Optimizing steam-assisted gravity drainage (SAGD) performance in oil sands reservoirs relies on the quality of steam allocation decisions made across the well inventory. With finite facility steam generation capacity, SAGD producers are typically challenged with identifying the true opportunity cost of allocating steam volumes based on well performance. This paper presents a novel technique to inform steam allocation decisions and managing SAGD reservoir pressures in service of optimizing production and consequently improving the economic performance of the asset through smarter SAGD field development planning. The concept of marginal steam-oil-ratio (mSOR) is introduced as a method of guiding steam allocation decisions. Marginal SOR is defined as the cold-water equivalent volume of steam required to produce the next marginal barrel of bitumen from the production system in a steam constrained environment. The metric represents the opportunity cost of deploying a barrel of steam to the next best alternative in steam allocation decisions. Dynamic quantification of mSOR over the plausible range of operating pressures for each producing entity (PRDE) in the inventory (such as a well group or drainage area) is critical to optimally allocating steam when faced with reservoir challenges such as reservoir complexity and heterogeneity and transient reservoir behaviors such as thief zone interaction. This paper prescribes methodologies to analytically and empirically quantify mSOR for a SAGD production system. Additionally, application of the concept if field production optimization is discussed under the context of integrated production modeling and constrained flow network optimization problems. A case example of applying mSOR to guide steam allocation decisions at ConocoPhillips' Surmont SAGD asset is presented under a steam constrained environment. The mSOR guided solution is validated using brute-force enumeration of steam allocation outcomes in the production system to prove production optimality. The results from this dynamic steam allocation strategy guided by mSOR characterization show significant improvements in field oil rates, field steam management efficiency and consequently the economic value of the SAGD asset.

Diagnostic Fracture Injection Tests (DFITs) provide a critical piece of information on the competency of the top seal for injection projects and are therefore essential for Subsurface Containment Assurance (SCA) and Maximum Operating Pressure (MOP) determination. Results of DFITs provide the best estimate for the minimum principal stress component, which is a major input for tensile and shear failure tolerance analysis. Therefore, best practices in execution and analysis of DFITs is extremely important for safe and successful operations. Numerous DFITs have been conducted over the past ten years in Surmont to assess the integrity of the caprock and determine the maximum allowable steam injection pressure. A combination of surveillance and coupled reservoir-geomechanics simulations have been utilized to maintain a minimum of 20% safety factor for caprock failure. The tangent analysis method for determining fracture closure pressure has been extensively used in the past decade for DFIT analysis in the industry [1 and 2]. The validity of this method has been challenged recently through more rigorous modeling of the hydraulic fracturing process and field observations. An alternative analysis method referred to as the compliance method has been proposed and successfully used in many cases [3]. In the past few years, we have demonstrated the potential to safely increase the maximum operating pressure and its impact on production, through extensive caprock integrity analysis in Steam Assisted Gravity Drainage (SAGD) operations [4 and 5]. In this study, the DFITs carried out in Surmont were revisited to assess the potential impact of characterizing in-situ stresses with improved accuracy on maximum allowable injection pressure and ultimately production uplift. The analysis shows higher minimum horizontal stresses in the caprock are supported by field observations, which could potentially allow for higher injecting pressure and close to five percent additional production in the two selected SAGD pads.