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Updated May 2022

 

The AER has limited its geological evaluation to bitumen resources of the Wabiskaw-McMurray Formations within the Athabasca Oil Sands Area (Figure R2.4). The reserves estimate include only those portions of the resource that are technically recoverable using steam-assisted gravity drainage (SAGD) as an enhanced oil recovery technology from the McMurray Formation. These estimates do not consider the economics of any project. The assessment includes data as of Aug 1, 2019.

Alberta oil sands areas

The current methodology involves applying appropriate cutoffs to reservoir properties so that non-reservoir intervals are not included in the net pay thickness. Reserves estimates are derived volumetrically using stochastic methods to capture the uncertainty of cutoffs used to determine net pay and to estimate bitumen reserves and resources.

Historically, the AER estimated reserves for the Wabiskaw-McMurray combined formations. The approach used a volumetric calculation that did not discriminate between the non-reservoir and reservoir intervals.

Figure R2.7 is a schematic chart that shows the resulting difference in net pay between the historical and current methods. The historical reserves estimate for the Wabiskaw-McMurray Formations used a 1.5 m continuous net pay thickness cutoff. The current reserves estimate for the McMurray SAGD potential uses 7 metres (m) as a continuous net pay thickness cutoff, considering 5 m between the injector well and producer well.

Difference in pay consideration for initial volume in place

The stochastic method uses variable cutoffs for the mass bitumen fraction to capture the uncertainty in reservoir thickness. Net pay probability was calculated for the Wabiskaw-McMurray, McMurray SAGD potential, and McMurray SAGD targeted.  In addition, each SAGD project was assessed separately because the rock quality varies between projects. The mass bitumen fraction cutoffs were varied between 6.5% and 10%, resulting in low, medium, and high case estimates of net pay probability at each location.

Cases are compared to operator-submitted values and a base case net pay probability is used to quantify the associated low, medium and high estimates for porosity, oil saturation, and net pay over the reservoir interval. These are used as input values to define the distribution shape (range/standard deviation, and frequency), which constrains random values for each data type during the simulation.

Randomly simulated net pay, effective porosity, and oil saturation values are used to output simulated oil column results.

Thus, the stochastic OBIPs are calculated by modeling the simulated oil column results from each well, to account reservoir heterogeneities, assess areal uncertainty, and report the OBIP by ranges as low, medium and high estimates.

Figures R2.8 and R2.9 show the Regional net pay maps for Wabsikaw-McMurray oil sands deposit and the McMurray oil sands deposit with 7 metre continuous cutoff.

Net pay map of the Wabiskaw McMurray oil sands deposit with a 1.5 m continuous pay cutoff
Net pay map of the targeted McMurray oil sands deposit with 7m continuous cutoff

Table R2.6 shows the low, medium and high values for the OBIP, as well as the average reservoir properties for the deposit intervals: Wabiskaw-McMurray, McMurray SAGD potential, and McMurray SAGD targeted.

Athabasca oil sands area in-place volumes and reservoir properties

Estimates of ultimate recovery factors used for the volumetric evaluation are based on information provided by operators in their applications or Directive 054 submissions.

Initial established reserves were calculated using a distribution of ultimate recovery factors, ranging from 38% to 74%, for all existing SAGD projects producing from the McMurray formation in the Athabasca Oil Sands Area. This distribution for the recovery factors was then multiplied by the distribution of OBIP to get low, medium, and high estimates of the initial established reserves.

This approach ensures that the range of uncertainty in the recovery between the different projects is captured, allowing for a consistent evaluation across the entire Athabasca Oil Sands Area.

Table R2.7 shows the low, medium, and high estimates for recoverable bitumen reserves in the Athabasca Oil Sands Area for the McMurray Formation with SAGD potential.

Athabasca oil sands area McMurray SAGD targeted reserves and ultimate potential

This estimate combines traditional reserves and resource values in accordance with the AER criteria.

Volumes used for estimating Initial Established reserves is as follows:

  • Volumes from Drainage areas with wells that are Drilled and Completed
  • Volumes from Drainage areas with wells that are On Production
  • Volumes from Drainage areas with wells that are Suspended
  • Volumes from Areas the Operator plans to drill within 5 years or, currently under development
  • Locations within the approved project area that meet well delineation criteria

In order to be included as Initial Established reserves, a minimum net pay cut off of 7 m continuous pau must be met. There must also be a well delineation density of at least 8 wells per section with if 3-D seismic was acquired, or 16 wells per sections without 3-D seismic.

Volumes used for calculating Ultimate Potential also include:

  • Locations inside the project areas that do not meet well delineation density described above, but meet the 7m minimum net pay cut off
  • Remaining locations outside the project areas within the Athabasca oil sands area that meet the minimum net pay cut off of 7m