Effect of Solution Gas on 1D Steam Rise in Oil Sands
Authors: Edmunds N. 
Published: March 2010

This paper summarizes evidence of gas effects in several Athabasca SAGD projects and shows that these effects can be easily reproduced with simple 1D column simulations. Solution gas probably has a material impact on SAGD rise, and therefore production rates in general, especially where the operating pressure is significantly below the initial pressure.

Introduction

Following the UTF Phase A SAGD test, it was reported that: "No significant accumulations [of non-condensable gas] were observed in the steam chamber. This was fortunate because such accumulations appear to be harmful because they inhibit steam transport to the front. "

"Current simulators incorrectly predict that even small amounts of gas???will accumulate in a steam chamber and substantially impair drainage???more work is required to account for gas transport mechanisms adequately so that reasonable predictions can be made for reservoirs containing greater amounts of gas(1). "

Simulators still do not properly account for known amounts of solution gas in the McMurray formation in the sense that it is not generally possible to produce a reasonable history match of field behaviour if the full amount of solution gas is included(2).

The question of how the gas is being removed from the chamber, and therefore what is missing from the simulators, remains unresolved, and is beyond the scope of this paper. Meanwhile, two important points have been passed over.

The first is that, even at UTF, some insignificant gas accumulations can be found in the data, for example as reported by Ito et al.(3).

The second is that "reservoirs containing greater amounts of gas " than UTF or Dover, include most of the current McMurray SAGD projects. In the case of Foster Creek, at the deep end, saturation pressure is 2,800 kPa and the solution GOR is estimated to be about five times that of Dover.

Since the gas removal mechanism(s) is unknown, it has always been possible that it was strong enough under UTF circumstances to prevent "significant " accumulations, but not strong enough to do this in deeper Athabasca reservoirs. However, the difficult nature of the SAGD gas problem, combined with the apparent success of UTF history matching without it, has understandably encouraged a situation where it has become standard practice to ignore solution gas in SAGD simulations.

Standard practice is also to arbitrarily lower absolute and/or relative permeabilities in order to match field performance. In the case of the UTF project, there was good correspondence between measured core and history match permeabilities using "open " relative permeabilities. This correspondence does not seem to apply to deeper, thicker reservoirs such as Surmont or Foster Creek, particularly with respect to steam rise rates.

Field Evidence

Hangingstone

Ito et al.(3,4) conducted detailed analyses and history matching of observation well temperature data from the UTF Phase B and Hangingstone Phase I projects. Although the Hangingstone situation is complicated by the high operating pressure of 5 MPa at a depth of 280 m (i.e. 18 kPa/m, which they demonstrated by cold water injection was enough to begin deformation of the sand matrix), it show anomalies in the rise rates at some wells where steam rise would "suddenly stop " for a while and then resume.