In recent years, the tight Cardium sandstones of west central Alberta have observed significant new development with the application of multistage-fractured horizontal wells (MFHWs). This case study reviews the completion costs, economics, and production performance of 148 horizontal oil wells completed in the Pembina field halo areas (west and east), central Pembina, Willesden Green, and Garrington fields. Production analysis was performed on all wells using the Duong decline-curve-analysis technique. This technique has been used successfully on tight multistage-fractured wells in other areas, and has proved successful at predicting long-term well performance and recoveries. Wells were chosen for comparison that were in the same geological and pressure regions, had a minimum of 2 years of production information, and were stimulated with various fracture-fluid systems. In one of the analyzed areas, a definite trend was identified; it was found that wells drilled in a certain orientation performed better than wells drilled with other orientations. Completions and hydraulic-fracturing costs were gathered from public sources in order to understand the cost differences between areas and types of fracture-fluid systems. Using decline curves and cost information, full-cycle economics were run on the "average" well for each area in order to determine the net present value (NPV) of each area. This case study shows there is value in optimizing fracture designs through look-back studies, and there is a need to focus on more-effective fracture-treatment designs in unconventional oil development. The overall results of the study showed: (1) the choice of fracture-fluid system is a key component in optimizing economics in the Cardium halo areas; and (2) the optimum fluid system varies in different areas of the Cardium.