Evaluation of the Oil Recovery and Economic Benefit of the First-Ever Polymer Flood Field Pilot to Enhance the Recovery of Heavy Oils on Alaska's North Slope using Machine-Assisted Reservoir Simulation

The first-ever polymer flood field pilot to enhance the recovery of heavy oils on the Alaska North Slope is ongoing. This study seeks to evaluate the oil recovery and economic performance of the project via machine-assisted reservoir simulation. First, a reservoir simulation model is calibrated to the production data through the introduction and modification of transmissibility contrasts. Machine-assisted history matching techniques are crucial to the success of this procedure. To replicate the early water breakthrough observed during waterflooding, transmissibility contrasts are emplaced in the reservoir model to force the viscous fingering behavior expected when water is used to displace this 330 cp heavy oil. After injection is switched to tertiary polymer flooding, the transmissibility contrasts are reduced to replicate the significant decrease in the producing water cut. This behavior indicates the dampening of viscous fingering effects, which is expected from the switch to a less mobile injected fluid. Later, transmissibility contrasts are reinstated in the simulation model to recreate a producing water cut surge. This surge indicates a decrease in the injection conformance, likely from the overextension of fractures developed at the injecting wells. Next, oil recovery forecasts are produced using calibrated simulation models from each stage of the history matching process. These production forecasts are then input into an economic model, incremental to waterflooding expectations. The decision to pursue incremental economic analysis is fit-for-purpose, allowing for a focused evaluation of the decision to switch from waterflooding to polymer flooding whilst canceling out a number of impertinent and uncertain cash flows. In all cases, the forecasts demonstrate that the polymer flood will produce a much greater heavy oil recovery than waterflooding, yielding attractive project economics even under conservative oil price and polymer cost assumptions. Thus, we conclude this polymer flood field pilot is both technically and economically successful. However, significant variations in recovery and economics between the simulation scenarios indicate that a simulation model only remains valid for prediction if the flow structure in the reservoir remains consistent with its historic behavior. Thus, a simulation model calibrated for waterflooding may not capture the full technical and economic benefit of polymer flooding or other enhanced oil recovery processes. Furthermore, the overextension of fractures from injecting wells reduces the expected performance of the polymer flood, perhaps necessitating future conformance treatments.