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Updated July 2018

Plants and Facilities

Alberta has over 30 000 oil facilities and close to 21 000 gas facilities, as shown in Figure 9.7 [Tableau] and Figure 9.8 [Tableau], respectively.

In 2017, Alberta had six operating oil sands mines, four bitumen upgraders, four refineries, two coal processing plants, and seven coal mines. Suncor Energy’s Fort  Hills oil sand mine began operations in Q1 2018.

Figure 9.7

Figure 9.8


Table 9.12

Table 9.12 [HTML] shows Alberta average upgraded bitumen production in 2017. Production from Nexen’s Long Lake facility is no longer provided in Table 9.12, following Nexen’s decision to indefinitely shut in the project in 2016.

Oil Refineries

Table 9.13

Table 9.13 [HTML] shows Alberta’s refinery capacity in 2017.

Oil refineries use crude oil, along with upgraded and nonupgraded bitumen and pentanes plus, to produce a wide variety of refined petroleum products such as gasoline and diesel.

In 2017, the four refineries in Alberta, with an estimated total throughput of 74.5 thousand cubic metres per day (103 m3/d)─0.45 million barrels per day (106 bbl/d)─of oil, processed 50.2 103 m3/d (0.32 106 bbl/d) of upgraded bitumen, 2.7 103 m3/d (0.02 106 bbl/d) of nonupgraded bitumen, 20.8 103 m3/d (0.11 106 bbl/d) of conventional crude oil, and 0.8 103 m3/d (0.01 106 bbl/d) of pentanes plus.

The North West Redwater Partnership Sturgeon refinery is projected to come on line in early 2018, with the first phase handling 7.9 103 m3/d (49.71 103 bbl/d) of raw bitumen. The refinery is designed to process bitumen and will produce about 6.4 103 m3/d (40.27 103 bbl/d) of ultra-low sulphur diesel, 4.5 103 m3/d (28.32 103 bbl/d) of diluent and naphtha, 1.4 103 m3/d (8.81 103 bbl/d) of low-sulphur vacuum gas oil, and 0.5 103 m3/d (3.15 103 bbl/d) of butanes and propane.

In 2017, Alberta’s refinery utilization was 101.5 per cent, up from 94.3 per cent in 2016, because refineries had a higher throughput of upgraded bitumen, also known as synthetic crude oil, due to the recovery from the Fort McMurray wildfires.

Natural Gas Processing Plants

Figure 9.9

In Alberta, there are over 600 active gas processing plants that recover natural gas liquid (NGL) mix or specification product, 11 fractionation plants that separate out NGL-mix streams into specification products, and 8 straddle plants. Figure 9.9 [Tableau] illustrates Alberta’s NGL flow.

With NGL production increasing over the last few years, companies have being expanding NGL infrastructure capacity in Alberta, including developing new projects servicing the Montney and Duvernay producing regions.

Pembina Pipeline Corporation finished expanding its RFS II ethane-plus fractionation plant at Redwater, Alberta, in 2016, doubling the company’s ethane-plus fractionation capacity of 11.6 103 m3/d (73.00 103 bbl/d). In 2017, RFS III was completed and started, adding 8.7 103 m3/d (54.75 103 bbl/d) of propane-plus fractionation capacity.

Keyera Corporation completed the expansion of its Fort Saskatchewan fractionation plant, increasing its propane-plus fractionation capacity from 4.8 103 m3/d (30.21 103 bbl/d) to 10.3 103 m3/d (64.82 103 bbl/d) in 2016.

Inter Pipeline Limited’s off-gas liquids extraction facility at Canadian Natural Resources Limited’s Horizon upgrader contributes an additional 2.4 103 m3/d (15.10 103 bbl/d) of ethane-plus extraction capacity. Combined with the off-gas liquids extraction facility at the Suncor upgrader, the two extraction plants have the capacity to recover 6.3 103 m3/d (39.65 103 bbl/d) of NGLs and olefins.

NOVA Chemicals completed its Polyethylene 1 Expansion (R3) Project at the company’s Joffre site. The project, which uses ethane as a feedstock, will produce between 0.431 and 0.499 megatonnes per year of linear low-density polyethylene (LLDPE). This will be the first LLDPE start-up in more than a decade in Canada or the United States.

Approved processing facility projects are expected to increase recovery of liquids by about 30.0 103 m3/d (188.79 103 bbl/d) in 2017, from a total recovery of 103.0 103 m3/d (648.17 103 bbl/d) in 2016. This increase includes the addition of ethanes-plus and propanes-plus fractionation plants, expansions to NGL-mix processing facilities, a new propane dehydrogenation facility, debottlenecking at current facilities, and new pipeline connections.

Table 9.14 [HTML] lists Alberta’s fractionation plants, and Table 9.15 [HTML] lists Alberta’s straddle plants.

Table 9.14

Table 9.15

Figure 9.9

Electricity Infrastructure

As of December 12, 2017, Alberta’s total installed generation capacity, as reported by the Alberta Electric System Operator (AESO), was 16 626 megawatts (MW), of which 7555 MW was gas fired, 6283 MW was coal fired, 1445 MW was wind powered, 894 MW was hydro powered, and 449 MW was from other sources (e.g., biomass, biogas, and solar).

According to the AESO, the percentage of natural gas-fired capacity in the province classified as cogeneration was 65 per cent in 2017. Cogeneration is the combined production of electricity and thermal energy using natural gas as the fuel source. Thermal energy is used for manufacturing, heating, producing steam for in situ oil production, refining, and upgrading.

Alberta’s electricity system has about 26 000 kilometres of transmission lines. It is connected to systems in British Columbia, Saskatchewan, and Montana. These three interties allow Alberta to import or export electricity. In addition to the transmission interties, a natural gas-fired electricity generation unit in Fort Nelson (northern British Columbia) supplies power to the surrounding communities and sells surplus electricity into the Alberta grid.