Comparing geology and well completions to production in the Unconventional region of the Cardium Formation (Upper Cretaceous), northwest Pembina field, Alberta, Canada

Abstract

Drilling of horizontal wells in the Cardium Formation in the Pembina field has abruptly increased since the successful completion of Bonterra Nexstar 4-25-47-03 W5 (surface-hole location) 1-25-47-03 W5 (bottom-hole location) in 2008. New Cardium Formation wells are targeting thinner lower quality reservoir intervals while implementing a variety of new completion techniques to improve hydrocarbon production. The purpose of this study is to compare reservoir quality, net-pay mapping, and completion techniques to production data to evaluate the successes and failures of geologic characterization and completion strategies. Well logs and routine core-analyses data were used to evaluate reservoir properties and map net-pay thicknesses. Subsequently, production data from 125 horizontal wells were compared based on the following criteria: presence of conglomerate, sandstone density porosity net-pay thickness, wellbore orientation, number of fractured stages, fracture spacing, lateral well length, base fracturing fluid, and average metric tons of proppant per stage. In the unconventional parts of the Pembina field, well-production–based evaluation of net-pay maps and reservoir characterization requires completion techniques to be considered. Conversely, reservoir thickness and quality must be considered to accurately assess the success of different completion techniques. The use of a 6% sandstone density porosity net-pay cutoff can only be shown to be effective in identifying the most productive wells if well completions are considered. Our analyses indicate that wellbore orientation has a limited impact on well performance, whereas decreasing fracture spacings and increasing lateral well length have the most significant impact on well performance.