SAGD Injection Wells What Your Prof Never Told You
Authors: McCormack Mike 
Published: March 2010

The intention of this article is threefold. The first is to provide some insight into the design of SAGD injection wells. This is a topic that has not yet been the subject of much formal literature.

The second is to disseminate some of the more interesting aspects of non-linear dynamics supported by material from the real world analysis of SAGD injection well performance. The petroleum industry is only beginning to understand the substantial implications of non-linear dynamics. The potential effect on the prediction of SAGD performance is significant. Extensions to other fields of reservoir performance analysis are possible and probable.

In the preface to the following material, it is important to recognize that numerical simulations of the SAGD process within existing numerical simulators provide results with acceptable or even superior accuracy, for most of engineering purposes. There are, however, fundamental limits to the current numerical simulation techniques used for SAGD processes. In this respect, the third objective of this article is to identify a few of this limitations.

SAGD Injection Well Performance

So you wish to inject steam into a SAGD injection well. Sounds pretty simple: just connect the wellhead piping to the surface steam supply and open the valve. Having some proper metering helps, but providing for this should be pretty routine.

The only real issue is to the design the well to optimise the placement if the steam for the SAGD process. For the purposes of this article, the design constraints during pseudo-steady-state operation after approximately six months of operation are discussed. The challenges of the early start-up period during the first six months or so are not considered. Indeed, these early time constraints can be quite complex and are worthy of future discussion.

The design constraints of pseudo-steady-state operation are framed by the desire for (in the author's estimation of importance):Drilling feasibilityLowest possible pressure drop along the horizontal annulus of the wellGood distribution of steam quality along the wellLowest drilling costRobust operating characteristics

This article will be limited to addressing constraints 2, 3, and to some extent 5.

Horizontal Annulus Pressure Drop Considerations

The folklore of SAGD well design is to allow for up to 50kPa pressure drop(1) along the annulus of the horizontal section of the well. The idea is that the pressure drop along the well will be reflected in an uneven liquid level in the chamber as shown in

FIGURE 1:Classical view of effects of pressure drop along the injector on the steam chamber liquid level. Available In Full Paper.

Figure 1. Integral to the idea is the assumption of a production well with very little pressure drop in the horizontal annulus, creating a near constant pressure sink. By extension, if the fluid level covers the injection well, the adverse steam injection distribution is expected(2). Based on a typical 5m vertical spacing between the injection and production wells, the 50 kPa guideline is roughly equivalent to the gravitational head of the liquid.