Integrated gasification combined cycle (IGCC) power plants are believed to be the type of power plants that will predominately be used to add to our electrical power supply, replace our aging coal power plants and out increasingly expensive natural gas power plants. (Wabash River, IN IGCC plant shown above) The process offers options to eliminate greenhouse gases, produce hydrogen and/or produce liquid fuels.
The process used by IGCC plants can be broken down into five broad steps:
the coal is gasified to produce a synthetic gas (syngas)
the pollutants are removed from the syngas, then electricity is generated using a combined cycle, consisting of the following three steps:
a gas turbine-generator burns the syngas
heat from the gasification and the exhaust heat from the gas turbine are used to create steam
the steam is used to power a steam turbine-generator.
The potential for carbon dioxide sequestration makes IGCC technology even more appealing and environmentally responsible. If desired hydrogen can be separated from the syngas stream. A more complex, but even more economical option is to generate Fischer-Tropsch liquid fuels from a portion of the syngas.
The following are the characteristics of an IGCC plant:
1. SOx, NOx and particulate emissions are much lower in IGCC plants than from a modern coal plant. Its VOC emissions and mercury emissions are comparable.
2. IGCC plants emit approximately 20% less CO2 emissions than a modern coal plant.
3. IGCC plants use 20-40% less water than a modern coal plant.
4. IGCC plants operate at higher efficiencies than conventional coal fired power plants thus requiring less fuel and producing less emissions. Current efficiency is 42% with efficiencies as high as 60% expected in the very near future using a high efficiency turbines and some other process improvements.
5. Costs for electricity, without CO2 capture, is about 20% higher than in a modern coal plant. Electricity costs are 40% lower than from a natural gas IGCC plant with natural gas at $6.50 per MMbtu.
6. CO2 can be captured from an IGCC plant much more easily that from a conventional coal plant at an an additional cost increase of 25-30% for capture and sequestration, without transportation charges.
7. IGCC offers the possibility to capture the hydrogen that is part of the syngas stream, in an economic manner.
A simplified flow diagram (courtesy Energy Northwest) for an IGCC process is shown below:
Coal and/or petroleum coke is pulverized and fed into the gasifier along with oxygen that is produced in an on site air separation unit. The combination of heat, pressure, and steam breaks down the feedstock and creates chemical reactions that produce hydrogen (H2) carbon monoxide (CO) and synthesis gas, or syngas. Feedstock minerals become an inert, glassy slag product used in road beds, landfill cover, and other applications.
The syngas is cooled producing syngas and high pressure steam. Sulfur and mercury are removed from the syngas. Elemental sulfur is recovered as a marketable commodity. CO2 is removed either as vent gas or captured for sequestration. If hydrogen is to be recovered it is also separated and recovered at this point. The syngas then goes to the gas turbine where it is burned to drive the turbine and generate power. The nitrogen, from the air separation unit, is expanded through the turbine to increase power production and reduce NOx emissions. The steam from gasification is combined with steam produced in the gas turbine heat recovery unit and fed to the steam turbine-generator.
Gasification technology can be divided into three types:
1) Moving Bed Gasifiers (dry ash) 2)Fluidized Bed Gasifiers and 3)Entrained Bed Gasifiers
In a presentation by EPRI, single stage entrained gasifiers (Shell/Prenflo, E-gas, GE (formerly Texaco), KBR, Mitsubishi, Noell/GSP, Eagle, Boeing Rocketdyne, etc) were found to have the best features.
1. At high operating pressures and in the quench mode they are best for high CO2 capture.
2. They are the least expensive way of putting in the moisture needed for the Shift reaction.
3. They produce the least CH4 and are best for producing syngas for Fischer-Tropsch synthesis.
4. They use dry coal feed
5. Cooled refractory liner extends refractory life.
6 Eliminates high maintenance carbon scrubber.
7. Continuous slag removal.
See EPRI presentation for more details.
CONTINUING R & D
DOE is continuing research on gasification projects in several areas aimed at reducing emissions, reducing capital cost and increasing process efficiency.
Turbines with higher efficiencies and operating temperatures are being developed. When the Energy Department started its advanced turbine systems program in the early 1990s, the best turbines available had efficiencies of only 50 percent. Today, efficient systems typically operate in the 57- to 58-percent efficiency range. The efficiency is important because each percentage point gain can mean as much as $20 million in reduced operating costs over the life of a typical gas-fired combined-cycle plant. Turbines with efficiencies as high as 60% operating at 2600 F have been developed and tested in natural gas combined cycle applications. The Mesaba IGCC project hopes to use a 60% efficiency turbines in its plant. Both GE and Siemans Westinghouse are participating in this program.
The Energy Department is working with its private sector partners to develop a new, potentially low-cost configuration for a future gasifier. Called the “transport reactor,” the gasifier is an advanced circulating fluidized-bed reactor.
Production of oxygen with cyrogenic air separation plants adds a considerable parasitic load to the process. A much lower cost alternative being explored is to use new innovations in ceramic membranes to separate oxygen from the air at elevated temperatures.
An especially important goal of the Energy Department’s coal gasification program is to develop inexpensive membranes that can selectively remove hydrogen from syngas so that it can be used as a fuel for future fuel cells or refineries, or perhaps one day as a substitute for gasoline in a hydrogen-powered automobile.
Future concepts that incorporate a fuel cell or fuel cell-gas turbine hybrid could achieve efficiencies nearly twice today’s typical coal combustion plants.
The summer 2005 issue of Clean Coal Today, p8, has an article updating current sequestration methods being investigated in the US. The following is a brief summary:
The Weyburn enhanced oil recovery test being conducted in Saskatchewan, Canada is the longest running program, being started in 2001. It is estimated that half the CO2 injected will remain sequestered.
In the Frio, TX saline formation project 1,600 tons of CO2 was injected, in October of 2004 and various types of measuring tools are being evaluated as well as movement of the plume, which has stabilized much as predicted.
Coalbed methane recovery has been combined with CO2 sequestration in some field projects. In a seven year project with CONSOl Energy R&D in Marshall County WV, both methane recovery and sequestration in an unmineable coal seam are being investigated. The project is currently in the pre-injection phase with over 26,000 tons of CO2 to be injected over a one year period. Another similar project is being undertaken in the San Juan Basin, New Mexico.
According to a study by Foster Wheeler the cost of electricity from IGCC plants is increased 25%-30% to $.056 to $0.063 per kWh if sequestration of the CO2 is added.
According to US Coal, American Energy Review 2005, Gasification plants come at a high price tag. They have typically cost US$1.2m to US$1.6m per megawatt of capacity compared to US$1m per megawatt for a conventional coal plant and US$550,000 per megawatt for natural gas plants. Not surprisingly, IGCC plants in the US have been constructed with financial support from the DOE. High prices for natural gas have made natural gas plants unattractive and some are idle. DOE has several projects to decrease emissions, hopefully at lower costs. Higher standards for emissions controls on new plants are shifting the tradeoffs towards IGCC because of its inherently lower emissions