Performance and Cost Discussion

The cost estimates in Tables 2 and 3 are in 1997 dollars. Capital costs are stated in dollars per kilowatt on an overnight construction basis. Costs not included specifically in Tables 2 and 3 are royalties to the owner of the geotherma l resource at a (typical) rate of 10% of the fluid-production-related capitalized and O&M costs.

No single technology used in geothermal electric systems is immune to improvement through industry experience an d basic and applied R&D. However, the most noticeable and measurable technology improvements that continue t o produce large cost reductions will be in geothermal wells and in power plants.

The temporal pace of improvement in Tables 2 and 3 is similar to that used in the 1991 National Energy Strateg y Current Policy Base Case. It generally assumes continued funding of the DOE Geothermal Research Program at th e constant dollar budget levels of 1995-1997 to about 2010, plus an average 10 to 15 percent industry-experience-based learning curve effect through the year 2030.

Capital Cost of Systems: Anecdotal information has suggested that U.S. industry had wrung about 20 percent out of flash-system costs in the 1985 to 1990 period, and about 30 percent out of binary-system costs in the same interval. This rough quantification has been essentially verified by the statement by Elovic [26] that Ormat, Inc., managed t o cut about 32 percent from the costs of its organic Rankine cycle (ORC) binary systems in the eight years between 1986 and 1994. Much of that improvement was attributed to changes in equipment design that lowered manufacturing costs.

Similar specific quantitati ve statements cannot be made for process- or manufacturability-related changes in geothermal flash electric power systems. It appears that the cost (in nominal dollars) estimated for Salton Sea power systems i n the NGGPP study (estimates made in late 1993 [1]) is not much different from that stated for such plants when buil t in 1985 to 1987 [27]. This would represent improvements in cost effectiveness (after inflation) on a number of fronts, but especially the replacement of crystallizer-clarifier technology (at about $17 million per 40 MW power plant i n 1985) by pH-modification technology for silicate scaling control (at only a few million dollars per plant).

Note: Power plant costs appear to have changed greatly in the past three years Geothermal power plant capital costs could be substantially different from the estimatesin this TC if there are moderate changes in the pace ofpower plant construction (in U.S. or abroad) or currency exchange rates. (See "Special Note on Power Plant Costs," page 3-20, for more details.)

The cost of purchased land is estimated to be $5,000 per ha for 10 ha, assuming desert land. Land costs in agricultural areas could be higher. This land accommodates the power plant, drilling pads (wellhead areas), and piping run s between wells and the plant. Power plant capital cost includes $15/kW for the final line transformer.

Cost of Wells: It is difficult to track the "modal" or average cost of geothermal wells, because the cost depends markedly on well depth, the geology being drilled, the sequence of the well among all wells drilled in a field, th e expertise of the drilling crew, and on the fact that relatively few geothermal wells are drilled each year. The prices o f geothermal well component materials and services fluctuate with the demand for nearly identical components for oi l and gas drilling. Those costs became extremely high (escalated rapidly) in the late 1970's and early 1980's, bu t de-escalated substantially in the mid-1980's as the world price of oil dropped dramatically.

Current R&D at Sandia National Laboratories promises to reduce the cost of drilling deep geothermal wells b y 20 percent within the next 5 to 10 years [28]. Percentage cost reductions will be less for relatively shallow wells, such as those for the moderate-temperature case characterized here, since a higher fraction of the cost of those wells is i n cement and casing whose costs are relatively inelastic with respect to improvement in drilling technology.

In the long run, say by about 2020, costs are expected to reach as little as 50% of current costs through radical improvements in drilling technologies, such as those being pursued by the National Advanced Drilling and Excavation Technologies (NADET) R&D program originated by the Department of Energy and now managed by th e Massachusetts Institute of Technology [29].

Other Reductions in Field Costs: Other improvements of field technology will arise from a number of fronts. None of the fronts are easy to either quantify or predict. Some of the expected improvements are: (a) improved siting o f production wells, through better means of interpreting geophysical data to detect permeable zones in reservoirs. Thi s will result in increased success per attempted well, and increased average production flow per well; (b) less drillin g damage to the wellbore, on average, from drilling operations per se, also increasing flow rates slightly; an d (c) improved positioning and selection of injection wells, leading to fewer abandoned wells.

Exploration Costs: Two modes of "exploration" are included here: wildcat exploratory drilling and power plant siting after wildcat drilling. (a) Wildcat drilling includes regional assessments that culminate in the first deep well(s) bein g drilled in a geothermal "prospect" area. Wildcat wells usually encounter heat at depth, but encounter economi c amounts of fluid and permeability only about 20 percent of the time in the U.S. (b) Exploration for plant siting occurs at reservoirs, prospects that have already been proven by wildcat drilling or subsequent additional drilling an d production. This exploration, as well as production well siting in general, has the advantage over wildcat siting an d drilling of information from nearby existing wells. So the likelihood of success is much higher, typically 80 to 9 5 percent.

Many of the enhanced geophysical methods that are expected to improve siting of production wells will also be applied to the siting of exploration wells. Many believe that a key path to improvements here is better understanding of th e fractures and faults that define much of the permeability and boundaries of geothermal reservoirs [30,31]. Also, drilling costs for geothermal exploration will continue to decline, especially as more and more "slim holes" of about 10 cm diameter, costing about half that of 30 cm production-diameter wells, are used for wildcat drilling [32,33].

Power Plant Capital Costs: Power plant costs should continue to decrease for two primary reasons: (a) There will be improved conversion cycle designs that produce more electricity from each pound of geothermal fluid, and (b ) There will be gradual reduction in the amount and number of instruments, controls, secondary valves, and safet y systems as designer s learn over time what can be excluded safely. But flash plant costs may stay flat over time because the large cost reductions experienced recently may have brought flash plant costs to near or below their long-ter m economic equilibrium point. (See "Special Note on Power Plant Costs," page 3-20, for more details.)

There are topping devices (e.g., Rotofow turbine [4] and Rotary Separator turbine [34]) that extract extra power from very-high-temperature fluids, hybridized main cycles that extract extra power from moderate-temperature fluids (e.g. , Kalina cycle [35] and Ormat "combined cycle" [36]), and bottoming cycles (e.g., vacuum-flash cycle [12]) bein g proposed and/or installed. Moreover, there is continued attention to how to simplify these plants to their bare essentials.

Operation & Maintenance Costs: Annual O&M costs will decrease markedly for many sites, especially those within the U.S., and perhaps abroad. Until recently, the general employment rate for U.S. geothermal power plants was about one full time equivalen t staff per MW of capacity. That is three to five times the rate for coal plants. With many o f the U.S. power sales contracts for these power plants reaching and nearing the date for reversion of price of electricity to low avoided costs of power, the geothermal industry is working very hard to reduce the labor costs of operations [16]. Pacific Gas and Electric has cut its labor pool at The Geysers significantly [37], but that is due in part t o retirement of some of PG&E's capacity there. No extensive statistics for changes in O&M expenditures for U.S. liquiddominated geothermal power systems seem to be available publicly, but such information continues to be sought.

Since most of the operating costs of geothermal electric systems are fixed, no variable operating costs are shown i n Table 1. In technical reports prior to the late 1980's a high variable operating cost for geothermal power plants is often shown; this is because those plants, often utility-owned and especially at The Geysers field, purchased steam or brine from a separate field-operating firm on an amount-consumed basis.

Capacity Factors: The availability and capacity factors of geothermal power systems tend to be much higher than the other baseload systems to which they are traditionally compared, coal and nuclear. This is because geothermal systems are intrinsicall y much simpler than the others. System availability factors (the percentage a year in which the syste m is capable of delivering its rated power) are historically very high, typically 95 percent or better [38].

Actual annual capacity factors equal to or greater than 100 percent have been reported. This is due to two trends in geothermal power plant design: (a) Generator ratings: Electric generators for geothermal service are usually ordere d with an assumed power factor (a technical parameter of alternating current systems) of 0.85: for a gross generator rating of 50,000 kW, a generator sized at 58,800 kVa would be ordered. The generator ratings and costs in the NGGPP study [1] were set on this basis [39]. However, the real loads that these generators serve tend to have power factors of about 0.98-0.99. In those circumstances, the generator produces substantially more than 50 MWh of real energy per hour. Manufacturers' ratings sometimes show this effect [40,41]. (b) Redundant equipment: One (dry steam) plant at The Geysers was designed with redundant turbines and generators, to ensure a capacity factor of essentially 10 0 percent; the economics of doing so were favorable in the mid-1980's [42,43]. This approach could be used at flashed-steam and binary plants whenever economics warrant it.

"Capacity factor" is usually defined based on nameplate rating (i.e., capacity factor = kWh output/year ^ ((nameplat e kW) X 8,760 hours/year)). Therefore, the reported capacity factor of these plants can reach 108 to 112 percent if their annual availability is 98 percent. It is also worth noting that many contemporary geothermal power sales contracts set a "contract" capacity factor at 80 percent. If production falls below the contract capacity factor, the plant receives no capacity payments for a designated period, e.g., three months. That 80 percent value is sometimes cited as the typical geothermal actual capacity factor, but that is rarely the case.

The levelized capacity factors in Tables 2 and 3 reflect effects of decreased system output late in project life, e.g., i n years 25-30, as it becomes uneconomic to replace production wells whose outputs might be declining. Such event s are expected to be ameliorated by continuing improvements in reservoir management technologies.

Expected Economic Life: The 30-year life is the common U.S. design life for geothermal power plants. Pacific Ga s & Electric's initial systems at The Geysers did operate for that life span. The effective life of geothermal productio n wells is usually shorter than that, and that has been taken into account in the costing here. The life of geothermal hydrothermal reservoirs can be much greater than 30 years, depending on how much capacity is installed. For example, The Geysers reservoir first produced power in 1960, and is expected to continue to operate until at least 2015. Reservoirs can be depleted in less than 30 years if too much capacity is installed. The life of reservoirs is generall y improved by injection of fluid back into the producing formations.

Construction Period: The construction period is typically reported as about 0.8 to 1.5 years. This period is that for erecting new capacity on a reservoir already discovered through exploration and fairly well characterized as to it s production potential. Those prior activities, exploration and reservoir confirmation, can require 3 to 8 years o f development work before installation of a first power plant on a reservoir [44]. (See Table 8, below, for allocation of capital costs over years before start up.)

Solar Stirling Engine Basics Explained

Solar Stirling Engine Basics Explained

The solar Stirling engine is progressively becoming a viable alternative to solar panels for its higher efficiency. Stirling engines might be the best way to harvest the power provided by the sun. This is an easy-to-understand explanation of how Stirling engines work, the different types, and why they are more efficient than steam engines.

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