The total installed geothermal power generating capacity in the world is approximately 9000 MWe from 21 countries, with the United States leading at nearly 3000 MWe and The Philippines with nearly 2000 MWe (Table II). Other major countries are Italy, Mexico, Indonesia, Japan, and New Zealand, with between 400 and 800 MWe each.
Geothermal power stations have very high availability, load, and capacity factors (>90%). They are most suitable as base load power stations. Liquid – dominated reservoirs are not suitable for peak load generation because two-phase flow and the separation process make their operations and control at changing flows difficult.
A geothermal power station that uses steam turbines to generate electricity is similar to a conventional fossil fuel-fired power station. The main differences are:
• Geothermal steam is usually saturated steam at less than 10 bar abs and 200°C (occasionally superheated up to ~ 50 bar abs and 300°C), but in
TABLE II
|
World Installed Geothermal Power Generating Capacity in 2000
Source. Institute of Geosciences and Earth Resources, Pisa, Italy. |
a fossil fuel-fired power station, the steam can be supercritical to as high as 300 bar abs and 600°C.
• Geothermal steam normally contains impurities of noncondensable gas (NCG) at up to a few percentage points by weight of steam (mainly carbon dioxide [>90%] and a few percentage points of hydrogen sulfide) and dissolved solids (mainly silica or calcite) that precipitated from flashing of the liquid phase.
• A fossil fuel-fired power station has a boiler and the steam/water is in a closed loop, whereas a geothermal power station does not have a boiler and the steam/water is in an open loop.
Because of the low-pressure saturated steam, a geothermal steam turbine unit is limited to a maximum capacity of approximately 55-MWe condensing unit due to the maximum length of the last – stage turbine blades limited by the material metallurgy. Two of these turbines can be installed on a single shaft to a 110-MWe generator.
The NCG is allowed to pass through the steam turbines but must be removed from the condensers so that the low subatmospheric pressure in the condensers can be maintained. A gas extraction system is used to remove the NCG from the condensers. A steam jet ejector is suitable for low gas contents of less than 1% weight of steam. A steam jet ejector has no moving parts, so it is easy to operate and has a low maintenance cost. However, the steam flow used to drive it is high (~five times the NCG flow rate). Hence, steam jet ejectors are suitable only for low NCG levels. The NCG removed from the condensers is normally exhausted to the atmosphere.
For economic reasons, a gas exhauster is required when the gas contents exceed 2%. This is normally a multistage centrifugal compressor with an intercooler. Recirculation valves between the stages are necessary for control. It is typical to drive the compressor by electric motor, but the compressor can be driven by the steam turbine.
A liquid ring pump can be used to replace the final-stage steam jet ejector to improve efficiency and economy. Liquid ring pump systems are used in fossil fuel-fired power stations to maintain condenser vacuum. They have a small capacity, so they are suitable only for low gas contents.
The condensers mentioned previously are direct – contact condensers. Shell and tube condensers can also be used to better control NCG emissions. However, shell and tube condensers are expensive and less efficient.
When a geothermal resource cannot produce a sufficient quantity of clean enough steam to drive steam turbines, other modes of power generations need to be used. If the steam contains too much NCG (>10% weight of steam), a condensing turbine unit becomes uneconomical. In such a case, a back pressure turbine that does not have an aftercondenser can be used. The steam is exhausted directly to the atmosphere, but this mode of generation is unlikely to be acceptable nowadays for environmental reasons. Either total flow or binary mode of generation needs to be used.
Many geothermal ORC binary plants are in operation around the world. A heat exchanger (shell and tube type) is used to transfer heat from the geothermal fluids to a low-boiling point secondary fluid (isopentane or isobutane). The secondary fluid superheated vapor drives a vapor turbine that exhausts to an air-cooled shell and tube condenser. The secondary fluid is in a closed loop, and the spent geothermal fluids are reinjected.
Whereas an ORC binary plant usually uses an aircooled condenser, a typical condensing steam turbine unit uses a direct-contact condenser. The resultant condensate/cooling water mixture is normally removed from the condenser via a barometric leg or a pump. This condensate mixture flows to a holding pond known as the hot well, and from there it is pumped to a cooling tower to be cooled for recirculation to the condensers. As the geothermal steam from the steamfield eventually becomes a part of the recirculating cooling water, the total volume of the recirculating water tends to increase, even though some is evaporated at the cooling tower. Hence, some of the condensate mixture is reinjected from the hot well. Because this condensate mixture is warm (~40°C) and oxygenated, it is quite corrosive to carbon steel. Stainless steel pumps, pipes, and well casing are required for condensate reinjection.
Two types of cooling towers are commonly used for a geothermal power station: natural draft and mechanical draft cooling towers. For economic reasons, a natural draft cooling tower is built for an approximately 100-MWe capacity geothermal power station. Natural draft cooling towers also function better in a cooler climate. For warm climates, mechanical draft cooling towers are more suitable. Because the fan of a mechanical draft cooling tower is limited by the length of the its blades due to the strength of the construction material, a mechanical draft cooling tower has a small capacity. So, mechanical draft cooling towers are normally built as rows of cells.
