Crude Bitumen Production


Crude Bitumen Production


Updated August 2017


Mined & In Situ Bitumen Production

Figure S3.1

  • Total combined mined and in situ bitumen production did not significantly change in 2016 from 2015, settling at 403.3 thousand cubic metres per day (103 m3/d), or 2537.9 thousand barrels per day (103 bbl/d).
  • As shown in Figure S3.1 [Tableau], total mineable raw production decreased by 1.3 per cent in 2016 due primarily to the Fort McMurray wildfires.
  • Total mineable raw production is forecast to grow by 41.3 per cent by 2026 relative to 2016 levels; Suncor Energy’s Fort Hills project and Imperial Oil’s Kearl expansion project are forecast to contribute the bulk of the added production.
  • Although there were a number of in situ projects that continued to ramp up production, total output increased only modestly, 1.9  per cent from 2015 to 2016. Growth in 2016 was slower as a result of fewer primary and experimental schemes, smaller operations shutting in, and oil sands facilities in the Fort McMurray area being temporarily shut in due to the wildfires.
  • Total in situ production is forecast to grow 56.1  per cent by 2026 compared with 2016 in spite of the reassessment of project start dates in light of the current low price environment. This latest forecast is slightly lower than the previous one due to the reassessment of project dates.
  • By 2026, in situ bitumen is forecast to account for 57.4 per cent of total raw bitumen produced, as seen in Table S3.1 [HTML] below.
  • Total raw bitumen accounted for 84.8 per cent of combined crude oil (excluding pentanes plus) and raw bitumen produced in 2016.

Table S3.1

Mining Project Highlights

  • Although there were year-over-year gains of 2.4 103 m3/d (15.1 103 bbl/d ) at Shell Canada’s Muskeg River mine and 0.5 103 m3/d (3.1 103 bbl/d) at its Jackpine mine, 2.8 103 m3/d (17.6 103 bbl/d) at Imperial’s Kearl mine, and 1.2 103 m3/d (7.6 103 bbl/d) at Syncrude Canada Limited’s Mildred Lake mine, and 0.3 103 m3/d (1.9 103 bbl/d) at its Aurora mine, and 0.2 103 m3/d (1.3 103 bbl/d) at Canadian Natural Resources Limited’s (CNRL’s) Horizon mine, total mineable bitumen production decreased in 2016. This was entirely due to decreased production of 11.1 103 m3/d (69.9 103 bbl/d) at Suncor’s operations.
  • Suncor saw the greatest year-over-year production decrease since its mining operations were the closest to the Fort McMurray wildfires and therefore the most affected in May 2016. As a result, Suncor’s mining production fell 22.7 per cent to 37.9 103 m3/d (238.5 103 bbl/d) compared with 2015 levels.
  • Output at CNRL’s Horizon mine grew by 0.9 per cent to 23.3 103 m3/d (146.6 103 bbl/d) in 2016. Production slowed during the summer in order to prepare for additional output from Phase 2B that came online in October 2016.
  • Completion of the Horizon Phase 3 expansions, expected to occur in late 2017, will provide further production gains.
  • Shell increased production at its Muskeg River operation in 2016 by 11.9 per cent to 22.6 103 m3/d (142.2 103 bbl/d) and increased output at its Jackpine mine by 2.8  per cent to 18.1 103 m3/d (113.9 103 bbl/d). Shell’s increases were the outcome of having higher monthly outputs in 2016 compared with the corresponding months in the previous year and maintaining production during the Fort McMurray wildfires because the sites are located farther north than most other mining projects.
  • Imperial continued to ramp up Phase 2 of its Kearl project in 2016, with production increased by 10.5 per cent to 29.5 103 m3/d (185.6 103 bbl/d) relative to 2015.
  • Syncrude realized a 6 per cent increase in year-over-year total production from 2015, averaging 51 103 m3/d (320.9 103 bbl/d) in 2016. While the gain for 2016 is attributed to cost reduction initiatives and recovery from the Mildred Lake outage in 2015, the proximity of Syncrude’s assets, particularly Mildred Lake, to the Fort McMurray wildfires kept production under the ten-year annual average.

In Situ Project Highlights

  • ConocoPhillips Canada increased output at Surmont by more than 152 per cent to 11.1 103 m3/d (69.9 103 bbl/d) in 2016. Despite temporarily shutting in the facility due to the Fort McMurray wildfires, ConocoPhillips was able to return to normal production by the end of the summer and the forecast projects increased production in 2017.
  • Devon Energy increased production by 26.1 per cent to 17.4 103 m3/d (109.5 103 bbl/d) in 2016 across its Jackfish project, which was largely driven by the ramping up of Phases 2 and 3. Lower operating expenses and strong reservoir performance have supported growth from these phases of the Jackfish project.
  • Before the wildfires, Husky Energy Incorporated was in the process of increasing production at its Sunrise project. Although the wildfires negatively affected output in May 2016, production resumed strongly, increasing by 242 per cent, for an average production of  4.1 103 m3/d (25.8 103 bbl/d) for 2016.
  • Production from CNRL’s Primrose and Wolf Lake projects were lower in 2016 relative to 2015 after the company was required by the AER to limit steam volumes at its Primrose East site in March 2016; output for the project averaged 11.2 103 m3/d (70.5 103 bbl/d) for 2016, down 29.1 per cent year over year. The restrictions were put in place as a result of a bitumen seepage incident in 2013 caused by excess steam used in its cyclical steam stimulation (CSS) operation.
  • Nexen, a subsidiary of China National Offshore Oil Corporation Canada Incorporated, experienced a sharp decline of 43.5 per cent from 2015 levels at its Long Lake in situ project to average 3.5 103 m3/d (22 103 bbl/d) of production in 2016. The decrease is attributed to a slowdown in activity following an incident at the company’s integrated upgrader in January 2016 and, as a precaution given the proximity of the Fort McMurray wildfires, halting production in May and slowly restarting in July.
  • As with the company’s mining operations, Suncor’s Firebag scheme was adversely affected by the Fort McMurray wildfires. Between April and May 2016, productivity decreased 85 per cent, although it steadily returned to normal by August. Overall, output slipped 3.4 per cent in 2016 to 28.7 103 m3/d (180.6 103 bbl/d).

Despite continued challenging prices, the modest decrease of bitumen production in 2016 was primarily due to the Fort McMurray wildfires affecting a few major projects over the spring and summer. Other noteworthy factors were a low number of projects shutting in due to current market conditions and a reduction in the number of active primary production bitumen wells in the Peace River and Cold Lake oil sands areas (OSAs).

The forecast of increased production over the next decade is based on projects coming on stream that began before the price drop and other projects that received regulatory approval and favourable financial investment decisions during the current downturn. Production will continue to grow during the forecast period as projects with capital that has already been committed or spent are developed and brought on production.

The forecast takes into account market uncertainty and a lag period for capital to be deployed, resulting in delayed projects further out in the forecast horizon and a lower outlook compared to last year’s. Volumes are forecast to continue to grow gradually as several existing projects cautiously continue to ramp up production. The lower capital currently accessible for new schemes, particularly where multiple new and existing projects are competing for a company’s funding, are considered in project timelines. Companies are currently focusing on preservation and efficiency rather than aggressively pursuing expansions and growth. Consequently, a number of new projects and expansions that have not progressed very far have been deferred or excluded in the forecast.

Climate change policies at the provincial and national levels have the potential to impact investment decisions and subsequent production. Alberta Bill 25, Oil Sands Emissions Limit Act, proposes a hard emissions limit on the oil sands sector of 100 megatonnes (Mt) per year. Preliminary analysis by the AER indicates that oil sands production will remain under the 100 Mt emission limit during the forecast period based on current emission rates. Alberta’s Climate Leadership Plan and federal intentions of mandating a pan-Canadian minimum price on carbon have been accounted for in this year’s crude bitumen supply cost estimates and is further discussed in that section’s methodology.

Based on the crude bitumen supply cost estimates for 2016, current prices are insufficient to encourage widespread development of greenfield projects in the near term. However, expansions of existing mines and in situ schemes stand to benefit from reduced costs associated with using existing infrastructure, labour, and materials. Producers are exploring and capitalizing on various cost-saving opportunities, including modularizing and standardizing facilities, allowing for the reduction in well pad sizes and increased well lengths. Lower operating costs have been realized in terms of natural gas and electricity prices contributing to decreased fuel costs. The use of solvents and other methods to improve bitumen recovery rates and reduce emissions from in situ projects continues to be tested and developed.

The methodology section provides a list of projects considered in the forecast.

Figure S3.2

Table S3.2

For OSAs, as shown in Table S3.2 [HTML], the only area with positive in situ production growth was in the Athabasca region (1.9 per cent increase), mainly as a result of a slightly higher number of wells and a modest improvement in steam-assisted gravity drainage (SAGD) efficiency. Significant increases in production within Athabasca over the past decade have been driven by the expansion of SAGD development. Peace River and Cold Lake both experienced a decrease compared with 2015 (9.5 per cent and 10.5 per cent, respectively), primarily due to a reduction in the number of wells and reduced productivity from the primary and CSS schemes prevalent in those areas.

Upgraded Bitumen Production

Figure S3.3

Table S3.3

  • Average daily upgraded bitumen production in 2016 was down 4.8 per cent from 2015. Declines at the upgraders of Nexen (Long Lake) and Suncor vastly outweighed output increases at Shell’s and Syncrude’s sites; CNRL remained unchanged. Uncertainty surrounding the future of Long Lake has resulted in the project being removed from this year’s forecast. Total output is forecast to increase by 11.2 per cent in 2017 on the assumptions that companies have recovered from the production lost during the Fort McMurray fires and that the turnarounds planned for 2016 occurred. Figure S3.3 [Tableau] shows that upgraded bitumen production is expected to increase by 31 per cent between 2016 and 2026.
  • Over the forecast period, the percentage of crude bitumen sent for upgrading is forecast to decline from 42.2 per cent of total raw bitumen produced in 2016 to 35.4 per cent in 2026. On average, about 15 per cent of raw bitumen used as feedstock for upgrading is lost in the conversion process; in 2016, this conversion loss improved to approximately 12 per cent due to lower throughput at Suncor and Syncrude facilities that use coking processes. The growth in production of nonupgraded bitumen is expected to outpace that of upgraded bitumen mainly because new mines, namely Fort Hills and Kearl, will not have upgrading capabilities.

Upgraded Project Highlights

  • Nexen’s Long Lake facility experienced an explosion at its hydrocracker unit in January 2016 and synthetic crude oil (SCO) production was halted thereafter. Nexen elected to shut down its upgrading operations indefinitely in July 2016. As a result, year-over-year output fell 95.8 per cent to 0.2 103 m3/d (1.3 103 bbl/d) across 2016. Production on the in situ side of the scheme continued, albeit at a reduced rate.
  • Production in 2016 from Suncor’s upgraders declined by 19 per cent from 2015 largely due to the planned turnaround of its Upgrader 2 in the first quarter of 2016 and the Fort McMurray wildfires in May. After making a steady rebound in June, output averaged 42.1 103 m3/d (264.9 103 bbl/d) in 2016.
  • CNRL’s Horizon production remained fairly flat at 20 103 m3/d (125.9 103 bbl/d) in 2016. Although not significantly affected by the Fort McMurray wildfires, production temporarily decreased in the third quarter due to preparations to bring Phase 2B on stream by the end of the year. Output is forecast to escalate as capacity continues to be added, notably with the completion of Phase 2B in 2016 and Phase 3 in 2017.
  • Shell sustained growth of 8.1 per cent at its Scotford upgrader in 2016. Despite slowed production at the end of the first quarter that was tied to a turnaround, SCO production for the year reached 42.1 103 m3/d (264.9 103 bbl/d). The location of Scotford, near Edmonton, ensured that the upgrader was not directly affected by the Fort McMurray fires.
  • Syncrude’s upgrading output increased by 9.7 per cent to 44.1 103 m3/d (277.5 103 bbl/d) in 2016. As both Syncrude’s and Suncor’s facilities were closest to the Fort McMurray wildfires, they saw the sharpest decrease in production, especially in May and June. Although SCO production dramatically slowed during these months, Syncrude rapidly accelerated production into the third quarter of 2016 to generate increased volumes for the year.

Fort McMurray Wildfires

Wildfires that began to the southwest of Fort McMurray quickly grew and spread, prompting a local state of emergency beginning on May 1, 2016. The Horse River Fire, which colloquially became known as the Fort McMurray wildfires, eventually covered approximately 590 000 hectares. More than a dozen operating oil sands schemes near the wildfires, shown in Figure S3.4 [Tableau], were affected as companies wound down operations to safely evacuate employees and residents in the area. Efforts by emergency personnel, along with favourable weather in June, led to the wildfires being declared under control on July 4.

Virtually all the oil sands projects had some form of risk mitigation in place at the time of the wildfires that prevented any serious damage, such as having a safe distance between facilities and treelines, having contingency plans to evacuate nonessential staff, and having the capacity to cooperate with regional first responders. At the wildfires’ peak, the AER estimates that about 250 103 m3/d (1.5 million bbl/d) of raw production and 100 103 m3/d (660 103 bbl/d) of upgraded production were taken off line. Total raw production lost over the duration of the wildfires is calculated to be in the neighborhood of 4.8 106 m3 (30 106 bbl).

Although a number of in situ schemes were affected by the wildfires and lingering smoke, Suncor’s and Syncrude’s large-scale mining and upgrading assets saw the greatest impact to production volumes due to their close proximity to the wildfires.

In addition to the production issues, a handful of pipelines in the area were shut down as a precaution, creating logistical challenges. Infrastructure delivering natural gas, diluent, and electricity and pipelines carrying products were affected, constraining producers’ abilities to transport bitumen. While no significant damages were reported, companies faced unique challenges when restarting the pipelines with reduced flow rates.

In the wildfires’ aftermath, residents were permitted staged re-entry into Fort McMurray between June 1 and 15, subject to safety and availability of essential services. Oil sands producers quickly managed to ramp production back to relatively normal levels as smoke cleared near operations and workers returned to sites.

Figure S3.4

Petroleum Coke Production

Figure S3.5

  • In 2016, coke inventories reached 106 million tonnes, up 8 million tonnes from 2015. As can be seen in Figure S3.9 [Tableau], inventories remained constant from 1998 to 2000 due to higher on-site use of coke by the upgraders; however, this has been followed by a trend of rising stockpile inventories related to increased SCO production at upgraders.
  • Approximately 90 per cent of coke produced at oil sands mines is stored in pits; most operators intend to eventually use the stockpiled coke in reclamation processes.

Oil sands petroleum coke, also referred to as “pet coke” or just “coke,” is a by-product of upgrading and is mostly stockpiled in Alberta. It is high in sulphur but has lower ash content than conventional crude oil petroleum coke. Suncor, Syncrude, and CNRL operate oil sands mines near Fort McMurray that use upgrading processes that produce coke; Nexen produced limited amounts of coke from its OrCrude gasification process at its Long Lake facility; Shell relies exclusively on hydrocracking technology, which does not produce coke as a by-product. Statistics of coke inventories reported in ST39: Alberta Mineable Oil Sands Plant Statistics show increases in the total closing inventories per year, as illustrated in Figure S3.9 [Tableau].

Approximately half of all coke produced in 2016 came from Suncor’s operations. Suncor has burned small amounts of coke in its boilers for decades at its mine near Fort McMurray, with about 11 per cent of its annual coke production used for site fuel in 2016.

Syncrude, which produced 20 per cent of all coke output in 2016, reported that about 21 per cent of its coke production was used as site fuel, similar to 2015. At CNRL’s Horizon project, all coke produced is stockpiled, accounting for just under 10 per cent of total coke inventories in 2016.