11. Hot Springs Hot springs in Steamboat Springs area. http://www.eia.doe.gov/cneaf/solar.renewables/page/geothermal/geothermal.html
12. Fumaroles Clay Diablo Fumarole (CA) White Island Fumarole New Zealand http://volcano.und.edu/vwdocs/volc_images/img_white_island_fumerole.html http://lvo.wr.usgs.gov/cdf_main.htm
50. Cost of Water & Steam http://www.worldbank.org/html/fpd/energy/geothermal/assessment.htm Table Geothermal Steam and Hot Water Supply Cost where drilling is required 10-20 Low Temperature (<100 o C) 20-40 3.0-4.5 Medium Temperature (100-150 o C) 3.5-6.0 High temperature (>150 o C) Cost (US ¢ /tonne of hot water) Cost (US $/ tonne of steam)
51. Cost of Geothermal Power http://www.worldbank.org/html/fpd/energy/geothermal/assessment.htm Normally not suitable 4.0-6.0 2.5-5.0 Large Plants (>30 MW) Normally not suitable 4.5-7 4.0-6.0 Medium Plants (5-30 MW) 6.0-10.5 5.5-8.5 5.0-7.0 Small plants (<5 MW) Unit Cost (US ¢ /kWh) Low Quality Resource Unit Cost (US ¢ /kWh) Medium Quality Resource Unit Cost (US ¢ /kWh) High Quality Resource
52. Direct Capital Costs Direct Capital Costs (US $/kW installed capacity) http://www.worldbank.org/html/fpd/energy/geothermal/assessment.htm Normally not suitable Exploration : US$100-400 Steam field:US$400-700 Power Plant:US$850-1100 Total: US$1350-2200 Exploration:: US$100-200 Steam field:US$300-450 Power Plant:US$750-1100 Total: US$1150-1750 Large Plants (>30 MW) Normally not suitable Exploration: : US$250-600 Steam field:US$400-700 Power Plant:US$950-1200 Total: US$1600-2500 Exploration : US$250-400 Steamfield:US$200-US$500 Power Plant: US$850-1200 Total: US$1300-2100 Med Plants (5-30 MW) Exploration : US$400-1000 Steam field:US$500-900 Power Plant:US$1100-1800 Total:US$2000-3700 Exploration : US$400-1000 Steam field:US$300-600 Power Plant:US$1100-1400 Total: US$1800-3000 Exploration : US$400-800 Steam field:US$100-200 Power Plant:US$1100-1300 Total: US$1600-2300 Small plants (<5 MW) Low Quality Resource Medium Quality Resource High Quality Resource Plant Size
53.
54. Operating/Maintenance Costs Operating and Maintenance Costs http://www.worldbank.org/html/fpd/energy/geothermal/assessment.htm 0.4-0.7 0.6-0.8 0.8-1.4 Total 0.25-0.45 0.35-0.45 0.45-0.7 Power Plant 0.15-0.25 0.25-0.35 0.35-0.7 Steam field O&M Cost (US c/KWh) Large Plants(>30 MW) O&M Cost (US c/KWh) Medium Plants (5-30 MW) O&M Cost (US c/KWh) Small plants (<5 MW)
a Ethanol blended into motor gasoline is included in both &quot;Petroleum&quot; and &quot;Biomass,&quot; but is counted only once in total consumption. b Includes supplemental gaseous fuels. c Petroleum products supplied, including natural gas plant liquids and crude oil burned as fuel. d Biomass includes: black liquor, wood/wood waste liquids, wood/wood waste solids, municipal solid waste (MSW), landfill gas, agriculture byproducts/crops, sludge waste, tires, alcohol fuels (primarily ethanol derived from corn and blended into motor gasoline) and other biomass solids, liquids and gases. P = Preliminary Note: Data revisions are discussed in Highlights section. Totals may not equal sum of components due to independent rounding. Sources: Non-renewable energy: Energy Information Administration (EIA), Monthly Energy Review (MER) March 2005, DOE/EIA-0035 (2005/03) (Washington, DC, March 2005,) Tables 1.3 and 1.4. Renewable Energy: Table 2 of this report. As a result totals in this table do not match the March MER.
I. Earth Heat The gradual radioactive decay of elements within the earth maintains the earth's core at temperatures in excess of 5000°C. Heat energy continuously flows from this hot core by means of conductive heat flow and convective flows of molten mantle beneath the crust. The result is that there is a mean heat flux at the earth's surface of around 16 kilowatts of heat energy per square kilometre which is dissipated to the atmosphere and space. This heat flux is not uniformly distributed over the earth's surface but tends to be strongest along tectonic plate boundaries where volcanic activity transports high temperature material to near the surface. Only a small fraction of the molten rock feeding volcanoes actually reaches the surface. Most is left at depths of 5-20 km beneath the surface, where it releases heat that can drive hydrological convection that forms high temperature geothermal systems at shallower depths of 500-3000m.
A geyser is a type of hot spring that erupts periodically, ejecting a column of hot water and steam into the air. The name geyser comes from Geysir , the name of an erupting spring at Haukadalur , Iceland ; that name, in turn, comes from the Icelandic verb gjósa , &quot;to gush&quot;. The formation of geysers requires a favourable hydrogeology which exists in only a few places on Earth, and so they are fairly rare phenomena. About 1000 exist worldwide, with about half of these in Yellowstone National Park , USA ( Glennon , J.A. 2005). Geyser eruptive activity may change or cease due to ongoing mineral deposition within the geyser plumbing, exchange of functions with nearby hot springs, earthquake influences, and human intervention (Bryan, T.S. 1995).
CDF is a fumarole in the Casa Diablo area, near the intersection of U.S. Highway 395 and State Highway 203. Vent temperature is measured a few times each year, has remained fairly stable between 92 and 94 degrees, and is the hottest of the 5 fumaroles that are monitored in the Long Valley caldera. Gas chemistry has been collected on several occasions (Farrar and others, 1985). Vent gas temperature and chemistry of CDF are monitored because changes in characteristics of CDF may indicate a change in the volcanic system. This is an especially large fumarole on the inner wall of the central crater. Image the sound of a large roaring jet engine, and you get an impression of the noise it produces. Together with the steam, the smell of foul eggs (caused by sulphur) and because it's not the only fumarole in the crater, a view in the crater is like looking in hell's kitchen. - Christian Treber Copyrights information on the above image Location : Central Crater, White Island, New Zealand
The steam once it has been separated from the water is piped to the powerhouse where it is used to drive the steam turbine. The steam is condensed after leaving the turbine, creating a partial vacuum and thereby maximising the power generated by the turbine-generator. The steam is usually condensed either in a direct contact condenser, or a heat exchanger type condenser. In a direct contact condenser the cooling water from the cooling tower is sprayed onto and mixes with the steam. The condensed steam then forms part of the cooling water circuit, and a substantial portion is subsequently evaporated and is dispersed into the atmosphere through the cooling tower. Excess cooling water called blow down is often disposed of in shallow injection wells. As an alternative to direct contact condensers shell and tube type condensers are sometimes used, as is shown in the schematic below. In this type of plant, the condensed steam does not come into contact with the cooling water, and is disposed of in injection wells. Typically, flash condensing geothermal power plants vary in size from 5 MWe to over 100 MWe. Depending on the steam characteristics, gas content, pressures, and power plant design, between 6 and 9 tonne of steam each hour is required to produce each MW of electrical power. Small power plants (less than 10 MW) are often called well head units as they only require the steam of one well and are located adjacent to the well on the drilling pad in order to reduce pipeline costs. Often such well head units do not have a condenser, and are called backpressure units. They are very cheap and simple to install, but are inefficient (typically 10-20 tonne per hour of steam for every MW of electricity) and can have higher environmental impacts.
Flash Steam Power Plant This is the most common type of geothermal power plant. The illustration below shows the principal elements of this type of plant. The steam once it has been separated from the water is piped to the powerhouse where it is used to drive the steam turbine. The steam is condensed after leaving the turbine, creating a partial vacuum and thereby maximising the power generated by the turbine-generator. The steam is usually condensed either in a direct contact condenser, or a heat exchanger type condenser. In a direct contact condenser the cooling water from the cooling tower is sprayed onto and mixes with the steam. The condensed steam then forms part of the cooling water circuit, and a substantial portion is subsequently evaporated and is dispersed into the atmosphere through the cooling tower. Excess cooling water called blow down is often disposed of in shallow injection wells. As an alternative to direct contact condensers shell and tube type condensers are sometimes used, as is shown in the schematic below. In this type of plant, the condensed steam does not come into contact with the cooling water, and is disposed of in injection wells. Typically, flash condensing geothermal power plants vary in size from 5 MWe to over 100 MWe. Depending on the steam characteristics, gas content, pressures, and power plant design, between 6 and 9 tonne of steam each hour is required to produce each MW of electrical power. Small power plants (less than 10 MW) are often called well head units as they only require the steam of one well and are located adjacent to the well on the drilling pad in order to reduce pipeline costs. Often such well head units do not have a condenser, and are called backpressure units. They are very cheap and simple to install, but are inefficient (typically 10-20 tonne per hour of steam for every MW of electricity) and can have higher environmental impacts. http://www.worldbank.org/html/fpd/energy/geothermal/technology.htm
Binary Cycle Power Plants In reservoirs where temperatures are typically less than 220oC (430oF). but greater than 100oC (212oF). binary cycle plants are often utilised. The illustration below shows the principal elements of this type of plant. The reservoir fluid (either steam or water or both) is passed through a heat exchanger which heats a secondary working fluid which has a boiling point lower than 100oC (212oF). This is typically an organic fluid such as Isopentane, which is vaporised and is used to drive the turbine. The organic fluid is then condensed in a similar manner to the steam in the flash power plant described above, except that a shell and tube type condenser rather than direct contact is used. The fluid in a binary plant is recycled back to the heat exchanger and forms a closed loop. The cooled reservoir fluid is again re-injected back into the reservoir. Binary cycle type plants are usually between 7 and 12 % efficient depending on the temperature of the primary (geothermal) fluid. http://www.worldbank.org/html/fpd/energy/geothermal/technology.htm If the geothermal resource has a temperature between 100o and 150oC, electricity can still be generated using binary plant technology. The produced fluid heats, through a heat exchanger, a secondary working fluid (isobutane, isopentane or ammonia), which vaporises at a lower temperature than water. The working fluid vapour turns the turbine and is condensed before being reheated by the geothermal water, allowing it to be vaporised and used again in a closed-loop circuit (Figure 12.3). The size of binary units range from 0.1 to 40 MWe. Commercially, however, small sizes (up to 3 MWe) prevail, often used modularly, reaching a total of several tens of MWe installed in a single location. The spent geothermal fluid of all types of power plants is generally injected back into the edge of the reservoir for disposal and to help maintain pressure. In the case of direct heat utilisation, the geothermal water produced from wells (which generally do not exceed 2 000 metres) is fed to a heat exchanger before being reinjected into the ground by wells, or discharged at the surface. Water heated in the heat exchanger is then circulated within insulated pipes that reach the end-users. The network can be quite sizeable in district heating systems. For other uses (greenhouses, fish farming, product drying, industrial applications) the producing wells are next to the plants serviced. http://www.worldenergy.org/wec-geis/publications/reports/ser/geo/geo.asp
Binary Cycle Power Plants In reservoirs where temperatures are typically less than 220oC (430oF). but greater than 100oC (212oF). binary cycle plants are often utilised. The illustration below shows the principal elements of this type of plant. The reservoir fluid (either steam or water or both) is passed through a heat exchanger which heats a secondary working fluid which has a boiling point lower than 100oC (212oF). This is typically an organic fluid such as Isopentane, which is vaporised and is used to drive the turbine. The organic fluid is then condensed in a similar manner to the steam in the flash power plant described above, except that a shell and tube type condenser rather than direct contact is used. The fluid in a binary plant is recycled back to the heat exchanger and forms a closed loop. The cooled reservoir fluid is again re-injected back into the reservoir. Binary cycle type plants are usually between 7 and 12 % efficient depending on the temperature of the primary (geothermal) fluid. http://www.worldbank.org/html/fpd/energy/geothermal/technology.htm If the geothermal resource has a temperature between 100o and 150oC, electricity can still be generated using binary plant technology. The produced fluid heats, through a heat exchanger, a secondary working fluid (isobutane, isopentane or ammonia), which vaporises at a lower temperature than water. The working fluid vapour turns the turbine and is condensed before being reheated by the geothermal water, allowing it to be vaporised and used again in a closed-loop circuit (Figure 12.3). The size of binary units range from 0.1 to 40 MWe. Commercially, however, small sizes (up to 3 MWe) prevail, often used modularly, reaching a total of several tens of MWe installed in a single location. The spent geothermal fluid of all types of power plants is generally injected back into the edge of the reservoir for disposal and to help maintain pressure. In the case of direct heat utilisation, the geothermal water produced from wells (which generally do not exceed 2 000 metres) is fed to a heat exchanger before being reinjected into the ground by wells, or discharged at the surface. Water heated in the heat exchanger is then circulated within insulated pipes that reach the end-users. The network can be quite sizeable in district heating systems. For other uses (greenhouses, fish farming, product drying, industrial applications) the producing wells are next to the plants serviced. http://www.worldenergy.org/wec-geis/publications/reports/ser/geo/geo.asp
The curves below give an indication of the electrical power output from a binary plant over a range of flows and geothermal reservoir temperatures.
Combined Cycle (Flash and Binary) Combined Cycle power plants are a combination of conventional steam turbine technology and binary cycle technology. By combining both technologies, higher overall utilisation efficiencies can be gained, as the conventional steam turbine is more efficient at generation of power from high temperature steam, and the binary cycle from the lower temperature separated water. In addition, by replacing the condenser-cooling tower cooling system in a conventional plant by a binary plant, the heat available from condensing the spent steam after it has left the steam turbine can be utilised to produce more power. A number of such plants have been built in the USA, Philippines and New Zealand with plant sizes ranging between 10 and over 100 MWe. Efficiencies of such plants in terms of the power generated for the total fluid flow (both steam and water) produced by the wells is significantly higher than conventional plants, mainly due to the extra power generated by utilising the heat in the brine.
Hot Dry Rock Geothermal Energy Technology The technology to mine the heat from the hot rock found almost everywhere at some depth beneath the surface of the earth was conceived and developed at Los Alamos between the years of 1970 and 1996. Conceptually, hot dry rock (HDR) heat mining is quite simple. As shown in the drawing (above, left) water is pumped into hot, crystalline rock via an injection well, becomes superheated as it flows through open joints in the hot rock reservoir, and is returned through production wells. At the surface, the useful heat is extracted by conventional processes, and the same water is recirculated to mine more heat. The key element in successful heat mining is the development of an engineered geothermal reservoir in a hot body, impermeable rock. The point in a hot rock body at which an HDR reservoir is created is determined by the selection of the location on the surface from which the injection well is drilled and the depth within the wellbore at which the water is injected into the hot rock, while the overall size of the reservoir is a direct function of the total amount of water pumped into the rock during its development. Although these parameters can be engineered, the shape, orientation, and internal structure of the reservoir, are entirely functions of the local geologic conditions and are, at present, beyond human control. For this reason, it is important to understand the local geology before attempting to develop an HDR reservoir. As an HDR reservoir is being formed, rock blocks are moved very slightly by the injected water. These small movements give rise to low frequency stress waves similar to, but much smaller than, those caused by earthquakes. Microseismic technology has been developed to identify these signals and locate their points of origin. The data from many such signals provide a picture of the size, shape, and orientation of the reservoir. With this information in hand, production wells can be drilled into the reservoir to most efficiently tap the superheated water that has been injected. As demonstrated at the Los Alamos Fenton Hill site (above, right) HDR system is operated by circulating water through the engineered reservoirs at a pressure somewhat less than that used during its creation. Under these conditions the overall volume of the engineered reservoir is relatively stable. In the closed-loop operation, the injection pump, working like the human heart, provides the entire motive force for the circulation. Nothing except a small amount of waste heat is released to the environment. The Fenton Hill test experiment has been completed and HDR technological advances realized at Los Alamos have been incorporated into a broader program encompassing hydrothermal environments. That program is under the leadership of Princeton Economic Research, Inc. (PERI). PERI is working with the US geothermal industry to apply technology developed as part of the Los Alamos HDR effort to problems facing commercial geothermal production which is currently derived entirely from natural hydrothermal resources. PERI is also formulating longer-term plans and designing programs that should eventually lead commercial utilization of HDR resources. HDR field work is continuing at sites in northern France and on the island of Honshu in Japan. A nascent HDR program is also getting underway in Australia. The experience gained from HDR work at Los Alamos is being utilized in all of these international projects. That experience also provided the basis for a wide range of related activities now underway in EES-4.
Direct use technologies are where geothermal heat is used directly rather than for power generation and are built around the extraction of heat from relatively low temperature geothermal resources, generally of less than 150oC (300oF). Because geothermal heat is non-transportable, (except short distances by fluid pipeline) any applications must generally be sited within10 km or less of the resource. For many resources, the relatively low temperatures and/or pressures in the reservoirs means that they have insufficient energy and/or pressure differences to naturally carry the fluids to the surface and pumps are frequently used (either downhole or at the surface). The type of technology selected for utilising geothermal heat for direct use applications is dependent on the nature of the geothermal fluid and the type of direct use planned. In many direct use applications, the geothermal fluid cannot be used directly, such as in drying processes or where clean steam or hot water is necessary, as geothermal fluid often contains chemical contaminants. In such cases heat exchangers are utilised to extract the heat from the hot geothermal fluid and transfer it to either clean water, or in the case of drying processes, to air. There are two main types of heat exchangers commonly used. They are plate heat exchangers and shell and tube. The heat exchanger technology employed in the geothermal industry is the same as is commonly used over a wide range of industries where heat exchangers are utilised. Commonly used heat pump technology can also be employed in order to utilise geothermal heat for air conditioning and refrigeration applications. Specific details of the technologies used for the various applications of direct use are presented under the section on applications.
A very efficient way to heat and air-condition homes and buildings is the use of a geothermal heat pump (GHP) that operates on the same principle as the domestic refrigerator. The GHP (Figure 12.4) can move heat in two ways: during the winter, heat is withdrawn from the earth and fed into the building; in the summertime, heat is removed from the building and stored under-ground. In some GHP systems heat is removed from shallow ground by the means of an antifreeze/water solution circulating in plastic pipe loops (either inserted in vertical wells less than 200 m deep which are then backfilled or buried horizontally in the ground). In other GHP systems flow water produced from a shallow borehole through the heat pump, discharges the water either in another well or at surface. The heat pump unit sits inside the building and is coupled either with a low-temperature floor or wall heating net or with a fan delivering heat and cold air.
Figure 9.4 The Southhampton geothermal district heating system technology schematic
Whether geothermal energy is utilised for power production or for direct use applications, there are issues in geothermal utilisation that often have technical implications. Geothermal fluids often contain significant quantities of gases such as hydrogen sulphide as well as dissolved chemicals and can sometimes be acidic. Because of this, corrosion, erosion and chemical deposition may be issues, which require attention at the design stage and during operation of the geothermal project. Well casings and pipelines can suffer corrosion and /or scale deposition, and turbines, especially blades can suffer damage leading to higher maintenance costs and reduced power output. However, provided careful consideration of such potential problems is made at the design stage, there are a number of technological solutions available. Such potential problems can be normally overcome by a combination of utilising corrosion resistant materials, careful control of brine temperatures, the use of steam scrubbers and occasionally using corrosion inhibitors. Provided such readily available solutions are employed, geothermal projects generally have a very good history of operational reliability. Geothermal power plants for example, can boast of high capacity factors (typically 85-95%)
Potential ImpactPotential EffectMitigation/Remediation measuresLand requirement Vegetation loss Soil erosion Landslides Land ownership issues Single drill pads –several wells Re-vegetation programs Adequate land compensation Water take from streams/waterways for drilling purposes Impact on local watershed Damming and diverting local streams Take from streams with high flow rates Coincide drilling with rainy season not dry season Build temporary reservoirs Liaise with local farmers to take their usage into account Water take from reservoir Loss of natural features ( see note below ) Increase in steaming ground Hydrothermal eruptions Lowering of water table Increase in steam zone Subsidence Saline intrusion Avoid water take from outflows Avoid areas where propensity for hydrothermal eruptions (which occur naturally also) Careful sustainable management of resource, balancing recharge with take Waste (brine & condensate) disposal into streams/ waterways Biological effects Chemical effects Thermal effects Effluent treatment and removal of undesirable constituents Reinject all waste fluids Cascaded uses of waste fluids eg. Fish farms, pools Reinjection Cooling of reservoir Induced seismicity Scaling Careful planning of reinjection wells outside main reservoir Monitor flow patterns before reinjection eg. Tracer tests Anti-scale treatment of fluids Drilling effluent disposal into streams/waterways Biological effects Chemical effects Contain in soakage ponds or in barrels for removal Air emissions Biological effects Chemical effects Localised slight heating of atmosphere Localised fogging Effluent treatment and removal of undesirable constituents Minimise emissions by scrubbing H2S and treating other NCGs (Non Condensible Gases) Noise pollution Disturbance to animals and humans Impaired hearing Muffling of noise eg. silencers
Although geothermal sites are capable of providing heat for many decades, eventually they are depleted as the ground cools. [2] The government of Iceland states It should be stressed that the geothermal resource is not strictly renewable in the same sense as the hydro resource. It estimates that Iceland's geothermal energy could provide 1700 MW for over 100 years, compared to the current production of 140 MW.
The cost of geothermal power developments is dependent upon many factors, the most important factors being: · The temperature and depth of the resource. A shallow resource means minimum drilling costs. High temperatures (high enthalpies) mean higher energy capacity. · The type of resource (steam, two phase or liquid). A dry steam resource is generally less expensive to develop as reinjection pipelines, separators and reinjection wells are not required · The chemistry of the geothermal fluid. A resource with high salinity fluids, high silica concentrations, high gas content, or acidic fluids can pose technical problems which may be costly to overcome. · The permeability of the resource. A highly permeable resource means higher well productivity, and therefore fewer wells required to provide the steam for the power plant. · The size of the plant to be built. As with most types of power plant, economies of scale means large power plants are generally cheaper in $/MW. · The technology of the plant. There are a number of geothermal power technologies available, including simple back pressure plant with atmospheric exhaust, conventional condensing plant, binary cycle, combined cycle binary plants, Kalina Cycle, multi flash plants etc. Each technology has advantages and disadvantages and different cost structures. · Infrastructure requirements (access roads, water and power services, proximity to adequate port facilities, proximity to a city). In isolated locations or small islands especially in developing countries, infrastructure may be a significant part of the total cost. · Climatic conditions at the site. As with all types of power plants their cost and performance is dependent on the local climatic conditions. Low ambient wet bulb temperatures for example can lead to a less costly cooling system and a more efficient plant. · Topography of the site. If the geothermal resource is sited in difficult terrain, civil development costs will be higher, pipelines may be more complex, of longer length with greater pressure drops and overall development costs may be higher. · Environmental constraints. Environmental constraints on the siting, construction and operation of the geothermal power station can often result in increased development cost. A typical example may be the requirement for minimal discharge of geothermal gases (in particular hydrogen sulphide) to the environment. This may require the gases to be either reinjected into the reservoir (such as at the Puna plant in Hawaii) or costly hydrogen sulphide abatement systems to be installed. · The proximity of the transmission lines. In isolated areas, it may be a requirement of the project to include for the construction of a lengthy transmission line to enable the power from the station to be fed into a grid servicing a sizeable load, possibly some distance away. · The type of construction contract employed. Turnkey/EPC contracts are becoming very popular, especially with IPP developments as they reduce the financial risk to the developer, enable financing to be more easily achieved as well as giving a single point of responsibility for plant performance. However such implementation methods are generally more costly than the traditional multi-contract approach. · Administration, management, legal, insurance, permitting, financing, local taxes and royalties and other indirect costs. The indirect costs of a power project, especially in developing countries can be a significant proportion of the overall project costs (up to 30%)
Costs of geothermal electric power are very dependent on the character of the resource and project size. The unit costs of power currently range from 2.5 to over 10 US cents per kilowatt-hour while steams costs may be as low as US$3.5 per tonne. Major factors affecting cost are the depth and temperature of the resource, well productivity, environmental compliance, project infrastructure and economic factors such as the scale of development, and project financing costs.
Risk Assessment An important part of the financial assessment is risk assessment. The track record of international geothermal developments in the prime exploration regions of East Africa and numerous Pacific Rim countries has shown that by adopting a systematic methodology of exploration and prioritisation, success rates of over 80% are regularly achieved during subsequent exploration drilling. Carefully implemented regional reconnaissance surveys have led to a sound prioritisation of target areas by the filtering out of less promising prospects. Examples of such successful programmes include those undertaken in Indonesia, New Zealand and the Philippines.Prospective sites may be selected on the basis of thermal manifestations, volcanic areas or areas of naturally high heat flow. Early reconnaissance of all known prospective sites leads to the selection of priority target areas on the basis of field characteristics, and power requirements. The priority areas can then be assessed by various surface geo-scientific surveys. Sociological and environmental studies are also carried out with the collection of some baseline data. These costs are relatively low. At this stage a prefeasibility assessment is made of the resource potential of a prospect to determine whether or not to proceed to the more costly phase of exploration drilling and testing. Risks and Limitations Exploration Risk Reconnaissance surveys of geothermal areas are frequently undertaken by national research institutions as part of national indigenous resource investigations. Prioritisation of resources for development at this reconnaissance stage will significantly increase the certainty of success. A survey of geothermal fields in active volcanic regions in the Pacific rim indicate that at the reconnaissance stage the probability that an exploitable geothermal field exists in the area is 50% if even a single hot spring is present. If the spring is boiling, or fumaroles (steam vents) are present, then the probability increases to 70%. However the more detailed surface exploration studies leading to the pre feasibility stage, may result in expenditure up to US$1 M, which is at risk (30% probability of failure) through not identifying a useable heat resource. The expenditure on exploration drilling (frequently 3 wells) is an order of magnitude greater (US$1.5 - 2 M per well) and this is similarly at risk if the wells do not result in useful production (commonly through low reservoir temperatures or low permeability). Fewer or less costly shallower wells may be applicable for smaller developments. On the other hand deep exploration drilling risk will increase with decreasing reservoir temperature below about 200oC. Resource prioritization to target the most promising areas and good exploration surveys have proven to deliver high success rates for exploration drilling of high temperature geothermal systems. Such decision making is shown diagrammatically in the technology section. A 1987 study in Indonesia identified 214 geothermal fields which were prioritized for development on a least cost of development basis. Of the top 20 fields, 11 have been drilled and exploitable reservoirs confirmed (currently 707.5 MW installed), one has been drilled with a single well and abandoned through poor results, 2 have completed feasibility studies and await exploration drilling, and surface exploration activities are continuing on the remaining 6 fields. The low exploration risk is emphasized in Indonesia by geothermal reservoirs (temperatures > 220oC) having been found in 89% of prospects where exploration drilling to greater than 1000 m has been undertaken. East African countries (Djibouti, Ethiopia and Kenya) have a similar success rate of 83% for deep exploration drilling while in New Zealand the exploration success rate is 100%. The Philippines has also had a very high success rate in developing geothermal resources through the Philippines National Oil Company accepting the risk of geothermal resource development in the belief that they had a good understanding of Philippine geothermal resources. The higher risks associated with lower temperature geothermal resources can be illustrated by the experiences in Thailand. Three main areas have been explored by drilling but wells deeper than 1000 m have only been drilled at San Kampaeng. Here the maximum well output was 11 kg/s of 125oC water, equivalent to about 170 kW(e), which is uneconomic to exploit due to the cost of drilling to these depths. In contrast at Fang, 17 kg/s of 120oC water is produced from 150 m deep wells and is used in a 300 kW binary turbine. This electricity is reported to cost about US 7cents / kWh and illustrates that if relatively high temperatures with moderate flows can be encountered at relatively shallow depths cost effective power can be generated. Size of Development and Reservoir Exhaustion The size, and therefore exploitability, of a geothermal reservoir provides another significant risk in geothermal development. A complete understanding of the reservoir can only be obtained by withdrawing fluids from the reservoir over a sustained period, with subsequent computer modeling to assess the performance into the future. It can take several years of production from a field before the reservoir performance can be gauged with confidence since the reservoir rate of decline is frequently exponential in nature with initial high rates of decline. Assessment of resource size and production capacity (resource assessment) is a critical part of any geothermal development. At the feasibility stage without long term production data, resource assessments rely on the extent of the reservoir, as defined by drilling and geophysical anomalies, and a knowledge of reservoir fluid temperatures. Such assessments can have large errors thus increasing the risk of plant size incompatibility. Once long term reservoir performance has been established the production capacity will be estimated in terms of MW of energy over a particular time period (frequently taken as 30 years being approximately the life of steam turbines). Such estimates reduce the likelihood of excessive withdrawal of fluids from reservoirs which leads to reservoir pressure decline and reduced well (energy) outputs. Reservoir pressure decline may in turn allow low temperature groundwater to flood the system and cool the reservoir even further. The risk of pressure decline can be mitigated by conservatively sizing the rate of heat extraction (power station size) in comparison to the estimated resource capacity. Several geothermal fields have oversized power stations for the exploited reservoir size, with the most well known being The Geysers in California. The Momotombo field in Nicaragua is another example. It was initially exploited with a 35 MW(e) power station in 1983 but with the addition of a second 35 MW(e) plant in 1989 the reservoir was over produced, resulting in reservoir decline, to the extent that in 1998 the field was only producing 20 MW(e). Once a resource has been developed, regular monitoring of production data (engineering and scientific data) is undertaken accompanied by simulation studies to better predict the future behavior of the reservoir in order to maximize production and minimize premature reservoir failure. Economic and Political Risk Rural electrification projects suffer less from changes in national policies and economics than private energy developments. The 1997 Asian economic downturn put many geothermal developments on hold with subsequent loss of income revenue. The finance for the power station at the Ulumbu rural electrification geothermal project on the island of Flores in Indonesia was diverted for alternative uses in late 1998 due to the Asian economic crisis. The late 1990's global economic weakness has also left many geothermal projects in Central and South America on hold due to lack of funding.
Geothermal Energy Cost for Power Generation Geothermal energy development of high temperature (>180oC) for power generation typically involves some risk in the initial investigations to prove the geothermal resource. Investment is required for exploration, drilling wells and installation of plant, but operating costs are very low because of the low cost of fuel. In comparison, fossil fuel station capital costs are usually significantly cheaper than geothermal power stations, but fuel costs are very much higher. Diesel powered generation plant capital costs for example are typically less than 50% of the cost of geothermal plants. However, diesel can cost between US$3 to US$6/GJ. There are many other benefits in utilising an indigenous geothermal energy resource. Geothermal power reduces the national reliance on imported fossil fuels, thereby saving valuable foreign exchange earnings. Due to many influencing factors, geothermal power development project capital costs are very much site and project specific. However, as a general guideline, the following sections give a range of direct and indirect capital costs and operating and maintenance costs under a number of scenarios. All scenarios below are based upon an EPC type project implementation approach, with the detailed engineering included in the direct costs, not the indirect, as would other wise be the case. http://www.worldbank.org/html/fpd/energy/geothermal/assessment.htm
Levelised Unit Power Costs The typical unit cost of power from geothermal plants, based upon a discount rate of 10% are shown in the table below. A capacity factor of 90% has been assumed. These costs are based upon projects constructed in developing countries and therefore indirect costs at the higher end of the scale have been chosen. With the unit cost of diesel generation at least 10c/kWh and up to 20c/kWh, geothermal generation is a very attractive option, especially in remote, off grid areas and small islands where diesel generation is often the only alternative for power generation. Direct use of the low temperature reject water fraction from geothermal power generation can often be attractive. It is advantageous for the power developer to be approached at an early stage to enable any such arrangement to be incorporated into the power plant/steam field designs
Direct Capital Costs The table below shows indicative direct capital costs (US$/kW) for small, medium and large plants, developed in high, medium and low quality geothermal resources. A high quality geothermal energy resource is taken to mean a resource with high temperature (>250o C) very good field wide permeability (and therefore high well productivity) likely to be a dry steam or two phase reservoir, low gas content and with benign chemistry. A low quality resource is one with reservoir temperature below 150oC, or a resource although with possibly higher temperature, has poor permeability, high gas content and difficult chemistry. The exploration phase is assumed in the costs to be made up of geoscientific surface exploration (US$600,000) and one (small plant development) to five exploration wells, each well costing about US$1.5 M
Indirect Costs Indirect costs vary significantly depending on the location of the site, its accessibility, level of infrastructure and expatriate requirements. Approximate Indirect costs have been given based upon three different categories of project locations. Location A, is typical project site in a developed country. Infrastructure is in place, skilled labour is available and port facilities and a major city relatively close by. Indirect costs are about 5 - 10% of direct costs. Location B is a typical project site in a more remote area of a developed country, or in an area of a developing nation where infrastructure is of a good standard, there is a pool of skilled labour and the nation enjoys political and social stability. Indirect costs are about 10-30% of direct costs. Location C is a typical project site in a more remote area of a developing nation, where infrastructure is poor, accessibility is difficult, skilled labour is scarce and there is the risk of political instability. Indirect costs are about 30 - 60% of direct costs.
Operating and Maintenance Costs The table below gives indicative power station and steam field operating and maintenance (O & M) costs for small, medium and large geothermal power developments. The above costs do not allow for the cost of new makeup wells, which are normally required with time to makeup for the gradual production decline from the original wells. The rate of decline in output of geothermal wells depends on the nature of the resource and the size of the development, but can generally vary between 5% and 10% per annum. Therefore, in addition to the above costs, a developer would also need to allow for about 8% of the total well costs each year for future makeup well requirements.
Geothermal-generated electricity was first produced at Larderello , Italy , in 1904 . Since then, the use of geothermal energy for electricity has grown worldwide to about 8,000 megawatts of which the United States produces 2,700 megawatts. The largest dry steam field in the world is The Geysers, about 90 miles (145 km) north of San Francisco began in 1960 which produces 2,000 MW . Calpine Corporation now owns 19 of the 21 plants in The Geysers and is currently the United States' largest producer of renewable geothermal energy. The other two plants are owned jointly by the Northern California Power Agency and Santa Clara Electric. Since the activities of one geothermal plant affects those nearby, the consolidation plant ownership at The Geysers has been beneficial because the plants operate cooperatively instead of in their own short-term interest. Another major geothermal area is located in south central California, on the southeast side of the Salton Sea , near the cities of Niland and Calipatria, CA. As of 2001, there were 15 geothermal plants producing electricity in the area. CalEnergy owns about half of them and the rest are owned by various companies. Combined the plants produce about 570 megawatts. Geothermal power is very cost-effective in the Rift area of Africa. Kenya's KenGen has built two plants, Olkaria I (45 MW) and Olkaria II (65 MW), with a third private plant Olkaria III (48 MW) run by Israeli geothermal specialist Ormat. Plans are to increase production capacity by another 576 MW by 2017, covering 25% of Kenya's electricity needs, and correspondingly reducing dependency on imported oil. Geothermal power is generated in over 20 countries around the world including Iceland (producing 17% of its electricity from geothermal sources), the United States , Italy , France , New Zealand , Mexico , Nicaragua , Costa Rica , Russia , the Philippines , Indonesia and Japan . Canada 's government (which officially notes some 30,000 earth-heat installations for providing space heating to Canadian residential and commercial buildings) reports a test geothermal-electrical site in the Meager Mountain–Pebble Creek area of B.C, where a 100 MW facility might be developed at that site.
Title: Dual flash plant geothermal power facility in Heber, California Caption The Heber Geothermal Power Station is owned by the Heber Geothermal Company and operated by Imperial Power Services, Inc. The power plant is located in Imperial County, CA and is seven miles south of El Centro. The number of wells drilled to date is 57, with the deepest being 10,800 feet. The average well depth is 6,500 feet with an average geothermal fluid production per well of 2,000 gallons per minute and an average fluid temperature of 360 degrees Fahrenheit. Its present electrical generating capacity is 52,000 kilowatts. The facility began commercial operation in July 1985. Credit: Gretz, Warren Publications: Date: DOE_office: Notes: Subject: buildings, electric, geothermal, utilities Descriptors: clouds, commercial, facility, fence, generate, output, pipes, power lines, power plant, sky, station, steam, tank, temperature, trees, well Person/Place: Heber, California; Heber Geothermal Power Station Release Level Full/Internet DOE Information:
Location of Resources Worldwide, those hot areas with fluids above 200oC at economic depths for electricity production are concentrated in the young regional belts. They are the seats of strong tectonic activity, separating the large crustal blocks in which the earth is geologically divided (Figure 12.5). The movement of these blocks is the cause of mountain building and trench formation. The main geothermal areas of this type are located in New Zealand, Japan, Indonesia, Philippines, the western coastal Americas, the central and eastern parts of the Mediterranean, Iceland, the Azores and eastern Africa. Elsewhere in the world, underground temperatures are lower but geothermal resources, generally suitable for direct-use applications, are more widespread. Exploitable heat occurs in a variety of geological situations. It is practically always available in the very shallow underground where GHPs can be installed. The risk for a prospector (of not locating hot water in the quantity and with the quality required) is limited in shallow depth targets where prior knowledge gained from earlier surveys is available. There are greater uncertainties on deeper resources where insufficient survey work has been conducted.
Flash Steam Power Plant This is the most common type of geothermal power plant. The illustration below shows the principal elements of this type of plant. The steam once it has been separated from the water is piped to the powerhouse where it is used to drive the steam turbine. The steam is condensed after leaving the turbine, creating a partial vacuum and thereby maximising the power generated by the turbine-generator. The steam is usually condensed either in a direct contact condenser, or a heat exchanger type condenser. In a direct contact condenser the cooling water from the cooling tower is sprayed onto and mixes with the steam. The condensed steam then forms part of the cooling water circuit, and a substantial portion is subsequently evaporated and is dispersed into the atmosphere through the cooling tower. Excess cooling water called blow down is often disposed of in shallow injection wells. As an alternative to direct contact condensers shell and tube type condensers are sometimes used, as is shown in the schematic below. In this type of plant, the condensed steam does not come into contact with the cooling water, and is disposed of in injection wells. Typically, flash condensing geothermal power plants vary in size from 5 MWe to over 100 MWe. Depending on the steam characteristics, gas content, pressures, and power plant design, between 6 and 9 tonne of steam each hour is required to produce each MW of electrical power. Small power plants (less than 10 MW) are often called well head units as they only require the steam of one well and are located adjacent to the well on the drilling pad in order to reduce pipeline costs. Often such well head units do not have a condenser, and are called backpressure units. They are very cheap and simple to install, but are inefficient (typically 10-20 tonne per hour of steam for every MW of electricity) and can have higher environmental impacts. http://www.worldbank.org/html/fpd/energy/geothermal/technology.htm
Binary Cycle Power Plants In reservoirs where temperatures are typically less than 220oC (430oF). but greater than 100oC (212oF). binary cycle plants are often utilised. The illustration below shows the principal elements of this type of plant. The reservoir fluid (either steam or water or both) is passed through a heat exchanger which heats a secondary working fluid which has a boiling point lower than 100oC (212oF). This is typically an organic fluid such as Isopentane, which is vaporised and is used to drive the turbine. The organic fluid is then condensed in a similar manner to the steam in the flash power plant described above, except that a shell and tube type condenser rather than direct contact is used. The fluid in a binary plant is recycled back to the heat exchanger and forms a closed loop. The cooled reservoir fluid is again re-injected back into the reservoir. Binary cycle type plants are usually between 7 and 12 % efficient depending on the temperature of the primary (geothermal) fluid.
If the geothermal resource has a temperature between 100o and 150oC, electricity can still be generated using binary plant technology. The produced fluid heats, through a heat exchanger, a secondary working fluid (isobutane, isopentane or ammonia), which vaporises at a lower temperature than water. The working fluid vapour turns the turbine and is condensed before being reheated by the geothermal water, allowing it to be vaporised and used again in a closed-loop circuit (Figure 12.3). The size of binary units range from 0.1 to 40 MWe. Commercially, however, small sizes (up to 3 MWe) prevail, often used modularly, reaching a total of several tens of MWe installed in a single location. The spent geothermal fluid of all types of power plants is generally injected back into the edge of the reservoir for disposal and to help maintain pressure. In the case of direct heat utilisation, the geothermal water produced from wells (which generally do not exceed 2 000 metres) is fed to a heat exchanger before being reinjected into the ground by wells, or discharged at the surface. Water heated in the heat exchanger is then circulated within insulated pipes that reach the end-users. The network can be quite sizeable in district heating systems. For other uses (greenhouses, fish farming, product drying, industrial applications) the producing wells are next to the plants serviced.
To generate electricity, fluids above 150oC are extracted from underground reservoirs (consisting of porous or fractured rocks at depths between a few hundred and 3 000 metres) and brought to the surface through production wells. Some reservoirs yield steam directly, while the majority produce water from which steam is separated and fed to a turbine engine connected to a generator. Some steam plants include an additional flashing stage. The used steam is cooled and condensed back into water, which is added to the water from the separator for reinjection (Figure 12.2). The size of steam plant units ranges from 0.1 to 150 MWe.
Recent Developments Comparing statistical data for end-1996 (SER 1998) and the present Survey, it can be seen that there has been an increase in world geothermal power plant capacity (+9%) and utilisation (+23%) while direct heat systems show a 56% additional capacity, coupled with a somewhat lower rate of increase in their use (+32%). Geothermal power generation growth is continuing, but at a lower pace than in the previous decade, while direct heat uses show a strong increase compared to the past. Going into some detail, the six countries with the largest electric power capacity are: USA with 2 228 MWe is first, followed by Philippines (1 863 MWe); four countries (Mexico, Italy, Indonesia, Japan) had capacity (at end-1999) in the range of 550-750 MWe each. These six countries represent 86% of the world capacity and about the same percentage of the world output, amounting to around 45 000 GWhe. The strong decline in the USA in recent years, due to overexploitation of the giant Geysers steam field, has been partly compensated by important additions to capacity in several countries: Indonesia, Philippines, Italy, New Zealand, Iceland, Mexico, Costa Rica, El Salvador. Newcomers in the electric power sector are Ethiopia (1998), Guatemala (1998) and Austria (2001). In total, 22 nations are generating geothermal electricity, in amounts sufficient to supply 15 million houses. Concerning direct heat uses, Table 12.1 shows that the three countries with the largest amount of installed power: USA (5 366 MWt), China (2 814 MWt) and Iceland (1 469 MWt) cover 58% of the world capacity, which has reached 16 649 MWt, enough to provide heat for over 3 million houses. Out of about 60 countries with direct heat plants, beside the three above-mentioned nations, Turkey, several European countries, Canada, Japan and New Zealand have sizeable capacity. With regard to direct use applications, a large increase in the number of GHP installations for space heating (presently estimated to exceed 500 000) has put this category in first place in terms of global capacity and third in terms of output. Other geothermal space heating systems are second in capacity but first in output. Third in capacity (but second in output) are spa uses followed by greenhouse heating. Other applications include fish farm heating and industrial process heat. The outstanding rise in world direct use capacity since 1996 is due to the more than two-fold increase in North America and a 45% addition in Asia. Europe also has substantial direct uses but has remained fairly stable: reductions in some countries being compensated by progress in others. Concerning R&D, the HDR project at Soultz-sous-Forêts near the French-German border has progressed significantly. Besides the ongoing Hijiori site in Japan, another HDR test has just started in Switzerland (Otterbach near Basel). The total world use of geothermal power is giving a contribution both to energy saving (around 26 million tons of oil per year) and to CO2 emission reduction (80 million tons/year if compared with equivalent oil-fuelled production).
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