Updated March 2018
Raw natural gas consists mostly of methane and other hydrocarbon gases, but it also contains nonhydrocarbons, such as nitrogen, carbon dioxide, and hydrogen sulphide (H2S). These impurities typically make up less than 10 per cent of raw natural gas. The estimated average composition of the hydrocarbon component without impurities is about 92 per cent methane, 5 per cent ethane, and lesser amounts of propane, butanes, and pentanes plus.
This section discusses both conventional and unconventional natural gas, with unconventional gas including coalbed methane (CBM), shale, and tight gas. CBM is methane found in coal, both as adsorbed gas and free gas. Shale gas is natural gas locked in fine-grained, organic-rich rock. Tight gas refers to natural gas found in low-permeability rock, including sandstone, siltstone, and carbonates. It is often difficult or impossible to separate the tight portion of the reserves or production of a conventional reservoir. Therefore, unconventional tight gas volumes are included within the AER’s conventional natural gas reserves and production reporting.
The AER uses natural gas production volumes submitted by industry to Petrinex. Petrinex is a secure, centralized information network used to exchange petroleum-related information.
All values for 2017 have been estimated using data reported by industry up until the end of August 2017. Full-year estimates for 2017 were derived using these data, adjusting for seasonality. Where this adjustment was not applied, such as for permitted volumes for removals, the last full year of complete data was used.
The AER defines supply cost as the minimum constant dollar price required to recover all capital expenditures, operating costs, royalties, and taxes, as well as to earn a specified return on investment. The supply cost estimate determines a dollar value required per unit of production.
The supply cost estimate for an average horizontal or vertical/directional well in each Petroleum Services Association of Canada (PSAC) area includes the following data: initial productivities, production decline rates, vertical drilled depths and total measured depths of the wells, gas composition, shrinkage, capital costs, operating costs, royalties and taxes, and a 10 per cent nominal rate of return. The supply costs estimates are not risked (i.e., assumes a 100 per cent success rate). Supply costs are estimated as plant-gate costs, which are reported in Canadian dollars (Cdn$). The representative wells in PSAC Areas 1, 2, 5, and 7, along with shale wells, are assumed to produce wet gas.
Marketable Natural Gas
Marketable gas is the gas that remains after the raw gas is processed to remove nonhydrocarbons and heavier natural gas liquids and that meets specifications for use as a fuel. Natural gas volumes are referred to as either the actual metered volume with the combined heating value of the hydrocarbon components present in the gas (i.e., “as is” gas) or the volume at standard conditions of 37.4 megajoules per cubic metre (MJ/m3). The average heat content of produced conventional natural gas leaving field plants is estimated to be 39.2 MJ/m3. This compares with a heat content of about 37.0 MJ/m3 for CBM.
Marketable natural gas production volumes for conventional gas are calculated based on production data from the ST3: Alberta Energy Resource Industries Monthly Statistics section on supply and disposition of marketable gas, as shown in Table S5.4 [HTML]. Gas production from CBM and shale gas wells is determined separately. As shale and CBM producing wells are re-evaluated based on new information, historical annual values can change. Removals are equal to the difference between Alberta production and Alberta demand.
In projecting marketable natural gas production, the AER considers three components: expected production from existing producing gas wells, expected production from new gas wells placed on production, and gas production from oil wells. The AER’s estimates of remaining established and yet-to-be established reserves of natural gas in the province are also taken into account. Conventional gas production from oil and gas wells are forecast separately from production from shale and CBM wells, and the projections are then combined to show anticipated total gas production in Alberta. Continual reclassification of CBM and shale wells placed on production results in revisions to historical data and, therefore, changes to annual forecasts.
Table S5.5 [HTML] shows the historical three-year average initial productivity for conventional gas wells, by PSAC area, and for shale and CBM wells. These numbers form the basis of the average well productivity used to forecast production.
Data from existing wells (Table S5.6 [HTML]), the number of new wells forecast to be placed on production (Table S5.7 [HTML]), the average initial productivity for the wells (Table S5.8 [HTML]), and the associated decline rates (Table S5.9 [HTML]) are the main determining factors used in projecting natural gas production volumes over the forecast period. In addition, prices, royalties, taxes, capital costs, and other costs are considered. This year’s forecast has been calculated using the Modernized Royalty Framework adopted in 2016. The supply model calculates a net present value for representative wells for all years within the forecast period, with the calculated net present value forming the basis of the forecast. The forecast considers limiting factors such as current and future capital market conditions and remaining reserves.
Decline rates for gas production from existing conventional gas wells vary depending on factors such as the age, type, and geological locations of the wells.