The Geysers geothermal field, located in Lake, Sonoma, and Mendocino Counties, California is the largest developed geothermal system in the world. Electric power generation started at The Geysers in 1960 with a 12 MW (gross) plant. The total installed capacity in the field peaked in 1989 at 2,043 MW. As more and more power plants were built during the 1980s and net mass withdrawals increased, reservoir pressures at The Geysers declined, eventually resulting in steam shortfalls and declining generation levels. This net withdraw is due to the fact that geothermal power plants at The Geysers typically lose about 70% to 80% of produced mass to evaporation in cooling towers, with the balance of mass being returned to the reservoir through injection of steam condensate.

A new analysis demonstrates a rough correlation between microseismicity with focal depths ~ 2 km and injection in one well located in the southeastern portion of the Geysers geothermal field (in and near Unit 13), confirming what Stark (1990) has shown for the area to the northwest. The abrupt onset of micro seismicity near well McKinley-5 early in 1980 follows the initiation of injection there by about three months. Until 1986, injection and numbers of earthquakes within 3000 feet of this well appear to be roughly correlated, with injection increases or decreases leading the rise or fall of microearthquake numbers. For the years after 1986, there seems to be no correlation between earthquake frequency and injection; this may be due to the overall decline of injection volumes in the well. A similar analysis was conducted for well Thorne-7, but no correlation is evident. However, after the start-up of injection in 1984, microseismicity near this well did become more continuous from month to month.

This paper investigates the practical range of net power capacity available from conventional and enhanced geothermal wells as a function of temperature and productivity index. For a temperature range of 100°C to 190°C, which is the operating temperature limit of presently available downhole pumps, wells are typically pumped and power is usually generated in a binary-cycle plant, and in rare cases in a flash-cycle or hybrid-cycle plant. In this temperature range, the net MW capacity of a well has an upper limit of about 7.3 MW, irrespective of how high the well’s productivity index is. This capacity limit cannot be improved unless technology can be improved to allow setting pumps deeper in the well than the current limit of 457m (1,500 feet) and pumping at a higher rate than the present limit of about 160 ℓ/s (2,500 gallons per minute). For resource temperatures greater than 190°C, wells must be self-flowed, and power is generated from such wells in a flash-cycle or hybrid-cycle plant. In the temperature range of 190°C to nearly 220°C a self-flowing well’s net power capacity (irrespective of its productivity index) is less than the maximum of 7.3 MW for a pumped well.

The U.S. Department of Interior has assigned to the US Geological Survey (USGS) the task of conducting an updated assessment of the geothermal resources in the United States. In that connection, we offer an objective analysis of the last such national assessment, made in 1978, and presented in USGS Circular 790, in View of the Industry experience accumulated over the intervening 26 years. Based on this analysis we offer our perspective on how such assessment may be improved.

In the design of geothermal installations, the possibility of scale precipitation caused by silica over saturation has often been taken as a design constraint upon steam separation pressure. At installations where over-saturation is allowed to develop, the resulting scale formation is a nuisance and in some cases affects the performance of injection wells. A review of the thermodynamics, reaction mechanisms, and kinetics of silica deposition, compared with actual experience at various locations, shows that it is possible to predict low-level scaling with sufficient confidence for production and injection system design. With foresight it thus becomes possible to suppress or manage the silica scale. A useful suppression technology is fluid pH reduction, achieved by mixing with noncondensible gases and/or steam condensate. Results from several geothermal systems will be presented. Further improvements of predictive technique will benefit from more uniformity in data collection, designing experiments, reporting of results, and reporting measurements of scaling in actual production systems.

Pressure decline within The Geysers geothermal reservoir has resulted in decreased power output from existing power plants. As a means of partially arresting these ,pressure declines, several field operators and the County of Lake propose to add approximately 13,000 lpm of treated municipal waste water from several small communities into 6 injection wells in the southeastern corner of the field. Water will be carried to the geothermal field via a 50- or 6O-cm diameter pipeline from the vicinity of Clear Lake, a distance of about 45 km. The results of this study suggest that the proposed injection of effluent could help reducing the high rate of pressure and production rate declines without inducing significant geochemistry incompatibility or microseismicity.

This paper analyzes the sensitivity of the levelized cost of geothermal power to: (a) capital cost; (b) operations-d-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). We consider here the levelized cost of power (in cents per kilowatthour) 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, with 50 MW as the base case, 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. The capital cost does not include transmission line cost or any unusually site-specific costs of regulatory compliance or environmental impact mitigation.

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.

Underground fluid injection is important to a geothermal project for a number of reasons: (i) to avoid any environmental impact arising from surface disposal, (ii) to provide pressure support to the reservoir, (iii) to scavenge heat from the rock matrix, and (iv) to avoid any ground subsidence.

NCPA is the developer and operator of the second-largest power installation at The Geysers steam field in California, generating some 120 MW at the southern end of the reservoir using 68 production wells and 8 injection wells. The current total monthly steam production is about 1.451 million lbs, and about 90% of this is replaced annually by a re-injection stream that comprises about 2,000 gpm of combined (treated) sewage and lake water and about 1,600 gpm of combined condensate and rain runoff. Routine monitoring of the stable isotopes and steam chemistry of production is carried out to evaluate injection returns (injection-derived steam), and the first comprehensive evaluation of the returns and evolution of non-condensible gases in the reservoir and production since 2001 has now been completed. In contrast to experience further north in the reservoir, the weighted average total gas / steam concentration of the NCPA well field has remained stable since about 1991, at about 3,000 ppm-wt. H2S has alsoremained stable at 100~150 ppm-wt. The dome-shaped reservoir has a well-defined halo of gas / steam that increases towards the top and sides, and the general character of this halo has not been changed by injection. NCPA gases are different in composition from a previously defined Southeast Geysers type, with high levels of total C and N, and high CH4 / CO2 (molar value up to 3) found especially in the far south. These gases are either released by local sedimentary rocks, or they are a remnant of the early Geysers reservoir, before it was once flushed by meteoric water.