Duvernay Reserves and Resources Report

Alberta Energy Regulator
When condensate was not reported separately from the gas stream, this methodology could not be used
to predict CGR cum values at abandonment. Caution should be exercised when applying this method to
publicly reported data. Several instances exist where gas and condensate may have initially been reported
as separate streams until a move at some point in the well’s history to combined stream reporting. In these
cases, linear trends in CGR cum that result from the lack of condensate reporting should be ignored in the
analysis. Condensate dropout in the reservoir, or in the wellbore if the gas velocity is not sufficient to
carry the liquid to surface, will also result in a drop in the CGR cum trend. An example illustrating a drop in
the established CGR cum trend is shown for well 00/06-11-063-20W5/0 in Figure 16.
The distribution of CGR cum values derived using this methodology was mapped spatially across the
Kaybob assessment area as shown in Figure 17. The area was subdivided into CGR regions based on
the CGR cum at abandonment (30 year) values. CGR cum abandonment intervals of 50 bbl/MMcf were used
to subdivide the regions. The total population of wells was then grouped based on which region they
are located. Each well group was then assigned a final CGR cum value equal to one-third of the specified
CGR cum range rounded to the nearest integer. For example, wells in the 100–150 bbl/MMcf region
were assigned a final CGR cum value of 117 bbl/MMcf. The final CGR cum value for each group was then
multiplied by the gas EUR for each respective well within the group to estimate a final condensate EUR.
Applying the one-third methodology described above generally gave reasonable results. Wells with
unreasonable results were identified and re-evaluated independently.
There were 146 wells identified within the potential retrograde condensate and volatile oil regions. Wells
with CGR cum values of less than 50 bbl/MMcf were assumed to be primarily natural gas wells. Figure 17
is strictly based on the production data that has been submitted to the AER. Due to issues associated with
field condensate being reported as a recombined gas stream, there is some variation between Figure 17
and the expected fluid regions as shown in Figure 5. However, both figures may be refined in the future as
new information becomes available.
5.1.3 Oil Reserves
The deterministic workflow described in Section 5.1 was applied to any oil wells with sufficient
production data to determine oil EUR. Very few oil wells could be reliably forecasted using this
methodology. Due to the limited sample size and insufficient production history, a Monte Carlo simulation
could not be applied to the oil wells. As such, oil EURs were assigned to the remaining oil producers
using the deterministically evaluated wells as approximate analogues. A list of oil wells and associated
EURs is provided in Appendix 4.
5.2 Developed Nonproducing Reserves
Developed nonproducing reserves are those reserves that either have not been on production or have
previously been on production but are shut in, and the date of resumption is unknown (SPEE, 2007).
Duvernay Reserves and Resources Report (December 2016) 21