The Tuktu Advantage

Conventional versus unconventional

The Deep Basin in the past has been a focus of large conventional reservoirs, such as the Cardium and deeper Devonian reefs, which provided Alberta with some of the largest onshore oil and gas pools in North America (e.g., Turner Valley in 2014, Leduc #1 in 1947, Pembina in 1953). Since these early days, operators have uncovered many other conventional reservoirs; however, pool size has decreased through time.  With the onset of multistage fracture stimulation in western Canada in about 2011, operators were able to exploit very low permeability reservoirs, thus extending the production capability of the basin which has more than offset the declining conventional reservoir production.  As the technology progressed, operators have become very efficient at such drilling and completion strategies; however, now, the technology is widespread, and it seems that one operator cannot be held above another by their knowledge and unique skill set. Success in a particular play is measured by the underlying geology, appropriate mix of producing liquids yield and gas volumes, and project scalability such that initial high production declines can be offset with continued drilling. Moreover, all of this must come with the lowest possible production costs.  

Oil and gas development is now in the super mature phase within the Western Canada Sedimentary basin (WCSB, Figure 1), because few, if any, significant conventional reservoirs have been discovered in western Canada within approximately the last 5 years. Operators, instead, have focused on unconventional plays (e.g., Montney, Duvernay, Wilrich). These plays are very costly to exploit; they require a significant initial capital investment and a large contiguous land base. Establishing a new corporate position in these plays is also highly competitive, in part, because the level of technical knowledge to drill and complete these wells is widespread, which drives stiff competition.  Recently, certain operators are paying record amounts  for such land: in May 15, 2024, an undisclosed operator paid an unprecedented, nearly $6 million for a single section of land, likely for a Montney drilling project. 

Figure S5. Regional statistics of the Cardium formation horizontal well development compared to the Stolberg Example. Local variability with each of the fields is related to reservoir quality and not to stimulation process. The high numbers for the foothills is related to the enhanced permeability due to tectonic deformation which results in natural fracturing of otherwise low permeability reservoirs.

Unconventional plays require a significant drilling inventory due to very high initial production declines. Other issues to contend with are the high volumes of frac-fluids which are required to carry proppant into the reservoir. Together with drilling costs, total well costs could be above $12 million/well. Fortunately, the “c*”, which is a royalty credit given to certain wells based on depth and stimulation style, renders these wells economic, despite high costs and very high initial decline rates. There is also an environmental issue relating to the volume of water required to place large proppant volumes, and in some cases, nearly 1 million barrels of water is required for certain Duvernay Formation stimulation programs.  

The Tuktu team’s approach is unique amongst the many current producers that focus on unconventional operations. Tuktu has the experience and skill necessary to exploit complex, highly fractured foothills or deep basin reservoirs that have, in the past, yielded some of the most prolific wells in the basin.

Figure S6. Regional statistics of the Wilrich and Mannville in the foothills and deep basin. Statistical data is based GeoScout information.