This data release contains hydraulic head data used to create a hydraulic head map of the Keg River / Winnipegosis hydrostratigraphic unit (HSU). The data were acquired from publicly available pressure data from drillstem tests from oil and gas wells, and industry monitoring wells accessed through environmental impact assessments reports and the Alberta Water Well Information Database.
Data have been processed, relevant records selected, and outliers removed to compile this dataset.
All attributes for the well data are as received from the data source.
Any error in elevation may influence the allocation of the well into the modelled HSU as well as the hydraulic head values, as the land surface elevation was used to calculate the mid-screen elevation and corresponding hydraulic head from measured “depth to” values.
Static water level data from the AWWID and drillstem test data from oil and gas wells used in this dataset have been collected over decades, by different parties, and using different methods.
There may be more than one record for a Source_ID if the well was sampled more than once. This will be reflected in the Source_ID being duplicated. Geographic coordinates (latitude/longitude) may be the same for different wells, because wells could have been recompleted and the HSU resampled.
The location of oil and gas wells may be accurate to within millimetres in accordance with surveying standards at the time of drilling.
A majority of the AWWID wells are located to the middle of the Alberta Township System quarter section (occasionally to the middle of the section). Therefore, there can be up to approximately 566 m (or up to approximately 1131 m if the well is located in the middle of a section) of error in the well location and subsequent maps derived from the well records. These sources of error are not unique to this study and are encountered in any hydrogeological study that uses the AWWID, unless further refinement of well locations is undertaken.
The locations of the oil and gas wells may be accurate to within millimetres depending on surveying standards at the time of drilling.
The mid-point of the 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.
The potential for up to approximately 566 m (sometimes approximately 1131 m) of horizontal accuracy error may for the location of water wells in the AWWID also introduce errors in the surface elevation, which is derived from the provincial 25 m DEM, based on the location of the well. This error is likely on the order of plus/minus 5 m but may be 10s of metres in areas where there are large changes in elevation. Additionally, most wells have a casing which sticks up above the land surface from which measurements of water level are usually recorded. The calculation of hydraulic head does not take into account the elevation difference between the top of the casing and the land surface because this number is not always recorded in the AWWID. These sources of error are not unique to this study and are encountered in any hydrogeological study that uses the AWWID, unless further refinement of well locations is undertaken.
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 Keg River / Winnipegosis HSU based on the depth information of the tested interval;
4. DSTs from intervals straddling the top or bottom of the Keg River / Winnipegosis 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 manually removed 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 (masl) = (Pressure (kpa)/ρg) + Elevation (masl), where ρ = fluid density (1000 kg/m3 for freshwater) and g = gravitational acceleration (9.81m2/s) and masl = metres above sea level.
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.
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 references: 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].
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.