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.

This spreadsheet is a compilation of Active Fault features compiled by the United States Geological Survey, courtesy of the Utah Geological Survey. This data is published as a Web feature service for the National Geothermal Data System. The document contains 7 worksheets, including information about the template, instructions on using the template, notes related to revisions of the template, Resource provider information, the data, a field list (data mapping view) and a worksheet with vocabularies for use in populating the spreadsheet (data valid terms). Each feature in an active fault data set (row in this spreadsheet) should be characterized by a unique combination of name, URI, geologic history, slip, locatability and orientation properties, as well as being physically connected or inferred to be connected in the Earth. For mapped active faults ,which are the scope of this scheme, the deformation style is assumed to be brittle (as opposed to ductile). Fields in the data table include FeatureURI, Name, FullName, ParentFeatureURI, Label, Description, Symbol, OtherID, SpecificationURI, FeatureType, GeologicHistory, RepresentativeAgeURI, YoungerAgeURI, OlderAgeURI, IntervalSinceMovement, Shape, ObservationMethod, PositionAccuracyMeters, PositionAccuracy, Displacement, SlipRate, SlipAccumulationInterval, MovementType, MovementSense, DipDirection, DateMostRecentEvent, RecurrenceInterval, TotalSlip, Source and MetadataURI.

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.

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.

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.

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.

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.

Most theoretical fundamentals of geothermal geochemistry were established by the mid-1980s, as were numerous practical applications of these fundamentals to geothermal resource evaluation and management. Since that time, these geochemical tools have been refined to various degrees. Advances are discussed in the categories of sampling and analysis, exploration and resource evaluation, and resource management. Noted developments include: widespread use of high-performance liquid chromatography (HPLC); advances in spectral analysis; new and refined chemical geothermometers (especially using non-condensible gas species); analysis tools that enable fluid inclusion stratigraphy; ground surface CO2 flux measurement; integration of geochemical reaction models into numerical reservoir simulation; scaling and wellflow chemistry modification; new reservoir tracers and flow-line tracer enthalpy technology. Emphasis is placed on commercially applied technology, but academic developments are included.

Existing geologic models of geothermal systems work reasonably well for the exploration of systems clearly associated with active, or recently active, volcanic centers. The poor results of exploration drilling undertaken during the last few years in the non-volcanic systems of the western United States, however, indicate that the model being used for exploring these systems requires significant modification to be useful. Based on considerations of local and regional geology, as well as on drilling results, it is proposed that the presence of large tilted fault blocks, characteristic of extended terrains, are essential to the development of this type of non-volcanic geothermal system.