Innovative Unconventional~2 EOR-A LightEOR an Unconventional Tertiary Recovery Approach to an Unconventional Bakken Reservoir in Southeast Saskatchewan

摘要

In 2011, Lightstream Resources initiated a tertiary dry-gas injection enhanced oil recovery (EOR) pilot scheme in the Bakken Formation of southeast Saskatchewan, Canada. The upper Devonian-lower Mississippian Bakken Formation is an extensive dolomitic siltstone unit containing a significant accumulation of oil reserves. The formation is found in the Williston Basin of North America which straddles the border between Canada and the United States. At a subsea depth of 3,020 feet (5,050 ft in true vertical depth), this tight-oil reservoir has a porosity of 9% to 12%, permeability less than one rnD and 42 degree API oil. Primary recovery in the Bakken, due to the nature of the reservoir, is low. This necessitates the use of EOR to lower declines, increase oil recovery and extend the economic life of the field. During the project evaluation stage, Lightstream reviewed the technical and economic merits of water, carbon dioxide and natural gas flooding as secondary and tertiary recovery methods. Processed solution gas was determined to be the most effective injectant because the high compressibility and low viscosity characteristics provide greater access to the formation and replace voidage in a tight-oil reservoir. Lightstream started its initial gas injection pilot project in the Viewfield Bakken Field due to its close proximity to the dry-gas source. The pilot project covers 1,280 acres and is developed on a combination of 80 acre and 160 acre spacing. It was designed with a one mile horizontal injection well supporting nine existing perpendicular producing horizontal wells. Pilot project gas (primarily methane) injection rates have varied between 350 mcf/d and 1,000 mcf/d resulting in an instantaneous voidage replacement ratio between 0.7 and 1.1. To date, pilot project results have been encouraging. Oil production at the pilot project has increased from an initial rate of 135 bbl/d to a peak rate of 295 bbl/d in the 12 months following the start of injection. Current oil production has stabilized at approximately 200 bbl/d. In addition, gas injection has resulted in lower decline rates and increased oil recovery. Continuing production trends forecast significantly improved expected ultimate recovery (EUR) and strong project economics. Secondary benefits include providing long-term gas storage that could be sold in the future. The vapourizing effect of dry-gas is increasing the natural gas liquids (NGL) content in the produced gas resulting in an additional future hydrocarbon stream.