To prioritize information for archiving and to determine the applicability of the Fenton Hill experience to the future development of Enhanced Geothermal Systems (EGS), an integrated review was made of five categories of Fenton Hill information: hydraulic fracturing data, well logs, seismic data, flow test data and tracer test data. Major experiments were identified, the methods of data collection and analysis were determined, the location and format of the data were determined, and further analyses that would yield information of value to EGS developers were suggested. Such analyses would be directed toward the determination of: I) if and how the state of stress in the reservoir changed during sequential fracturing jobs; 2) how the orientation of fractures changed with depth and location; 3) how the reservoir size increased as fracturing and flow testing operations proceeded; 4) how the hydraulic properties and heat-transfer characteristics of the reservoir varied with changes in operating conditions; and 5) how the Phase II reservoir (the deeper and hotter of the two reservoirs developed) would behave over the long term under various operating conditions.

This paper presents an evaluation of the cost of electric power from Enhanced Geothermal Systems (EGS), that is, reservoirs with sub-commercial permeability enhanced by hydraulic stimulation. The parameters in this exercise reflect the conditions encountered at the Desert Peak EGS project in Nevada, but the results should be applicable, at least qualitatively, to any EGS project. The approach taken is to : 1) use numerical simulation to evaluate energy recovery versus time over an assumed 30-year project life for various system configurations (number and spacing of wells, assumptions about stimulation effectiveness, etc; 2) estimate the levelized power cost for each configuration, based on capital cost, O&M cost, the cost of money and inflation rate (using Monte Carlo sampling to address uncertainties); 3) determining the sensitivity of levelized cost to the cost components, interest and inflation rates, and resource characteristics (maximum practical pumping rate, reservoir characteristics, and the depth to thereservoir at the site); and 4) estimating future EGS costs and considering the possible technology improvements that could be made by that time.

This paper describes a low-risk, low-cost and modular alternative to the conventional Hot Dry Rock or Enhanced Geothermal Systems (EGS). In this approach, which we have named the Earth Energy Extraction System (“Triple- E” System), the injected fluid is allowed to get preheated in the injection wellbore before reaching the reservoir; this preheating is achieved through injection in ultra-slim diameter wells (2.5 to 7.5cm) and by keeping the rate of injection very low (on the order of 10 liters per second). The injected fluid then heats up further as it travels to the production well through pores and fractures in the rock. The injection wells are terminated close to and at a shallower level than the top of the productive interval in the production well. This approach avoids the two main technical limitations associated with conventional EGS: (a) creating a significant reservoir volume by artificial fracturing; and (b) fluid loss control. This approach reduces dependence on the occurrence of natural permeability that limits the scope of conventional geothermal technology. The risk of cooling of the production well by shortcircuiting of injected water, a common concern in both EGS and conventional geothermal projects, is significantly reduced by preheating of the injected water.