Part 1 of this study (SPE-187956-PA) presented a method to calculate the liquid pool level from temperature profile in observation wells, provided new insight into how factors like wellbore drawdown can compromise subcool control and cause steam breakthrough, and illustrated how liquid pool depletion may result in uncontrolled steam coning with time. In Part 1, the algebraic equation for liquid pool depletion based on wellbore drawdown, subcool and emulsion productivity was generated. However, not included in Part 1 was an examination of the effect of localized hot spots on well control, which is the focus of this paper.
As a part of this study, the effect of localized hot spots is mathematically included as a virtual skin factor representing the hot spot length in the algebraic equation for liquid pool depletion. The results of this work suggest that longer hot-spot will yield to lower differential pressure and make it harder to control the steam breakthrough by choking the well at a given rate. Two important finding of this work are that: (1) the zero-differential pressure (or steam coning) in reservoirs with higher permeabilities occurs in shorter hot-spots; and (2) it is harder to control the steam coning in high permeability reservoirs after hot-spots develop.
Flow control devices (FCDs) have been extensively used in horizontal wells for conventional oil and gas production in order to prevent early water break-through or gas coning. The benefits associated with this technology in SAGD industry have been studied with reservoir simulations and validated with field experience. The cost comparisons of bridge plug at the toe and scab-liners in heel with FCD installation along the producer is typically not large, which makes the FCDs the more attractive full life cycle option in producers experiencing hot-spots. Although installation of FCDs to prevent steam coning after steam breakthrough and hot-spots creation is part of the common practice as retrofits by SAGD operators, in recent years FCDs are now often installed to improve SAGD well pair performance as part of the initial completion. Although FCDs have demonstrated potential for improving recovery in SAGD production wells, vendors use a variety of approaches when designing their FCDs independent of the liquid pool element resulting in many cases where the field results showed no improvement. It is necessary to accurately characterize different FCDs under different reservoir conditions. In this study, the liner deployed FCD and liquid pool systems are coupled, and two criteria are suggested as for a design of liner deployed FCDs on the basis of pressure drop ratio of FCD relative to the liquid pool (ΔPFCD / ΔPpool) and the coefficient of variation (CoV) of inflow for the liner deployed FCD wellbore (CoVFCD).