| Abstract |
Both natural and engineered geothermal systems are conceptually simple but face complex geological conditions and risks in field realization. The chief difficulties appear to be: • The high cost of drilling. • Large uncertainties in predicting in situ fluids flow. Per-well drilling-costs are likely to continue to remain high. But progress can be made through finding ways for targeting and/or stimulating of what is termed here as ‘in situ’ sites of high fluid permeability. The main issue here appears to be our understanding of how flow takes place in fracture dominated rock. We believe that the key factors in improving this understanding are to recognize and deal with: • The physical origin of in situ flow uncertainty. • That in situ flow admits no averaging solution. • That in situ flow uncertainty can be modeled. • Such models can be obtained from well-logs and cores. • Sub-horizontal drilling technology will be needed high volume flows. We discuss this sequence of points in the context of geothermal projects for both: (a) single wells in natural systems and (b) pairs of wells for fluid circulation in engineered ones. We will show that control of rock porosity  and permeability  by native fractures can be characterized by two spatial relations. We will then discuss how these relations can be used for both exploring for, and enhancing as needed, such fractures using seismic, electromagnetic, and advanced stimulation techniques. At cm-scales, fluctuations in well-core porosity  and permeability  appear to be related by  ~ log(),  denoting spatial variation on the order of cm to m. At hundred-meter scales, variations in seismic velocity ѵ and electromagnetic resistivity ρ appear related by Δѵ ~ Δlog(ρ), Δ denoting spatial variations on the order of 10s to 100s of m. We suggest that small-scale well-core porosity  and large-scale bulk seismic-velocity ѵ are responding to spatial variations in fracture density at their respective scale lengths. (They are part of the same self-similar process.) We likewise propose that small-scale well-core permeability  and large-scale bulk electrical-resistivity ρ are responding to variations in flow paths at their respective scales. These two relations suggest that seismic and electromagnetic field data can be interpreted using joint inversion methods to find areas with high concentrations of native fractures. We illustrate this approach by case studies of Krafla, Iceland, and Olkaria Domes, Kenya, seismic shear-wave and magnetotelluric data that indicate the existence of stress-aligned-fractures at depth. These fractures induce shear-wave and resistivity anisotropy, which can be targeted for drilling high-productivity region of the geothermal area. |