Peter Malin has an extensive background in seismology and geological-geophysics. He has worked on San Andreas fault seismology and tectonics, on deep crustal reflection seismology, and the seismology of hydrothermal systems. He has developed borehole instrumentation and has over 25 years experience installing borehole networks. His instruments have been used worldwide from geothermal fields in Iceland to the Californian San Andreas fault.
||Enhanced/Engineered Geothermal Systems (EGS) are conceptually simple but have long defied cost-effective field realization. The chief difficulties appear to be
- 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,
a2ℓ ~ Qr0 / 2πφv ~ O(106m3)
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.