Natural Gas Production


Natural Gas Production


Updated March 2018

Figure S5.1

  • In 2017, production of natural gas increased by an estimated 1 per cent year over year, as shown in Figure S5.1 [Tableau].
  • Production from the Montney and Upper Mannville Formations continued to grow, accounting for 45 per cent of Alberta’s raw natural gas production in 2017, up from 42 per cent in 2016.
  • Production from the Montney and Upper Mannville Formations increased by 5 and 12 per cent, respectively. These increases are in line with results of the supply cost analysis that show that the Upper Mannville Formation is competitive with the Montney Formation.
  • Production gains in Petroleum Services Association of Canada (PSAC) Area 2 were largely associated with new wells placed on production using horizontal multistage fracturing, illustrating the productivity of these wells.
  • In the near term, production from PSAC Areas 2 and 7 (containing both the Montney and Upper Mannville Formations) and from shale (Duvernay Formation) is forecast to continue to grow, contributing about 70 per cent of total Alberta natural gas production by 2027, up from an estimated 62 per cent in 2017. Growth in natural gas demand in the oil sands sector and in the electricity generation sector is projected to result in declining removals throughout the forecast period.
  • The AECO-C natural gas price increased by an estimated 9.8 per cent in 2017 compared with 2016 and is expected to increase for the remainder of the forecast period. The AECO-C price hit an all-time low of Can$-0.55 per gigajoule (GJ) in September and remained low, periodically dipping into negative territory, due to outages along the TransCanada Mainline, as discussed in the Commodity Prices section. After October, prices reflected more seasonal trends. The AECO-C natural gas price is estimated to increase over the forecast period as a result of increasing oil sands demand, a shift from coal- to gas-fired electricity generation, and anticipated pipeline expansions.

Table S5.1

Figure S5.2

In 2017, natural gas from conventional gas and oil wells placed on production represented an estimated 91.6 per cent of total production, with the remainder coming from coalbed methane (CBM) and shale gas wells. CBM production continued to decline in 2017, falling an estimated 4.5 per cent, while production from shale continued to grow, increasing by 0.5 million cubic metres per day (106 m3/d) or 6.4 per cent. Gas production from conventional oil wells declined by 2.7 per cent as a result of declining oil production. Sour natural gas represented 19 per cent of total gas production in 2015, the last year for which sour gas data are available. This percentage has been relatively stable since 2012 at around 19 per cent, following a decline from 31 per cent of production in 2000.

There were under 117 000 producing gas wells in 2017, down from 120 000 in 2016, as shown in Figure S5.2 [Tableau]. This downward trend began in 2010 as producers began focusing on drilling fewer, more productive wells.

Figure S5.3

As shown in Figure S5.1 [Tableau], with the exception of production from PSAC Areas 2 and 7, and from shale, production in all areas of the province decreased in 2017. The increase in production from PSAC Areas 2 and 7 and shale is due to higher drilling activity driven by the presence of wet gas, which makes wells in these areas more economical due to the value of the natural gas liquids, and the higher initial productivity associated with horizontal drilling and hydraulic multistage fracturing.

Consistent with the trend over the past few years, production from the wetter formations in PSAC Area 2 is forecast to account for most of the natural gas production. Total production, is forecast to remain relatively constant through to 2021 and gradually decline thereafter, reaching 255.0 106 m3/d by the end of the forecast period.

Figure S5.3 [Tableau] shows historical raw natural gas production by on production year. Production has increased in recent years despite the lower number of wells placed on production because of the higher productivity of these wells.

The forecast for total natural gas production does not include gas production from bitumen upgrading and raw natural gas from bitumen wells because this gas is typically used on site. The forecast for gas production from the oil sands can be found in the Oil Sands Gas Production and Use section.

A summary of 2017 historical and forecast initial productivities by area can be found in the Methodology section.

The Government of Alberta’s Climate Leadership Plan will affect the production forecast, creating additional demand for natural gas from power generation and abating methane emissions. The retirement of coal power plants, beginning at the end of 2019, is forecast to increase natural gas demand for electricity generation throughout the remainder of the forecast. This is anticipated to result in stronger prices, leading to additional well activity and stable but slightly decreasing production for the balance of the forecast, with marketable production reaching 255.0 106 m3/d in 2027.

Oil Sands Gas Production and Use

Figure S5.7 [Tableau] shows gas produced from bitumen upgrading—referred to as process gas—and raw natural gas from bitumen wells—referred to as produced gas. Gas from these sources is typically used as fuel in oil sands development, although increasing volumes are being sent to processing facilities for the removal of liquids. Oil sands operators use gas in both thermal in situ production and mining to separate the bitumen from the sand, to convert bitumen to synthetic crude oil, and to produce heat and electricity in cogeneration.

Process gas production is estimated to have increased in 2017 to 16.8 million cubic metres per day (106 m3/d) from 15.6 106 m3/d in 2016. This growth is attributed to new upgrading capacity coming on line from expansions and restored capacity following the Fort McMurray wildfires in 2016. Process gas volumes are expected to reach 20.2 106 m3/d by 2027, which is slightly lower than the AER’s previous forecast of 20.9 106 m3/d by 2026, largely due to Nexen’s Long Lake upgrader being removed from this year’s forecast as a result of the upgrader being placed on an indefinite hold.

Natural gas production from primary and thermal bitumen wells decreased to an estimated 5.6 106 m3/d in 2017 from 6.2 106 m3/d in 2016 due to lower primary production of bitumen and the full-year shut in of the Nexen upgrader, whose synthetic gas had been included under produced gas and was used on site at its in situ Long Lake project. Produced gas is forecast to reach 7.0 106 m3/d by 2027, which is similar to the AER’s previous forecast of 7.8 106 m3/d by 2026. Produced gas is used primarily as fuel to create steam for on-site operations.

Table S5.10

The average use rates for purchased gas in 2017 are provided in Table S5.10 [HTML]. The gas use rates for steam-assisted gravity drainage (SAGD) are similar to those for 2016, while cyclic steam stimulation (CSS) rates have increased, reflecting the alternating pattern between steaming and production.

Figure S5.1

Total gas use for the oil sands sector is shown in Figure S5.8 [Tableau], including gas used for in situ recovery, mining and upgrading, and electricity generation. Supply is sourced from purchased gas, process gas from mining and upgrading operations, and produced gas from bitumen wells. Gas use by the oil sands sector was 92.4 106 m3/d in 2017, which is 8.8 per cent higher year over year due to the increase in purchased gas for in situ recovery and electricity cogeneration. Demand is expected to increase to 128.3 106 m3/d by 2027, which is higher than the AER’s previous forecast of 125.2 106 m3/d by 2026, reflecting the forecast for increased oil sands production.