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Updated June 2021

In Summary

After a decline in 2018 and 2019, average daily production of marketable natural gas in Alberta stabilized in 2020 at 288 million cubic metres per day (106 m3/d) or 10.2 billion cubic feet per day (Bcf/d). Flat production levels for the year were the result of declines in conventional gas production and increases in production from unconventional sources.

By 2030, marketable natural gas production is expected to increase by 2.4 106 m3/d (0.1 Bcf/d). Rapid production increases are expected across the Foothills Front and Northwestern regions of the province (Petroleum Services Association of Canada [PSAC] areas 2 and 7). A small increase in gas production from oil wells is also projected. Meanwhile, production declines are expected across most other regions of the province.  

Figure S5.1 shows Alberta’s average daily marketable gas production by source and PSAC area.

Table S5.1 shows Alberta’s average daily marketable natural gas production and number of new wells placed on production by year.

Marketable Gas Production in 2020

Figure S5.2 shows Alberta’s average daily production of marketable gas and the number of new producing wells.

Total conventional gas production—defined here as all gas production excluding coalbed methane (CBM) and shale gas—declined by 0.3 per cent in 2020. Shale gas production increased 9 per cent from 2019. Coalbed methane production also increased slightly in 2020, after a decade of consistent declines.

Forecast for 2021 to 2030

Three trends are expected to continue over the forecast:

  • Gas producers target the most productive plays in the province. This means there will be fewer new wells than are historically needed to maintain production levels. 
  • Liquids-rich plays attract the most attention given their profitability. Generally, this will mean higher natural gas liquids (NGLs) in the raw gas stream. 
  • Consolidation of operations is likely to progress as producers seek ways to optimize infrastructure use and reduce operating and capital costs.

Given these trends, most new natural gas wells in Alberta are expected to come on line in the Foothills Front, Central (including shale gas), and Northwestern regions (PSAC areas 2, 5, and 7). Despite an anticipated surge in new wells placed on production, marketable gas production in Alberta is forecasted to increase only slightly by 2030. Production of new wells in these areas narrowly offsets decline rates across other regions of the province.

Oil Sands Gas Production and Use

Oil sands operations produce process gas and produced gas. Process gas is produced during bitumen upgrading, meaning its composition varies by process (e.g., coking vs. hydrocracking). Produced gas is raw natural gas from bitumen wells, and its composition varies by the source formation. Production trends for these gas sources are driven by bitumen production and upgrading.

Figure S5.3 shows the average daily gas production from bitumen upgrading and wells.

Oil sands operators use process gas and produced gas for fuel and feedstock to generate electricity, steam and hot water for on-site operations, and hydrogen for upgrading units. Process gas is also sent to processing facilities for the removal of high-value liquids.

Operators also purchase large quantities of natural gas from external sources—termed “purchased gas”—for use in their operations. In fact, oil sands operations account for almost one-third of total natural gas consumption in Alberta (excluding gas used for cogeneration).

Figure S5.4 shows Alberta’s total purchased, processed, and produced gas for oil sands operations.

Oil Sands Gas Use

In 2020

Gas use by the oil sands sector declined by two per cent from 2019, reaching 96.8 106 m3/d (3.4 Bcf/d. This decline reflected lower output from all oil sands operations due to low crude oil prices resulting from the COVID-19 pandemic.

Forecast for 2021 to 2030

Oil sands gas use is expected to reach 129.4 106 m3/d (4.6 Bcf/d) by 2030, a 34 per cent increase from 2020. Although total gas use increases in line with bitumen production, the bulk of the incremental gas use is gas purchased for in situ bitumen recovery and electricity cogeneration. In situ operations account for most of the bitumen production increases in the forecast, followed by increasing investments from oil sands operators on cogeneration facilities.

Purchased Gas

Table S5.2 shows the average use rates of purchased gas for oil sands operations in 2020.

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