Material world27 February 2014
New materials are being investigated for coal-fired power plants as their owners and operators seek to reduce emissions, using alternative fuels and carbon capture technologies.
Coal-fired power plants are under increasing pressure to reduce emissions. Options for doing so include carbon capture and sequestration, and/or switching partially or wholly to biomass as a fuel. But both have potential implications for the materials used in power stations, not least because they may impact corrosion rates. So, if we are to benefit from such green approaches, we need to understand their impacts on components and find ways to deal with them, without compromising plant safety or incurring excessive costs.
Back to basics and all coal-fired power plants have extensive piping and tubing, in and around the boiler, subject to high temperatures. For steam-raising tubes and pipes, the resulting corrosion can be in the form of steam-side oxidation on the internal surfaces or fire-side corrosion, where the external metal is exposed to species in the combustion gases and ash. Both result in the formation of oxide scales.
Oxides are less thermally conductive than the metals from which they are derived, so the result is localised temperature rises above the equipment design limits. Oxides can also spall off and collect in tube and pipe bends, restricting steam flow and leading to additional overheating. Perhaps most important, corrosion is a problem, because it reduces the wall thicknesses, leading to increased stress and accelerated creep, which eventually causes pipes and tubes to crack and rupture, if not repaired or replaced.
Conditions affect corrosion
Rates of corrosion are well understood under conventional conditions and power plants schedule maintenance routines accordingly. But changes to operating conditions can affect corrosion rates. So, before engineers intervene with emissions-reducing plant changes, it is critical to understand how these will affect the infrastructure and to plan viable mitigating responses.
Carbon sequestration, where carbon dioxide is removed from flue gases before they are emitted into the atmosphere, diverts heat from the boiler to fuel the regeneration of chemicals used in capturing the carbon. This results in reduced efficiency on an operating plant of about 10–12 %. One way to offset this is to increase operating temperatures and pressures. Modern plants can now operate at higher temperatures, thanks to advances in materials and coatings, and their reducing cost. But higher-temperature combustion accelerates corrosion rates in conventional alloys. Similarly, higher steam temperatures influence material performance by accelerating oxidation and creep rates.
Another method of making these plants greener is moving partially or wholly to alternative fuels. This is being introduced through retrofitting coal plants to combine coal burning with biomass, or moving to 100% biomass firing. But the term 'biomass' covers a diverse range of fuels with varying alkali salts (potassium, chlorine, sulphur, etc) content, leading to different corrosion rates and mechanisms. These are not fully understood, so there is work to be done to assess how to replace or coat boiler materials to match current corrosion rates and hence plant longevity.
To ensure that more environmentally-friendly approaches can be pursued, without adversely affecting electricity prices, considerable research is being undertaken into new materials and coatings. Organisations such as the National Physical Laboratory (NPL) have been working closely with energy companies to help them model the behaviour of alloys and coatings, to demonstrate how they will degrade under real-world operating conditions.
The first step is to conduct laboratory-scale tests with a range of materials and coating, to gather data on how they respond. For fire-side corrosion testing, a tube furnace is used with the sample placed inside and sealed. Simulated combustion gases are produced, based on the energy companies' measured service conditions. These are introduced at one end of the tube and allowed to flow over the sample to the exit. The tube is thermally cycled and a range of salt deposits used to simulate both uniform and fluctuating power plant temperatures to test how different fuel and temperature combinations affect the material.
Exposures to simulate steam-side oxidation are more straightforward, as there are no molten salt deposits. This is about straight corrosion, with oxides forming on the tubes, thickening and spalling off. So tests tend to be performed at atmospheric pressure – although NPL does have a recirculating high-pressure steam loop that can mimic the effects of pressure on oxidation rates.
Either way, sacrificial coatings are considered a cost-effective method to mitigate against higher corrosion rates. They are cost effective and easier to deploy than replacing large amounts of tubing. And centres such as NPL offer a range of atmospheric testing tools for measuring coating oxidation rates with different temperatures and steam chemistries. These can look at the kinetics of reactions under simulated conditions and material wastage rates.
But any laboratory-based modelling process has its limitations. In a real plant, exposure conditions cannot be as well controlled as in the laboratory, so extrapolation to long durations under changing conditions results in large uncertainties. However, by combining laboratory-based measurements with ultrasonic measurement data taken from long-term studies in real power plants, reasonably accurate predictions can be made.
To do this, NPL has developed a neural network computer model that uses plant condition data to predict real metal wastage rates. Information from partners such as E.On, RWE npower and Doosan Babcock Energy, allows the network to learn how materials in power plants are affected over time. We then input key parameters from our laboratory tests to reflect different materials and conditions, and the network uses this information to predict degradation rates.
A number of funded projects have recently brought NPL together with industry to work on developing novel solutions. The Technology Strategy Board (TSB)-funded ASPECT project, for example, identified potential coatings for fire- and steam-side tubes and pipes in both coal- and co-fired plants. As a result, a fire-side coating has since been installed in a power plant and its performance is due to be assessed under the EC-funded Nextgen power project. Meanwhile, a steam-side coating that showed promise is subject to continuing study under the Macplus project. If all goes as hoped, these could be in use in the near future.
Following ASPECT, a new TSB-funded project ASPIRE commenced last year to look at coatings for 100% biomass-fired plants. This is a much bigger step into unknown territory, as long-term measurements taken by power plants relate to the effects of coal combustion gases. So a new burner rig has been built at NPL, which will allow us to inject salt solutions and replicate deposits that would form in service when biomass is burned. This will give us an idea of deposition rates and chemistry, from a thermodynamic perspective, for feeding into the neural network model.
Finding the right materials is not just about competitive advantage. It's about continued, efficient plant operation but with reduced emissions. So it is in everyone's interest to find the best solution. Collaborative projects between industry and academia, capable of simulating power plant conditions, can help everyone in the industry by identifying the best, most cost-effective materials before they are put into use.
Tony Fry is principal research scientist at the National Physical Laboratory
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