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.

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.