Fossil Steam Plants Rankine Cycle Subcritical Steam

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The Rankine cycle (or vapor steam cycle) represents the basic energy conversion cycle providing 70% of the electricity in the US economy. Fundamentally, it is the conversion of water into steam, followed by the extraction of work, which today is usually accomplished by conversion into electricity (or in the case of cogeneration, steam for industrial processes). The first design was developed in the late 1712, yielding a cycle efficiency that was less than 2%. It has taken almost 300 years to reach an efficiency of over 40%, the current state-of-the art for fossil steam plants. Today's facilities operate with steam temperatures on sub-critical plants range from 537°C/1,000°F to 565°C/1,050°F.

In the United States, 50% of the electricity is generated using coal as the primary source of energy, releasing about 1 tonne CO2/MWh. The energy extracted from coal is converted into heat, converting water to steam, and fed into a rotating steam turbine. Overall efficiency of a sub-critical unit (one that operates well below 3,200 psig) is on the order of 10,000 Btu/kW h, about 33% (even less if the fuel contains a large quantity of water as is found in some coals such as lignite or Powder River Basin coal). Rankine Cycle (Supercritical)

Increasing the steam pressure and temperature increases the amount of energy carried with the steam, and more energy can then be extracted by the steam turbine. Operating at supercritical conditions (above 3,200 psig), the cycle efficiency can increase by an additional 5% (depending on plant size, complexity, and fuel).

Supercritical steam units are more efficient to operate, and if fuel costs are high, they are likely to be the preferred thermal system. The first commercial supercritical plant in the United States went into service in 1957 (operated by AEP), the second in Philadelphia by 1961. Both units were relatively small by today's standards—125 and 325 MWe respectively. By any standards, these units were groundbreaking, and pioneering, and not without early problems.

By the mid-1960s, about half of all United States units under order were supercritical, suggesting that the initial teething problems with the new technology had been largely solved. Some of the key problems were materials related, leading to decisions to derate the units to improve reliability. As of 1986, 15% of the United States fleet operated at supercritical steam conditions.

In Japan and Europe, supercritical units were continuously built throughout the 1980s and onward. It took years after the first wave before problems with materials, startup, controllability, and reliability could be solved. In the United States much of the supercritical fossil steam construction came to a halt in the 1980s partly, because of the introduction of nuclear power generation and partly because the low cost of domestic coal didn't demand the more extreme operating conditions.

By 2001, a new wave of supercritical fossil steam plant construction began. Nearly all new power plants under consideration will be supercritical (that is, operate above the critical conditions for steam). Worldwide, more than 400 supercritical plants are in operation. Ultra-supercritical

Operating steam and gas turbines at higher pressures and temperatures improves efficiency. Pushing thermal plant operating conditions beyond 5,000 psig and 700°C may allow operation at efficiencies approaching 50%+, about 10% points higher than current commercial supercritical power plants. There are extreme material challenges to be overcome as the metals weaken at the high temperatures and pressures proposed (perhaps as high as 4,000-5,000 psig). It is another facet of the research effort to find materials capable of operating long term under these conditions.

Once metal temperatures exceed 620°C (1,150°F) threshold, steels comprised of substantially iron (ferrite) must be replaced with a more exotic, expensive, difficult to weld and machine nickel-based alloys. Some of the materials proposed for these extraordinary conditions do not conduct heat as well as those used in less severe conditions (i.e., conditions found in the most advanced boilers and steam turbines produced today). At some of the more extreme conditions (approaching 700°C/1,290°F), very expensive alloys such as Inconel or Hastelloy may be required. This will require the high-pressure steam piping, steam turbine blades, vanes, and casing to be fabricated from materials to handle these conditions, materials that are also quite expensive.

Specialty materials will be required for ultra-high efficiency plants still on the drawing boards, and high efficiencies will be needed if fossil plants must adopt energy intensive post combustion emission controls for carbon capture. All known carbon capture processes degrade unit performance substantially. Therefore, it is critically important to push the core efficiency of the power station to its maximum so that the efficiency penalty is offset once additional controls are put in place. If the loss in efficiency is not offset, it will require a larger facility, consuming even more carbon fuels to produce the same energy production as a unit without controls. Consider it from a different perspective: If we use existing established boiler technology, it would require mining and consuming even more coal, since a significant part of the energy in the fuel would be required to operate carbon capture system.

We clearly have the tools to model, design, and even construct facilities that can produce power while extracting CO2. The impacts on power and efficiency, and ultimately on the cost to the consumer, have yet to be resolved. This is one reason why improving plant efficiency (increased MWh per tonne of CO2) or using a lower carbon fuel (natural gas) provides a convenient short-term solution to a very challenging problem. A major benefit of selecting the NGCC option is that one realizes both a lower emission rate of CO2 and improved efficiency, significantly higher than any competing technology. This benefit can be quickly lost by adding emission controls to a source that already exhibits a substantially lower CO2 emission profile compared to any other fossil-fueled power generation. The natural gas option only has long-term viability if supplies of gas are robust. Fortunately, that appears to be the case. Supplies of unconventional gas (gas from shales and coal bed methane) and offshore supplies are making the gas option more viable going forward. While the United States appears to lead the world in the "unconventional gas expansion," these geological formations are not unique to North America and can be found in virtually every continent, making this a long-term global option. Thus what we have learned in solving the issue here in the US could readily be adapted to other major economies wrestling with the same problem. Combined Cycle

Combining both a Rankine and Brayton cycle yields the largest efficiency step increase in the last few decades. While steam cycles have topped out in the range of 40-45%, and air cycles are close to that, combining the two cycles is capable of producing an overall cycle efficiency in the range of 55-60%. Since the vast majority of these units operate on natural gas as the primary fuel, the mix of cycle efficiency and fuel carbon content is the primary reason for CO2 emission levels achieved in the 0.3-0.35 tonne/MWh range. Reaching these performance levels also required decades of research and development. In the 1970s operating temperatures for the gas turbine component were limited to 760°C, with efficiency in the range of 28-30%. Using state-of-the-art materials, design methods, and cooling strategies, operating temperatures now are in the range of 1,300-1,400°C. This evolved over a period of almost 40 years, a process that is still on going.

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