Late in the life of the steam‐assisted gravity drainage (SAGD) process, drilling a single, horizontal infill well (called a wedge well by some) has become a common practice in the oil bank located between two mature SAGD well pairs to produce bitumen that has been heated and mobilized but could not be effectively drained by gravity because of the large lateral location relative to that of the SAGD producers. Because this oil bank is surrounded by a large, depleted steam chamber created by the existing well pairs, little heat is required to mobilize bitumen. Consequently, the incremental steam/oil ratio (SOR) to produce this bitumen can be reduced using these infill wells. One of the challenges, however, in producing such wells is that nonuniform drainage and local hot spots can be readily created in the first year of their operation that in many cases require steam stimulations and completion retrofits, such as with flow control devices (FCDs), to improve the drainage profile. This work is a continuation of three previous parts (presented in Irani 2018, 2019, and Irani and Gates 2018) on SAGD near‐wellbore drainage behavior, control, and some of the modeling challenges. In previous parts, productivity index (PI) models were formulated specifically for an SAGD well producing emulsion from the liquid pool under changing operational subcool conditions. Given the conformance challenges, many infill wells have greater risk of developing hot spots than SAGD producers, suggesting that the wellbore modeling, which includes the response of the FCDs, should be coupled with a PI model appropriately for such wells.
Currently, there is no suitable PI model to predict drainage rates in these SAGD infill wells. The production rate in these wells is highly pressure driven in contrast to the SAGD reservoir drainage process that is dominantly gravity driven. In this study, a time variable PI model is analytically developed for infill wells considering a developed pressure‐driven formulation. The model accurately shows fluctuations in the production rate because of flowing bottomhole pressure (FBHP) variations and can be used for both oil rate prediction and forecasting and wellbore hydraulic design for infill wells. This novel approach is the first of its kind to incorporate temperature variation, pressure dependency, and steam interface velocity within a PI model for infill wells. To achieve higher efficiencies, the location and characteristics of the FCDs along the infill wells should be optimized. In this study, the mathematical PI model of infill wells is coupled with an FCD model, and the analysis of different configurations of FCDs is evaluated. The results of this work show an uplift in a well completed with liner‐deployed FCDs, but because flashing is not incorporated in the PI model, the pressure drop predicted within these FCDs for produced fluids with free steam vapor is found to be less than reality. Ignoring flashing through the FCD provides higher density of the fluid passing through the venturi. Therefore, the FCD creates less choking with reduced conformance control than would be expected if flashing was considered.