Abstract Efficient application of Steam-assisted Gravity Drainage (SAGD) for bitumen or heavy oil recovery requires production of large fluid volumes, close to the boiling point of water. Flowing or gas/steam lifting such wells is an attractive alternative to rod pumping, but evidence is given that the flow can be unstable, due to the large energy release of flashing water. The instabilities are the same phenomena that drive cyclic eruptions in geothermal geysers. A unique finite difference simulator is used to model and study the transient thermohydraulics of superheated water in an idealized wellbore. It is shown that some form of dynamic wellhead choking system is probably required for satisfactory control of a surface access SAGD well. The advent of horizontal wells for thermal recovery and especially for SAGD has led to the need to produce very large fluid volumes from individual wells, at high temperatures. For optimum SAGD, the temperature in the production liner should be kept close to the steam point at bottomhole pressure (steam trap production control)(l), so as to maintain the steam chamber as deep as possible. Sustained fluid production rates of 300 m3/D or more(2) are anticipated from single producers; at this rate, wellbore heat losses will have a limited cooling effect. In most SAGD applications, then, produced water will flash as pressure declines on the way to the surface. UTF Production Lifting Experience At the AOSTRA Underground Test Facility (UTF)(3), SAGD testing is carried out using horizontal wells that are drilled from a tunnel located below the oil sand reservoir. Steam generation and production treating facilities are on the surface, and standard piping carries fluids to and from the well chambers. The wellheads and production control valves are about 20 m lower in elevation than the production liners. This arrangement takes advantage of gravity to avoid flashing in the wellbore and the tunnel facilities, but production is still subject to flash conditions in the riser, during the 185 m climb to the surface. This was recognized during the design of the Phase A facilities, and it was hoped to exploit the resulting steam lift effect. The underground pump was de-rated and a steam sparge system was installed at the base of the riser to enable the lifting of cold fluids. A summary of experience with this system is shown in Figure 1. This is a scatter plot showing the average riser pressure gradients for about 700 days of Phase A operation, as a function of riser bottomhole temperature. This temperature is expressed in terms of subcooling below the steam point, to account for varying pressure. Most days fall into one of three groups indicated, corresponding to the (I) no flashing, (II) slight flashing, and (III) high enthalpy (est. 15 – 30% quality) conditions. The large gap between regions II and III represents conditions that were avoided due to extreme and persistent instability. In this region, flow consisted of geyser-like eruptions occurring at periods from one-half to several hours.