The technique of completing or recompleting production wells as multiple-legged or "forked" wells has been successfully applied in the Aidlin area of the northwest Geysers field. Wells in the Aidlin area are deeper, hotter and have smaller diameter casings than wells in the southeastern part of the field, where forked wells have been drilled previously. These factors, plus frequently unstable formation conditions at the production casing shoe, add further complications to the forking technique. During 1992-1993, two producing wells at Aidlin were worked over and recompleted as two-legged producers, and one new well was completed with three producing legs. Despite a variety of drilling problems, each of the recompletions resulted in a significant increase in well productivity, with an average increase per well of 58 %. In addition to yielding steam production at a cost that is relatively low compared with drilling new wells, multiple-legged recompletions allow for more flexible scheduling, budgeting and permitting of drilling programs.

This paper presents an analysis of the sensitivity of the cost of geothermal power to: (a) capital cost; (b) operations-and-maintenance (O&M) cost; (c) make-up well drilling cost; (d) resource characteristics (well productivity and its rate of decline); (e) development and operational options (installed plant capacity, number of years of make-up well drilling, and project life); and (f) macro-economic climate (interest and inflation rates). The power cost here represents levelized cost (in cents per kilowatt-hour) over the project life, the capital cost being amortized over 30 years; any royalties, tax burden, or tax credit are ignored. A range of development sizes, from 5 to 150 MW, is considered. The economy of scale in both capital cost and O&M cost, as well as the higher productivity decline rate due to increased installed capacity, are taken into account.

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.

At the request of the United States Department of Energy, the author was asked by the Geothermal Energy Association (Washington, D.C.) to prepare a white paper on the subject (in connection with a new national assessment of geothermal resources). This paper offers a possible scheme in which geothermal resources are classified into seven categories based on temperature: non-electrical grade (<100°C), verylow temperature (100°C to <150°C), low temperature (150°C to 190°C), moderate temperature (190°C to <230°C), high temperature (230°C to <300°C), ultrahigh temperature (>300°C), and steam fields (approximately 240°C with steam as the only mobile phase). In the first four classes, liquid water is the mobile phase in the reservoir; in the “high” and “ultra-high” temperature reservoirs, the mobile fluid phase is either liquid or a liquid-vapor mixture.

Non-condensible gas and stable isotope data from the extreme northwest end of The Geysers steam field indicate that this part of the reservoir consists of a deeper zone, below about -8,000 feet msl, where gas concentrations arc as high as 100,000 ppm-wt, and a shallower zone with steam containing 15,000 ppm-wt gases, generally conforming to stratification of the reservoir previously reported from a production area several miles to the cast. Production wells may tap the shallow zone, the deep zone, or both, depending upon the positions of their production zones with respect to the interface. In addition to high gas content, the deeper zone is characterized by anomalously high temperatures, heavy isotopes of oxygen (and pcrhaps hydrogen) in the steam, and high total carbon in the gases. Shifts of gas composition during production can be interpreted in terms of dilution of steam in the shallow zone by boiling of reservoir liquid, and mixing between deep and shallow steam. Reservoir steam saturation after 1-1/2 years of production is caleulated to be about 0.3 in the shallow zone, and about 0.9 in the deep zone. There is some problem with saturation caleulations which involve the concentration of hydrogen, which yields deep zone saturation values as high as 2.5, which is impossible. This is discussed in relation to the possible presence of "excess" hydrogen in the steam.

Formal booking of geothermal energy reserves, for accounting purposes or annual reporting to shareholders or portfolio management, is not yet a common practice among geothermal companies. In the petroleum industry booking of oil and gas reserves is a routine practice, and at least two geothermal operators that are subsidiaries of petroleum companies book geothermal reserves. As in the petroleum industry, the reserves should be booked in appropriate resource uncertainty categories. To this end we propose three reserve categories with reference to the cumulative probability of exceeding the estimated reserves level: "proved" (equivalent to the 90th percentile), "proved-plus-probable" (equivalent to the lesser of the median and most-likely values), and "proved plus probable-plus-possible" (equivalent to the 10th percentile). However, before any reserves are booked in the proved category, we believe prospects for commercial productivity from the reservoir should be demonstrated. For the purpose of booking, reserves can be expressed in kilowatt-hours and also in equivalent barrels of oil.

This paper presents a technical feasibility analysis of the Western Geopower Corporation’s (“WGP”) 25.5 MW Unit 1 power project at The Geysers steam field, California; the WGP leasehold covers 567 acres. A commercial power plant (P.G.&E. Unit 15) operated at this leasehold during 1979 to 1989; the plant was shut down and dismantled, and the wells were plugged and abandoned, mainly due to the unduly high rate of decline in well productivity then experienced throughout The Geysers field. A new geothermal power development at this site has several attractive attributes: (a) a long production history and a large amount of resource data are available; (b) a substantial infrastructure still exists intact at the site; and (c) the decline rates in reservoir pressure and well productivity throughout The Geysers field are far lower today than when the original plant operated. An assessment of the geological characteristics of the field indicates that at least 423 acres of the leasehold can potentially supply steam to a power plant. Based on the potentially productive acreage and the 10-year production history of the original wells, steam reserves within supply a 25.5 MW plant for a project life of at least 20 years.

The Rye Patch geothermal field is a classic Basin-and-Range resource with a "blind" anomaly, moderate temperature and "deep circulation" as the source of heat. This paper presents a conceptual model of the field based on lithologic, geophysical and temperature logs as well as production, injection and pressure interference data from 8 deep wells drilled to date. For the hottest well in the field (405°F), we have conducted well bore heat transfer modeling to resolve a major observed discrepancy between the flowing and static temperature profiles, the latter being shown to be affected by downflow of cooler water. The conceptual model has been developed to fit all available resource information, and had been used to estimate reserves: a minimum of 36 M Wand a most-likely level of 64 MW for a 20-year project life. Based on well test data, the maximum gross power production capacity from the existing wells is estimated at 21 MW. The existing wells are capable of supplying the 12.5 MW plant installed at the site if one or two additional wells are drilled for injection.

This paper derives the relation between productivity and pressure decline trends in a geothermal steam reservoir. At all stages of a geothermal project, the economics is affected by the rate of productivity decline. The rate of pressure decline becomes a critical issue when the reservoir pressure declines to the point that wells have to be flowed wide open to supply the turbine; at that stage, maintaining reservoir pressure and well productivity by redistribution and/or augmentation of injection becomes a stratcgic issue in field management. Therefore, the issues considered in this paper have significant practical implications.

This paper presents an analysis of power generation prospects from Enhanced Geothermal Systems (EGS), specifically, reservoirs with subcommercial permeability enhanced by hydraulic stimulation. EGS is also known as “hot dry rock” or “hot fractured rock” systems. The performance under consideration here is the net electrical power delivered as a function of time over the 20-to-30 year life of a power plant. Although the parameters in this exercise generally reflect conditions encountered at the Desert Peak EGS project in the State of Nevada, United States, the conclusions are applicable, at least qualitatively, to any EGS project.