Process steps for selection of pressure data from DSTs:

1. Records containing depth of tested interval, recovery information, and recovered water were selected;

2. The tested interval was constrained to less than or equal to 50 m;

3. DSTs were allocated to the Leduc HSU based on the depth information of the tested interval;

4. DSTs from intervals straddling the top or bottom of the Leduc HSU were excluded, unless they were from wells in data-poor areas and it was verified that less than 30% of the tested interval extended into the formation directly above or below the HSU, but not into any other formation. In addition, DSTs that straddled the contact with the Ireton Formation in areas of Leduc reef buildups were used.

5. DST pressure values were considered potentially valid if there was evidence of a mechanically sound test (no misruns), pressures had stabilized or were close to stabilization (tests must have Pmax), and flow and shut-in times were reported.

DSTs were individually examined to remove any remaining non-representative fluid pressures. Outliers were more thoroughly examined manually during the mapping process based on the following conditions:

1) Final shut-in and final flow times less than 30 minutes

2) Final shut-in time less than the final flow time

3) Difference between final and initial shut-in pressures was more than 25% (may be indicative of supercharging)

4) Substantial gas flow or significant oil recovery

Pressure data were converted to equivalent freshwater hydraulic heads using the relationship: Hydraulic Head= Completion Mid Point Elevation + Pressure / ρg, where ρ = fluid density (1000 kg/m3 for freshwater), g = gravitational acceleration (9.81 m/s2), pressure is measured in kPa (kg/ms2), and hydraulic head and mid point elevation are measured in metres above sea level (masl).

DSTs were also analyzed to determine if nearby production or injection had influenced the pressures. To identify these influences, the CII methodology from Singh et al. (2017) was used with production and injection data from the Leduc and adjacent formations. At the regional scale, production and injection influences were not noted. More information on the CII methodology can be found in:

Singh, A., Palombi, D., Nakevska, N., Jensen, G. and Rostron, B. (2017): An efficient approach for characterizing basin-scale hydrodynamics; Marine and Petroleum Geology, v. 84, p. 332-340, http://dx.doi.org/10.1016/j.marpetgeo.2017.02.015.

This dataset includes only those wells that were used in the production of the final potentiometric surface.

Details about the screening process can be found in the following reference: Jensen, G.K.S., Rostron, B., Palombi, D., and Melnik, A. (2013): Saskatchewan Phanerozoic Fluids and Petroleum Systems project: hydrogeological mapping framework; in Summary of Investigations 2013, Volume 1, Saskatchewan Geological Survey, Saskatchewan Ministry of the Economy, Misc. Rep. 2013-4.1, Paper A5, 10 p. URL http://publications.gov.sk.ca/details.cfm?p=80100 [October 2014].