Traditionally, in-situ oil sands operators use the simple approach of placing steam-assisted gravity drainage (SAGD) well pairs as close to the base of pay as possible, with the expectation that the effects of reservoir heterogeneity will be mitigated by the use of longer well pairs. It has been proven, however, that the geometry associated with the top and base of the SAGD pay interval and the distribution of reservoir lithofacies within the pay interval have a significant impact on SAGD performance. This chapter proposes that optimal well placement and selective completion strategies can more effectively address reservoir heterogeneity issues, provided that a three-dimensional (3-D) model of the SAGD reservoir and an ultimately fuller understanding of the evolution of the steam chamber over time exist. By applying strong scientific principles and consistent SAGD strategies, top operators have demonstrated that improved reservoir performance is possible, evidenced by higher production rates, lower steam-oil ratios, and maximized recoverable reserves.

In northeastern Alberta, the McMurray Formation hosts in-situ oil sands reservoirs ideal for SAGD operations. Ideal SAGD reservoirs are commonly associated with fluvial or tidally influenced depositional environments; specifically stacked, lower point-bar deposits; and open estuarine deposits. Operators with a history of obtaining optimal production rates, lower steam-oil ratios, and recovery factors greater than 60% commonly place both the producer and injector wells in continuous, high-permeability cross-bedded sand lithofacies. Cross-bedded sands commonly exhibit darcy-scale permeabilities and favor unrestricted communication between the injector and producer wells. This allows for a more efficient startup and ultimately results in better well-pair production performance. Thin discontinuous mudstones and minor mudstone-clast breccias, if present, do not appear to significantly impede vertical steam chamber growth or associated gravity drainage of production fluids to the horizontal producer. In contrast, placing well pairs in inclined heterolithic stratification (IHS) can negatively affect operations. Inclined heterolithic stratification lithofacies contain laterally continuous mudstone interbeds, commonly characterized by a magnitude-scale reduction of vertical permeability of magnitude as compared to cross-bedded sand lithofacies.

The Underground Test Facility (UTF), where SAGD was first developed and piloted, provides an analog for understanding the effects of IHS on production. In the UTF phase B reservoir, core samples taken from observation wells along an SAGD well pair indicate that IHS mudstone beds have vertical permeabilities ranging from 0.04 to 700 md. The lateral continuity inherent to the mudstone interbeds within an IHS succession is of greater significance to production performance than the individual thickness of these permeability barriers.

Optimal well placement, in association with appropriate operating and completion procedures, is a recommended best practice. Understanding the interaction of the oil sands reservoir, steam chamber, and associated drainage of production fluids is crucial to SAGD success. Integration of SAGD fundamentals with reservoir characterization provides the tools to maximize production.