The Cretaceous age Glauconitic sandstone formation is present across a large area of Central Alberta, Canada. The majority of the play involves multi-stage horizontal wells for tight gas exploitation. This case study focuses on channel sand Glauconitic oil pools. These semi-conventional pools were initially exploited with hydraulically fractured vertical wells. The implementation of multi-stage fractured horizontal wells has breathed new life into the play, with much higher production rates, recoveries and better economics.
The historical fracturing technique used in the Glauconitic consisted of a gelled hydrocarbon fluid system, due to known reservoir fluid sensitivities to water. The operator had completed a number of multi-stage horizontal wells using this fracture fluid system, and was uncertain if this was the optimum fracture design or fluid system.
Production analysis of the existing multi-stage horizontal wells was used to determine how effective the fractures were, as well as drainage areas and estimated ultimate recoveries, etc. The study concluded the gelled hydrocarbon fracture design was not optimal in terms of effective fracture half lengths, or net present value (NPV).
A new fracture design was proposed, involving the use of foamed, solids free, viscoelastic surfactant water based fracture fluids, much larger fracture sizes and higher conductivities. This new design was implemented on approximately seven multi-stage fractured horizontal wells (MFHW) during 2013.
The new design approach has increased well productivities and enhanced the economics significantly compared to the old design. Other benefits include: much better capital efficiency, better cleanup, accelerated positive cash flow, reduced safety issues and reduced sand flow-back problems. The paper will discuss the initial phase of the optimization process, the early production results, enhanced economics and net present value.