Special Report: Forecasts moderate Alberta oil sands production growth

July 12, 2009
Various forecasters have lowered their expectation for increases in bitumen production from Alberta oil sands, but most still see a sizable rise during the next decade, with bitumen production of at least 2 million b/d in 2018 compared with 1.3 million b/d in 2008.

Various forecasters have lowered their expectation for increases in bitumen production from Alberta oil sands, but most still see a sizable rise during the next decade, with bitumen production of at least 2 million b/d in 2018 compared with 1.3 million b/d in 2008.

Alberta’s Energy Resources Conservation Board in its recent update forecasts bitumen production to reach 2.7 million b/d in 2018.1 This rate is a decrease from its forecast last year that saw oil sands production increasing to 3.23 million b/d in 2017.

For determining its current projections, ERCB has lowered its crude price assumptions and now expects US West Texas Intermediate to average $55/bbl in 2009 and increase to $120/bbl in 2018. The lower oil price expectations are one reason for the lower production forecasts.

The lower oil price scenario also ties into the slowdown in world economies that has lowered future oil demand and investment expectations.

Another recent forecast from the Canadian Association of Petroleum Producers estimates oil sands production under a growth scenario will reach 2.6 million b/d in 2018 and 3.3 million b/d in 2025. Without growth and with only projects currently in operations and under construction producing, CAPP expects production to remain relatively constant at 1.957 million b/d in 2018 and 1.987 million b/d in 2025.

In 2008, the Canadian Energy Research Institute forecast oil sands production potential of more than 5 million b/d by 2015 and 6 million b/d by 2030 and a reference case production of 3.4 million b/d in 2015 and 5 million b/d by 2030. CERI now has lowered its production outlook. In its February 2009 outlook, the institute now expects oil sands production to range from 1.9 to 2.9 million b/d in 2015 and from 3.7 to 5.4 million b/d in 2030.3

Oil sands resources

The main deposits discussed in ERCB’s report are the Athabasca Wabiskaw-McMurray, Cold Lake Clearwater, and Peace River Bluesky-Gething that cover about 54,000 sq miles (Fig. 1). Besides showing the three main oil sands areas in Alberta, Fig. 1 also indicates that Saskatchewan contains potential oil sands.

Fig. 2 shows the ERCB bitumen forecast to 2018 and Fig. 3 shows the disposition forecast for crude bitumen and bitumen upgraded into a synthetic crude oil.

The report contains the following assessment of bitumen resources in Alberta at yearend 2008:1

  • Initial in place—1,731 billion bbl.
  • Initial established—177 billion bbl.
  • Cumulative production—6.4 billion bbl.
  • Remaining established—170 billion bbl.
  • 2008 production—0.477 billion bbl (1.30 million b/d).
  • Ultimate potential—315 billion bbl.

The in situ volumes include production with enhanced recovery methods, such as injection of steam, water, or other solvents into the reservoir to mobilize the bitumen, as well as bitumen and heavy oil produced with primary methods from the Athabasca, Peace River, and Cold Lake regions.

ERCB currently is working on an update of the Upper and Lower Cold Lake Grand Rapids deposits and Athabasca Grosmont deposits. It expects to complete the assessment in 2009.

From its previous work, it reduced in the 2008 report the initial established reserves in Peace River to 5.5 billion bbl, based on a 20% recovery factor for thermal processes. But in the report, it also increased the area suitable for mining in the Athabasca region by 141⁄2 townships, based on drilling in that area (Fig. 5). This change increased initial minable recoverable reserves to 38.7 billion bbl, up from 35.2 billion bbl in last year’s report.

These two changes reduced the ERCB initial established reserves estimate by 1.9 billion bbl from that shown in the previous year’s report.

Of the 170 billion bbl remaining established reserves, ERCB considers 80%, or 135 billion bbl recoverable with in situ methods and the remaining 34 billion bbl recoverable with surface mining methods.

The currently active mining developments contain 23.5 billion bbl and active in situ areas contain 3.5 billion bbl of remaining established reserves.

Besides the three mining projects that were on production, other projects that ERCB considers as active includes the Canadian Natural Resources Ltd. Horizon project that started producing synthetic crude oil in early 2009, the Petro-Canada Fort Hills development, the Shell Canada Ltd. Jackpine mine, and the Imperial Oil Ltd. Kearl project (Table 1).

ERCB estimates that the ultimate potential in situ bitumen recovery is 208 billion bbl from Cretaceous sediments and 38 billion bbl from Paleozoic carbonates.

In situ remaining established reserves in areas under active development are 90 million bbl in Peace River, 1,236 million bbl in Athabasca, and 2,350 million bbl in Cold Lake.

Production

In 2008, the upgrading of 264 million bbl of mined bitumen and about 8% of the 213 million bbl from in situ projects yielded 239 million bbl of synthetic crude oil. ERCB noted that bitumen production in 2008 increased by 9% from in situ projects while decreasing by 8% from mined projects, resulting in a 1% production drop from the oil sands compared with 2007.

In 2008, average production from the three oil sands areas was:

  • Athabasca—721,500 b/d mined, 232,100 b/d in situ.
  • Cold Lake—310,700 b/d in situ.
  • Peace River—42,000 b/d in situ.

As noted previously, production from mining projects in 2008 decreased from 2007. In 2007, average production was 784,000 b/d from the three ongoing mining projects operated by Syncrude Canada Ltd, Suncor Energy Inc., and the Shell-operated Albian Sands project.

In 2008, Syncrude produced 47% of the mined production, while Suncor produced 34%, with the remaining 19% coming from the Albian Sands.

The ERCB report attributed the 8% production decrease to 338,000 b/d from Syncrude Crude Ltd. to two planned coker tunarounds and an operational upset during fourth-quarter 2008.

Suncor’s production was 7% lower, at 247,000 b/d, due to planned maintenance, according to the report. ERCB expects Suncor’s 2009 SCO capacity to increase to 350,000 b/d from the current 260,000 b/d.

Shell’s Albian Sands produced an average 135,000 b/d in 2008, a 10% drop from the previous year. ERCB attributed the decline to execution of a mine tailing plan that temporary led to the production on lower grade ore and to planed and unplanned maintenance.

CNRL’s Horizon project began mining in September and produced 346,000 bbl in 2008. SCO from the production started in February 2009.

Table 2 shows the projects ERCB includes in its production forecast for minable projects. It excluded from the list the proposed UTS Energy Corp. Equinox and Frontier projects that, if implemented, would start up in the later part of its forecast.

ERCB forecast that production from mined project would increase to 1.56 million b/d in 2018 from the 0.72 million b/d in 2008.

Fig. 4 shows the historic in situ production from each of the three areas. ERCB expects production from in situ projects to increase to 1.39 million b/d in 2018 compared with 0.58 million b/d in 2008. Its 2018 production projection is 5% less than in its previous year’s report.

Companies have drilled most in situ producing wells in the oil sands as deviated wells from pads to minimize the drilling and production footprint. From 1985 through yearend 2008, the oil sands have had 38,913 wells drilled for exploration and development of the resource. In 2008, companies drilled 4,627 wells in the oil sands. Of these, 1,209 were development wells and 3,428 were exploratory wells. According to the ERCB report, about 9,700 wells were on production during 2008, with the average well producing 62 bo/d.

Production from the Cold Lake region accounts for 53% of the in situ production, with another 40 % produced in the Athabasca region and 7% in the Peace River region, the report says.

As with the mining projects, the timetable for additional in situ projects is uncertain.

CERI in its February 2009 forecast dramatically decreased its estimates of future capital investment in the oil sands (Fig. 6). In its economic slowdown projection, it expects companies to invest $218 billion (Can.) in new oil sands. This is $97 billion (Can.) less than its 2008 base case and $241 billion (Can.) less than its 2008 unconstrained projection.

References

  1. Albert’s Energy Reserves 2008 and Supply/Demand Outlook 2009-2018, ST98-2009, Energy Resources Conservation Board of Alberta, June 2009.
  2. Crude Oil Forecast, Markets & Pipeline Expansions, Canadian Association of Petroleum Producers, June 2009.
  3. McColl, D., The Eye of the Beholder: Oil Sands Calamity or Golden Opportunity?, Canadian Research Institute Oil Sands briefing, ISBN: 1-896091-85-7, February 2009.