• The high cost of drilling
• Difficulties in predicting flow.

While drilling costs continue to resist significant reduction, we believe important progress is at hand for addressing flow uncertainty in situ – the latter meaning at the drilling target itself. Accurate handling of in situ flow uncertainty can thus in principle reduce risks to EGS drilling.

Key to EGS progress is recognizing:

• the specific physical origin of in situ flow uncertainty on all scale lengths;
• the fact that in situ flow uncertainty admits no statistical/sampling/averaging solution;
• in situ flow uncertainty is amenable to numerical modeling;
• modeling in situ flow uncertainty can be integrated into well-log analysis;
• increased applications of horizontal drilling to hydrocarbon recovery provide a technology base relevant to EGS.

We discuss this sequence of points in the context of an EGS project centered on a pair of parallel horizontal wells. The wells are modeled as located in a rock volume with well log and core determined flow uncertainty. Focusing on in situ flow heterogeneity between the EGS well pair, we find an approximate scale-relation,

between a wellbore length ℓ and separation 2a and two EGS flow factors. These factors are: wellbore flow Q ~ 25L/s and mean in situ flow velocity v ~ 10-8m/s. The latter velocity allows sustained conductive heat recharge of the EGS volume. The other terms in this relation are wellbore radius r0 ~ 0.1m and mean porosity φ ~ 0.06. With these factors, sustained heat exchange can be realized, for example, for ℓ ~ 400m and 2a ~ 75m.

In this presentation we use well log-determined flow-uncertainty models to design wells for the Raton Basin that satisfies the scaling relation.