On the Difficult Birth of SAGD

Abstract

Introduction This contribution attempts to address some questions suggested by the series(1,2,3) to date. The answers are not all technical in nature: "Problems aren't solved by technology alone; we also need a thorough understanding of social dynamics."(4) After some select technical observations, this contribution is indeed an essay on social dynamics, as they relate to R&D in general, and SAGD development in particular. Is There any Evidence SAGD is Better Than Conventional Methods? The best evidence of this is that the more successful SAGD projects have demonstrated comparable oil/steam ratios (OSRs) to those of vertical/thermal implementations, even though the SAGD projects were conducted in reservoirs of significantly lower quality. This is illustrated in Figure 1, which compares the realized or projected OSRs of four actual projects plus a projected "prime Athabasca" case. Reservoir quality is characterized by permeability times thickness. It can be seen that approximately twice the kh is needed to achieve the same OSR using vertical technology, as can be obtained with twin-well SAGD. Pikes Peak and Cold Lake were each conducted in essentially the best reservoirs ever found in their respective formations; whereas the pay zone at Senlac, at only about 40 feet thick, would have failed most screening criteria that have been proposed for vertical CSS or steam flood. The low value of kh assigned to the UTF B Pattern is actually on the generous side. A low-energy estuary resulted in good quality sand units (5 Darcys) but with frequent silty laminations (25 – 250 mD), which prevented easy passage of steam around them. The reservoir was too heterogenous to estimate an effective bulk permeability, but geostatistical simulations and the observed project performance suggest an overall effective SAGD permeability of about 1.0 ± 0.3 Darcy. The projected Prime McMurray case is based on 40 m of 5 D sand, representing perhaps a top-decile Athabasca reservoir. Such reservoir quality is not ubiquitous over the deposit, but is known in commercial quantity at a number of widely-separated places.(5) Finally, OSR is by far the most important economic indicator for steam recovery, but the high productivity of SAGD pairs also promises lower unit costs for drilling, workovers, wellbore heat losses, and field operating labour. Why Do All SAGD Wells Seem to Produce at 100 m3/d? The UTF B pattern performance has widely come to be viewed as representative of the better Athabasca reservoirs. Nothing could be further from the truth; at least 1/3 of the total Athabasca resource is better than the B pattern, and the top 10% is enormously better. The author hypothesises that this situation has resulted in a syndrome of significant under-design in many projects, exploiting much better reservoirs. In order to reconcile predictions for such reservoirs with UTF results (while assuming sand quality is comparable), unrealistically low values for kh, kroi' and/or kv/ kh must be employed. Acceptable OSRs are nevertheless predicted, and the project proceeds. The resulting field design may be too conservative by a factor of two or three, in terms of unit-length well performance.