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.

This paper investigates the practical range of net power capacity available from conventional and Enhanced Geothermal System (“EGS”) wells as a function of temperature. For a geothermal resource temperature up to about 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 under the current state of downhole pump technology, the net MW capacity of a well has a practical 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 pumping at a higher rate than the present practical limit of about 160 l/s (2,500 gallons per minute); improving the temperature tolerance of pumps, by itself, will not increase this capacity limit. 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.

Many sedimentary formations, including some that contain oil or gas, may be hot enough to serve as commercial geothermal reservoirs. Unlike conventional geothermal reservoirs which generally occur in fractured formations, these reservoirs have intergranular porosity, which allows relatively easy estimation of the hydraulic characteristics of a well from cores and well logs. Using these estimates, the well’s power capacity can be estimated for various well production options (such as, pumped or self-flowing) and power generation technology options (such as, binary, flash or hybrid).

There are three types of petroleum wells potentially capable of supplying geothermal energy for electric power generation: (a) a producing oil or gas well with a water cut, (b) an oil or gas well abandoned because of a high water cut, and (c) a geopressured brine well with dissolved gas. This paper considers the basic technical and economic aspects of power generations from each of the three types of wells and presents case histories of estimating the available power capacity of a typical well (or a group of wells) in each of the above categories. We have conducted these assessments for commercial developers and operators.

Geothermal assessments and cost estimates were performed as part of California’s Renewable Energy Transmission Initiative (RETI) to help guide transmission planning. The RETI assessments identified approximately 5,300 gross megawatts (MW) of additional electrical-generation capacity that could be brought on line from geothermal sites within 10 years, including 2,440 gross MW within California. The RETI study area spanned 5 western states and parts of Canada and Mexico. Geothermal assessments were performed for 116 sites in California, Nevada, Oregon, and southern British Columbia. MW capacity estimates were made on a regional basis for Arizona, Washington, and the northern portion of the Mexican state of Baja California Norte (“Baja”). Capital costs and costs for Operations and Maintenance (O&M) were estimated primarily as a function of MW capacity. For most sites, estimated capital costs ranged from $3,000 to $5,500 per gross MW installed, and estimated O&M costs ranged from $22 to $35 per gross MWh (2008 dollars). These costs were converted to a net-MW basis in the RETI analysis for purposes of comparison with other renewable energy sources. The Levelized Cost of Energy (LCOE) for most geothermal sites ranged from $65 to $130 per net MWh.

There is a persistent perception worldwide that The Geysers field is a classic example of everything that could go wrong with geothermal power development. This presentation analyzes the history of The Geysers to dispel that perception. It concludes that this field has proven to be the most productive geothermal field discovered yet, and that it provides the best example to date of maintaining commercial viability of geothermal power generation through ingenious field management. The analysis considers both the resource behavior and the socioeconomic forces at play at this field. The presentation also forecasts the performance of this field over the next two decades and considers the lessons learned from its forty-year history.

Injection of steam condensate back into the Geysers reservoir produces shifts in the chemistry of produced steam at nearby wells. Specifically, these effects include: 1) changes in the spacial variation of non-condensible gas/steam ratio; 2) changes in the 18 concentrations of stable isotopes 0 and deuterium; 3) shifts in the abundance of gas species Ar, N2 and NH3, and 4) changes in calculated gas geothermometers and steam saturation factors. This geochemical information, when combined with other reservoir data, has been used to assist in the targeting of new injection wells.

This paper investigates the economics of steam production at The Geysers from the point of view of a field developer. We present a cash-flow analysis and the calculation of several profitability criteria for steam supply to a hypothetical 55 MW (gross) power plant starting in 1989. This paper assesses in two parts the economics of developing the steam supply: (1) a deterministic economic analysis to establish the sensitivity of the profitability criteria to steam price where each parameter is given a unique value, and (2) a probabilistic analysis to estimate the profitability criteria, and their sensitivity to steam price, when uncertain parameters are allowed to vary. The results of the study indicate that no new commercial project is economically feasible at The Geysers unless the steam price exceeds 2 cents/kw'hour, because of long payout and extremely low profitability. Only a steam price exceeding 2.7 cents/kw'hour ensures a reasonably short payout time and the minimum profitability typically expected by field developers. Above a steam price of 3 cents/kw'hr, the economics of field development are attractive and risks are low. The accelerated decline in well productivity in recent years has increased risks and reduced profitability.