An industry-DOE cost-shared project is underway to evaluate the technical feasibility of developing an EGS power generation project on the eastern side of the Desert Peak geothermal field. An existing well (DP 23-1) is the focus of much of the Phase I investigation, including re-interpretation of lithology, acquisition and analysis of a well bore imaging log, conducting and analyzing a step-rate injection test, performing a "mini-frac" to determine the magnitude of the least principal stress, and re-completing the well in preparation for hydraulic stimulation in Phase II. In addition, numerical modeling has been undertaken to estimate heat recovery and make generation forecasts for various stimulated volumes and well configurations.

An industry-DOE cost-shared project is underway to evaluate the technical feasibility of developing an EGS power generation project on the eastern side of the Desert Peak geothermal field. Analysis of existing geological and geophysical data is complemented by new geologic mapping and gravity work in the Hot Springs Mountains undertaken by researchers with funding from the Great Basin Center for Geothermal Energy at the University of Nevada Reno (UNR). An existing well (DP 23-1) is the focus of much of the Phase I investigation, including re-interpretation of lithology, acquisition and analysis of a well bore imaging log, and conducting and analyzing a step-rate injection test. As of June 2003, the project is about half complete; results are summarized below. Phase I work remaining to modeling, numerical modeling and the development of a be completed includes conceptual detailed plan to guide upcoming field activities.

Most presently active or contemplated hot dry rock (HDR) projects vary significantly from the original HDR concept of creating an engineered reservoir in an effectively impermeable medium. Instead, they form part of a spectrum of geothermal resources that exhibit less-than-commercial productivity, but are not completely impermeable. A new working definition, "Enhanced Geothermal Systems" (EGS), is now being used to describe all but the high-grade hydrothermal portion of the geothermal resource spectrum. To promote the commercial development of these lower permeability and/or fluid-deficient resources, EGS research and development in the U.S. during the next few years is likely to include field experiments that target hot, low permeability zones within or near the margins of commercially developed hydrothermal systems. These systems are located in areas of elevated regional heat flow (Cascade Range, Basin and Range Province, Salton Trough, California Coast Ranges and Rio Grande Rift Zone), where temperatures of 250°C can be reached at depths of 4 km or less. Potential sites for EGS experiments were identified with the objective of yielding immediate benefits to the geothermal industry while also contributing to the commercial development of an incrementally broader range of geothermal resources.

A DOE-Industry cost-shared project is underway at Desert Peak East, located within the Hot Springs Mountains, northwestern Churchill County, approximately SO miles (80.S km) northeast of Reno, Nevada. The potential reservoir under investigation is contained within pre-Tertiary metamorphic and granitic rocks with temperatures exceeding 400°F (204°C). The purpose of the geologic study is to determine the lateral and vertical extent of basement lithologies, and the character and mineralogy of natural fracturing in the rocks to identify suitable targets for hydrofracturing and stimulation in subsequent phases of this enhanced geothermal system (EGS) project.

Based on a review of the Enhanced Geothermal Systems (EGS) developed to date worldwide, numerical simulation of idealized EGS reservoirs, economic sensitivity analysis, and practical considerations of some site characteristics, this paper shows that certain steps can be taken towards minimizing the levelized cost of electric power from EGS systems; these steps are as follows: (a) choosing the site with the highest possible vertical temperature gradient and for the thickest possible sedimentary cover on the basement; (b) choosing the drilling depth that maximizes a well’s power capacity per unit drilling cost rather than reaches the hottest resource; (c) creating the largest possible stimulated volume per well; (d) increasing per well productivity by stimulating multiple, “vertically stacked” zones and/or increasing the pumping rate of production wells taking advantage of the evolving advances in pump technology; (e) improving stimulation effectiveness, and particularly, reducing the fracture spacing and heterogeneity in the hydraulic characteristics of the stimulated volume; (f) through reservoir modeling, optimizing well spacing and injection rates that minimize the rate of decline in net generation with time (g) reducing the power plant cost; (h) developing multiple, contiguous EGS units to benefit from the economy of scale; and (i) reducing the operations and maintenance cost. The basis for these conclusions is presented in the paper.