The mid-point of the sampled tested interval is a calculated value and its accuracy is dependent on the accuracy of the measured depths and elevations provided from the well header. For oil and gas wells, the well elevations and locations are surveyed, so accuracy will be to the same significant digits provided by the source, even though there may be considerable uncertainty as to the exact depth of the pressure measurement.

The location of the DST intervals in oil and gas wells may be accurate to within millimetres in accordance with surveying standards at the time of drilling.

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 Swan Hills / Slave Point HSU based on the depth information of the tested interval;

4. DSTs from intervals straddling the top or bottom of the Swan Hills / Slave Point 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.

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 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 (m asl).

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 Swan Hills / Slave Point and adjacent formations. More information on the CII methodology can be found in Singh et al. (2017):

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 final potentiometric surfaces. 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, Sask. 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].