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Updated June 2020

Figure S5.1 shows Alberta's average daily marketable gas production. The production forecast reflects only the base case for natural gas and liquids prices, with an explanation of this case found in the natural gas and oil price forecast sections.

Summary

Natural gas in Alberta is first produced as raw natural gas and is mostly methane and other hydrocarbon gases. However, it also contains nonhydrocarbons, such as nitrogen, carbon dioxide, and hydrogen sulphide (H2S), which are impurities that are later removed. Once these impurities have been removed, the natural gas is called marketable natural gas.

Average daily production of raw natural gas decreased 3 per cent in 2019, averaging 335.7 million cubic metres per day (106 m3/d), or 11.9 billion cubic feet per day (Bcf/d). High well productivity and high liquid content in the Foothills Front (Petroleum Services Association of Canada Area [PSAC] 2) and Northwestern Alberta (PSAC Area 7) regions helped to mitigate the overall raw production decline resulting from an even larger decrease in number of wells placed on production.

Average daily production of marketable natural gas decreased in 2019 by 4 per cent compared with 2018, averaging 288.1 106 m3/d (10.2 Bcf/d). The decrease in gas production was driven by lower output across most of Alberta, most notably from the Foothills Front and Southeastern Alberta regions (PSAC Areas 2 and 3). The decrease from these regions was partially offset by increases in gas production from oil wells and shale wells. More than half of the production continues to come from the Foothills Front region (PSAC Area 2) as producers remain focused on liquids-rich areas.

Table S5.1 shows Alberta's average daily natural gas production and wells placed on production.

Production in 2019

Figure S5.2 shows Alberta's average daily production of marketable gas and the number of producing wells. There is an option to toggle the marketable gas production and activity forecasts based on base and low liquids prices, with an explanation of these cases in the oil price forecast section.

With a reduction in the number of new wells in the province in 2019 (see Figure S5.2) and decreased production of marketable natural gas from most regions in Alberta, total Alberta marketable natural gas production declined by 4 per cent.

The majority of wells drilled were horizontal, using multistage fracturing completion technology, resulting in highly productive wells. The high initial production rates help offset the higher overall capital costs of drilling long horizontal wells. These wells typically target liquids-rich formations because wet gas is more valuable than dry gas, supporting well economics.

Natural Gas Production Trends

Marketable natural gas production in the Foothills Front region decreased by 3 per cent in 2019. This area represents 52 per cent of the overall natural gas production in Alberta and is considered the main area of growth for new natural gas production. The Montney and Upper Mannville Formations are the primary targets for natural gas development in the area, accounting for approximately 75 per cent of 2019 production in the Foothills Front region (PSAC Area 2). Operators in the Foothills Front continue to target higher-value condensates, with natural gas considered as a by-product. Producers in Alberta can get a higher price for condensates because they typically track oil prices and can be blended with bitumen for transportation.

Marketable gas produced from oil wells increased by 8 per cent in 2019 as producers continue to focus on liquids-rich areas in the Foothills Front and Northwestern Alberta regions. Growth was somewhat dampened with producers shifting spending away from growing production and focusing on sustaining existing assets, lowering debt, and repurchasing stocks.

Production from shale wells increased by 5 per cent in 2019. Shale gas production remains an area of growth, even though it made up only 3 per cent of overall production in 2019. These wells remain a small proportion of production as they tend to have relatively higher capital costs and lower initial productivity rates compared to some of the prominent areas in Alberta.

Though the majority of new wells placed on production are horizontal wells, vertical wells still make up the majority of producing wells. However, producers are drilling fewer vertical wells every year. The number of new vertical wells placed on production in 2019 decreased by 42 per cent. These wells are typically less costly to drill, target dry natural gas, and typically have lower productivity rates.

The share of marketable gas production from the Foothills Front region continues to grow, this trend is anticipated to continue as producers target liquids-rich formations such as the Upper Manville, Montney, and Duvernay.

Montney Formation: Production from the Montney formation, in the Foothills Front, increased in 2019, rising 15 per cent to account for an estimated 12 per cent of total production.

Duvernay Formation: The Duvernay continues to be an active formation with 2019 production growing by 40 per cent compared to 2018 in the Foothills Front area.  The Duvernay within the Foothills Front accounts for approximately 4 per cent of total gas production within Alberta.

Upper Mannville Formation: In the Foothills Front region the Upper Mannville decreased in 2019, falling another 4 per cent after a 26 per cent decline in 2018.

Forecast for 2020 to 2029

As many of the new wells placed on production are expected to be drilled in liquids-rich regions, near-term activity is expected to be sensitive to the low-price environment for oil and natural gas liquids. Based on the forecast cases for oil prices, marketable natural gas production in 2020 is expected to decrease between 4 and 5 per cent compared with 2019, ranging from 273.2 106 m3/d (9.7 Bcf/d) and 277.7 106 m3/d (9.9 Bcf/d). Through the remainder of the forecast, production is expected to decrease, but remain relatively stable ranging from 270.4 106 m3/d (9.6 Bcf/d) and 277.1 106 m3/d (9.8 Bcf/d) in 2029.

In response to low liquids prices, production of marketable gas from the Foothills Front region and gas from oil wells are forecast to decrease by 1 per cent and 9 per cent, respectively, between 2019 and 2020 accounting for nearly half of the decrease in total marketable production. Liquids-rich areas are expected to remain the main focus of activity as operators continue to use horizontal multistage drilling completion techniques to increase well productivity. Producers are expected to continue to focus development in these areas throughout the forecast as they target higher value products to offset higher capital costs.

Total production of marketable natural gas is projected to increase from 2022 to 2024 and gradually decline by the end of the forecast period as production from new wells does not offset the declines in existing production. The production increase during this time is expected to be supported by higher consumption and greater market access.

The retirement of coal power plants and the transition to coal-to-gas conversions is forecast to increase natural gas demand for electricity generation for the remainder of the forecast. Demand for diluent from the oil sands sector is also anticipated to continue to increase over the forecast period, along with demand for natural gas and natural gas liquids due to the Government of Alberta's Petrochemicals Diversification Program. The increased natural gas demand is projected to raise the AECO-C price benchmark, leading to additional well activity and stable production for the remainder of the forecast.

Oil Sands Gas Production and Use

Process gas is gas produced from bitumen upgrading. Produced gas is raw natural gas from bitumen wells. Both process gas and produced gas are typically used by oil sands projects as fuel and feedstock to create electricity and steam for on-site operations. However, increasing volumes of natural gas are being sent to processing facilities for the removal of liquids. Producers are also able to purchase gas from external sources for use in operations, which is categorized as purchased gas.

Oil sands operators use gas (produced, purchased, and process) in both thermal in situ production and mining to heat and separate the bitumen from the sand, to convert bitumen to synthetic crude oil, and to produce heat and electricity in cogeneration.

Figure S5.3 shows the average daily gas production from bitumen wells and upgrading. As these volumes of gas depend on the amount of bitumen produced and processed, there is an option to toggle the outlook for gas production based on the base and low bitumen production forecasts. An explanation of these cases can also be found in the oil price forecast section.

Process Gas

In 2019

Production of process gas decreased slightly in 2019 to 16.8 106 m3/d from 17.0 106 m3/d in 2018. The overall 1 per cent decline is mostly attributed to the CNRL Horizon upgrader that underwent extended maintenance during the fall of 2019.

Forecast for 2020 to 2029

Process gas volumes are expected to increase by almost 13 per cent between 2019 and 2029, reaching 18.8 106 m3/d by the end of the forecast. The increase is related to capacity additions on upgraders planned over the forecast period.

Produced Gas

In 2019

Natural gas produced from primary and thermal bitumen wells increased to 8.0 106 m3/d in 2019, from 7.3 106 m3/d in 2018. Production ramping up at a number of large in situ projects supported the increase in produced gas volumes.

Forecast for 2020 to 2029

Produced gas is forecast to remain fairly stable in the near term increasing to 8.8 106 m3/d by 2029. Even as produced gas volumes from primary bitumen wells are projected to decrease over the forecast, several large in situ projects are expected to eventually contribute additional bitumen and natural gas production.

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

Total Oil Sands Gas Use

Gas is used in the oil sands sector for in situ recovery, mining and upgrading, and electricity generation. The gas is sourced from purchased gas, process gas from mining and upgrading operations, and produced gas from bitumen wells.

In 2019

Gas use by the oil sands sector was 100.4 106 m3/d in 2019, which is 7 per cent higher compared with 2018 because of the increase in purchased gas for mining and upgrading operations, produced gas for in situ recovery, and electricity cogeneration.

Forecast for 2020 to 2029

Oil sands gas use is expected increase from 99.7 106 m3/d to 110.5 106 m3/d in 2020 and increase to 127.7 106 m3/d by 2029, with oil sands production affecting gas production and consumption. Despite oil price challenges in 2020, production is expected to resume to normal in 2021, although some projects have been delayed under current market conditions. The increase in gas use trends over the forecast period is in alignment with the oil sands production forecast.

Purchased Gas

Table S5.2 shows the average purchased gas used for oil sands operations in 2019. This table reflects the relative energy intensity across different oil sands operations for both in situ and mining operations.

SAGD facilities generally use a consistent amount of energy following preproduction phases, where more natural gas is burned early on to heat the ground with steam and get the reservoir ready for production. Gas-use intensities at SAGD projects typically level off once pads begin producing bitumen, subject to geological and other constraints. As a result, the amount of gas used per barrel of bitumen produced in SAGD schemes in 2019 were similar to those for 2018.

Unlike SAGD projects with consistent steam injections, cyclic steam stimulation (CSS) schemes alternate between injection and waiting a period of time to produce—sometimes over several months. As CSS projects have irregular injection patterns, gas-use intensities and production can vary vastly from year to year. Additionally, the limited number of CSS projects and production relative to SAGD means that any changes to CSS activities (alternating pattern between steaming and production phases) will result in a higher variable average gas-use rate.

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