Updated March 2018
Table 1.6 [HTML] summarizes the estimated costs for conventional, shale, and coalbed methane (CBM) natural gas wells from specific areas in Alberta based on 2017 estimated costs and production profiles. The supply costs are based on representative wells in each Petroleum Services Association of Canada (PSAC) area. Supply costs for different geological plays and PSAC areas vary significantly because of differing production rates, well types, drilling and operating costs, royalties, and other factors. Therefore, the results may not reflect wells that differ from the representative well profiles used in the analysis.
The table shows that the supply costs vary considerably depending on the area and the type of well used, illustrating the importance of having sufficient understanding of the underlying geology to use the most effective and cost-efficient completion technology. The table also shows that wells that target wet gas (the horizontal wells in PSAC Areas 2, 5, and 7) typically have lower supply costs because the liquids add value, which helps offset the costs of the well. Wells with longer total measured depths, typically horizontal wells, tend to have higher initial productivity but also higher capital costs. However, since the higher initial productivity is typically able to offset the higher capital costs, these wells tend to have lower supply costs. With the exception of horizontal wells in the Duvernay and Mannville Formations and vertical wells in PSAC Areas 3 and 4, supply costs went down in 2017 relative to 2016 because higher initial productivity offset increases in capital costs across all areas. The improvement in initial productivity resulted from drilling that targeted only the most productive areas in the formations due to the current low-price environment.
The analysis also includes a separate set of supply costs for certain PSAC areas to reflect the industry practice of drilling more than one well or lateral leg from a well pad, commonly referred to as a multiwell pad or multilateral well. Operators of these wells are able to take advantage of economies of scale and typically incur lower capital costs, resulting in a lower cost per unit of output. As shown in Table 1.6 [HTML], supply costs are lowest for horizontal wells in PSAC Areas 2 and 7.
The AER has not considered recompletions in the analysis, which are substantially cheaper than new drills but have weaker initial productivity.