 b/d) pipeline (see Daily GPI, Dec. 20, 2013) – have all elicited some degree of public opposition. All three would also transport oil sands production.
During the third quarter of 2015, Canadian Natural Resources Ltd. (CNRL) reported production volumes at its Horizon oil sands mine averaged 131,779 b/d of synthetic crude, a 61% increase over the previous third quarter, and said a C$13 billion (US$11 billion) project to double production to 250,000 b/d was on track and 74% complete. Also during 3Q2015, ConocoPhillips reported its first oil production from its Surmont Phase in-situ oil sands facility in Alberta, and expects production to ramp up through 2017, adding 118,000 b/d gross capacity. Total gross capacity for Surmont 1 and 2 is expected to reach 150,000 b/d (see Daily GPI, Oct. 30, 2015). Meanwhile, Imperial Oil Ltd. and ExxonMobil Canada completed the second phase of an expansion of its Kearl oil sands project in June 2015. Imperial holds a 71% stake in the project, located 70 kilometers (43 miles) north of Fort McMurray, while ExxonMobil holds the remaining 29%. The project is expected to reach about 345,000 b/d of production by about 2020 (see Daily GPI, Jan. 16, 2015).
Local Major Pipelines
Crude Oil: Access Pipeline, Alberta Clipper, Enbridge, Keystone, Keystone XL (Proposed), Northern Gateway (Proposed), Pembina, TransCanada East Coast Pipeline Project (Proposed), TransMountain