This is the first in a series of papers detailing the development of an 800-foot thick Potter sand oil column on the northwestern boundary of the Midway-Sunset oilfield in west-central section 21N, T31S, R22E. Tools used to develop the depletion strategy for this property include analogy and thermal numerical simulation. This viscous 11° API crude is currently producing 1500 bopd under cyclic steam support. This area will be re-developed as a steam flood over the entire 81 acres. Besides the viscous nature of the crude and the massive volume of reservoir that must be heated, another technical challenge is the presence of low pressure vadose or air sands immediately above the oil column. These air sands will act as a thief zone to the injected steam and will make heating this massive oil column more difficult. These challenges posed the following question: How does one effectively heat an 800-foot thick oil column without having the steam preferentially rise to the top of the column and into the low pressure air sands?

To adequately develop guidelines for steam injection rates and placement, a numerical simulation model with sufficient gridblock and compositional resolution was used to accurately simulate the countercurrent flow of steam and oil as the steam rises to the top of the reservoir. A two dimensional mechanistic model with very fine gridblocks was used to isolate this mechanism. Gridblock dimensions were calculated using a characteristic length, and the steam assisted gravity drainage (SAGD) process was used to estimate the rate of rise of the vertical steam chest. The oil was characterized by a 5-component system that was fully compositional and could simulate the complex phase behavior associated with the oil and steam rising into the air sands. The techniques used in the study resulted in a numerical model with sufficient resolution to provide guidelines for steam injection rates and for steam placement within the 800-foot thick oil column.

This project is under active development with over 130 wells drilled and completed in 1998. Future papers will detail the producer/injection well completion strategies and the steps used to optimize the recovery process.

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