During the past two decades, the booking of unconventional hydrocarbon reserves has hiked, thereby rising significantly above published conventional hydrocarbon reserves. Unconventional hydrocarbon resources became economically viable in the 1990s after horizontal well designs achieved commercial application in the late 1980s (King, 1993). This milestone was preceded by the development of steam-assisted gravity drainage (SAGD). The objective of this paper is to conduct an in-depth review of thermal Enhanced Oil Recovery (EOR) projects, in addition to presenting a prediction model for steam EOR and a review of heavy oil well injection/production patterns. An initial screening criterion is presented for steam EOR reservoir candidate selection, which is based on 15 categories of dataset distribution taken from 274 projects. Correlations also are provided for steam EOR project variables that significantly influence oil recovery, namely, the number of injection wells. A deterministic steam EOR prediction model has been generated to guide area development versus well patterns and targeted oil production rates. Reducing the number of horizontal (injection/production) well pairs decreases oil production significantly. However, reducing the perforation length of both the injection and the production wells does not significantly decrease oil production rates. Changing the injection well design from a horizontal to a vertical orientation notably decreases oil production rates. Neither increasing the number of injection wells or the injection and production tubing size significantly increases oil production. Perforation length and tubing size influence the voidage replacement ratio and therefore should be considered during the various stages of heavy oil field development. Horizontal injection well designs are suited to rehabilitate the voidage replacement ratio (VRR) in depleted fields. The results also indicate that the temperature gradient increases with fewer horizontal injection wells (Case 1 versus Case 2), as well as when the horizontal injection well perforation section is reduced (Case 2 versus Case 3) and when a horizontal injection well design is substituted with a vertical injection well design (Case 6).Case 6 involves the most vertical injection wells and largest tubing size diameter.

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