Degradation of heat exchanger materials under biomass co-firing conditions

Abstract

Co-firing biomass in conventional pulverised coal fired power stations offers a means to rapidly introduce renewable and CO₂ neutral biomass fuels into the power generation market. Existing coalfired power stations are both much larger and more efficient than current designs of new biomass combustion systems, so feeding a few percent of biomass feed into an existing large coal fired station will give more biomass derived power than a new dedicated biomass station. Co-firing levels started at ～2% biomass, but this has increased to ～5–10% biomass, with higher levels of biomass co-firing being investigated, although supply of biomass becomes an issue with increasing co-firing levels. The lower levels of biomass co-firing (up to ～5%) can be achieved with relatively minor modifications to existing plants, so avoiding the large capital costs and risks of building new biomass-only fired power systems. However higher levels of co-firing are more difficult to achieve, requiring dedicated biomass supply systems and burners. For existing coal-fired power stations, the co-firing of biomass causes some practical problems, e.g.: the control of co-firing two fuels; changes to bottom/fly ash chemistry; changes to deposition (fouling and slagging) within the boiler; reduced reliability of key high temperature components (e.g. heat exchangers) due to increased corrosion problems relative to those experienced with coal alone.

This paper reports the results of assessments carried out to evaluate the potential operating conditions of heat exchangers in combustion systems with biomass (wood or straw) and coal cofiring, as well as laboratory corrosion tests that have been carried out to give an initial assessment of potential effects of biomass-co-firing.

The corrosion tests have been carried out using the deposit recoat method in controlled atmosphere furnaces. A series of 1000 hour tests have been carried out at typical superheater and evaporator metal temperatures using simulated deposit compositions and gaseous environments (selected on the basis of plant experience and potential fuel compositions). Five materials were exposed in these tests: 1Cr steel, T22 steel, X20CrMoV121, TP347HFG and alloy 625. In order to produce statistically valid data on the actual metal loss from the materials, the performance of the materials in these tests was determined from dimensional metrology before and after exposure. For each material, these data have been used to determine the sensitivity of the corrosion damage to changes in the exposure conditions (e.g. deposit composition, gas composition) thereby producing initial models of the corrosion performance of the materials. The corrosion data and model outputs have been compared with data available from power plants operating on coal, straw or wood fuels.     

Probes to monitor in-plant material degradation

Abstract

Fireside corrosion in coal fired boilers has been well-investigated. The main causes of water wall fireside corrosion are: (1) impurities in the fuel, such as sulphur alkali metals and chlorine; (2) the lack of control of the combustion process resulting in a reducing gaseous environment at the tube surface; (3) flame impingement; and (4) overtemperature of tube metal.

Co-firing secondary fuels in coal fired boilers is becoming common practice in many power stations in Europe. Secondary fuels like wood, refuse derived fuels, meat and bone meal, straw, poultry litter or mixtures of several secondary fuels are co-fired up to 20-wt%.

Most of these biomass fuels contain high concentrations of alkali chlorides. Considering the composition of these fuels, limitations on the maximum amount of secondary fuels to be co-fired in coal fired boilers are expected.

In addition to the environmental benefits from biomass fired power plants, co-firing can result in “green” power labelling and governmental subsidy. Also savings on fuel costs may be a driving force for an increase of the amount of biomass or secondary fuels to be co-fired.

However, without corrosion monitoring, short-term policies concerning co-firing secondary fuels in large volumes can lead to high costs in the medium or long term. These costs can be due to corrosion damage both in the furnace and superheater sections and penalties due to unplanned outages in a highly competitive electricity market.

This paper summarizes practical experiences from corrosion monitoring programs with KEMA corrosion probes. The first prototype was successfully tested in 1997 at the Hemweg Unit 8 coal fired power plant of Reliant Energy in Amsterdam, the Netherlands. Other corrosion monitoring programs were carried out at coal fired power plants and at a waste incineration plant.

At present a large-scale corrosion monitoring and material testing program is in progress at the Maasvlakte power station Unit 1 near Rotterdam, the Netherlands. In this 520 MWe power plant of E.on Benelux more than 10-wt% of mixtures of secondary fuels are directly co-fired.

In addition to aspects such as emissions, fuel handling and fuel cost savings, co-firing secondary fuels requires corrosion monitoring to check the tolerance to different fuel types of coal fired boilers.     

Rates of fireside corrosion of superheater and reheater tubes: making sense of available data

Abstract

Interpretation and use of a body of field data for corrosion of superheater and reheater (SH/RH) tubes in coal fired boilers was found to be unsatisfactory without some indication of how the corrosive environment encountered differed when different coals were burned. A new factor intended to represent the relative corrosion potential (RCP) of the coal burned is suggested, based on the accepted mechanism of accelerated corrosion of SH/RH tubes by the development of low melting complex sulphates beneath ash deposits. Initial testing of the RCP concept was encouraging, given the difficulty in some cases of ensuring accurate representation of the actual coal burned during the corrosion exposures. However, some data suggested that new boiler operating modes, such as various approaches to emissions reduction through staging of the combustion process, appeared to be capable of causing significantly more rapid corrosion of SH/RH tubes than would be expected from the RCP value for the coal. Although increased corrosion with some emissions control systems has been recognised in practice, understanding of the particular corrosion process involved is lacking. Some degree of mechanistic understanding of the key features of this form of corrosion is needed to provide a firm basis for application of concepts such as RCP or development of improved versions.     

Microstructural investigations of Ni and Ni2Al3 coatings exposed in biomass power plants

Abstract

The present work investigates the corrosion resistance of Ni and Ni₂Al₃ coated austenitic stainless steel (TP347H) tubes, which were exposed in a biomass-fired boiler with an outlet steam temperature of 540 °C for 6757 h. The Ni₂Al₃ coating was produced by electroplating Ni followed by low temperature pack cementation. After exposure, microstructural investigations were performed by light optical and electron microscopy (SEM-EDS). Electroplated Ni coatings were not protective in straw firing power plants and exhibited similar corrosion morphology as uncoated tubes. For Ni₂Al₃ coatings, the nickel aluminide layer was no longer adherent to the tube and was only found within the deposit. However, Ni₂Al₃ coatings had provided some protection compared to uncoated and Ni coated tubes. The formation of nickel chloride binds aggressive chlorine and slows down the active oxidation mechanism. In local areas, sulphidation corrosion attack of Ni was detected.     

Influence of nickel alloying on hot corrosion of stainless steels in SO2-environment

Flue dust produced by copper flash smelting causes problems by forming corrosive melts on the walls of heat recovery boiler used to recover the process heat value and to separate flue dust from SO₂-rich gas, derived from smelting sulphidic copper ore, before manufacture of sulphuric acid. The corrosion phenomena of molybdenum containing low and high nickel stainless steels AISI 316 and Sanicro 28 were studied by simulating the conditions prevailing in the heat recovery boiler in laboratory in the temperature range of 250–350°C. ZnCl₂ in copper smelter flue dust resulted in partial melting of the deposit containing sulphates and oxides of copper, zinc, arsenic, iron and lead, which increased the rate of corrosion dramatically. Chlorination of the steel was the dominant corrosion mechanism. The high nickel steel corroded more than low nickel steel due to reactivity of nickel under molten sulphates.     

Boiler corrosion and monitoring

Abstract

Results of a collaborative effort to investigate and develop solutions for key material issues affecting the performance of large-scale coal-fired boilers operating at advanced conditions is presented. Advanced conditions include advanced steam temperatures, oxyfuel firing, and co-firing biomass materials. A series of laboratory experimental results are presented on fireside corrosion in environments representing air-, and oxy-fired conditions, and with coal and/or biomass as the fuel. The effects of fluctuating reducing atmospheres and heat flux effects were examined. A variety of boiler corrosion probes and sensors were developed and tested. The probes measured corrosion by section loss and the sensors by electrochemical techniques including electrochemical noise. The probes were tested in coal and waste-to-energy boilers. Correlations between section loss probes and electrochemical noise sensors allow for real-time corrosion rate measurements to be made that allow for changes in boiler operations to be tracked in terms of corrosion effects.     

Failure analysis and retrofitting of superheater tubes in utility boiler

The extreme spray water mass flow rate deviation was observed to occur in the middle temperature superheater of Sahand 2 × 325 MW Power Plant utility boiler, which severely affected its economic performance and safe operation. Boilers operating in these conditions led to failure in superheater tubes at the same place for two consecutive times in a three year span. Thus, the failure analysis of superheater tubes by investigating the visual inspection, chemical, scale and creep analysis was carried out. The brittle failure occurred in the superheater tubes after the fuel was changed from natural gas to heavy oil. Failure analysis showed that tubes were suffering from long term overheating which was instigated by high spray water flow rate. In order to rectify the boiler operating conditions, some modifications were applied in the boiler unit 1 and operating parameters on this boiler were compared with boiler unit 2. The results showed that the 8.33% reduction in heating surface area corresponds to 52.84 and 17.80% reduction in spray water mass flow rate for capacities equal to 300 and 260 MW, respectively.     

ANN–GA approach for predictive modeling and optimization of NOx emission in a tangentially fired boiler

An artificial neural network (ANN) and genetic algorithm (GA) approach to predict NOx emission of a 210 MW capacity pulverized coal-fired boiler and combustion parameter optimization to reduce NOx emission in flue gas, is proposed. The effects of oxygen concentration in flue gas, coal properties, coal flow, boiler load, air distribution scheme, flue gas outlet temperature, and nozzle tilt were studied. The data collected from parametric field experiments was used to build a feed-forward back-propagation neural net. The coal combustion parameters were used as inputs and NOx emission as outputs of the model. The ANN model was developed for full load conditions and its predicted values were verified with the actual values. The algebraic equation containing weights and biases of the trained net was used as fitness function in GA. The genetic search was used to find the optimum level of input operating conditions corresponding to low NOx emission. The results proved that the proposed approach could be used for generating feasible operating conditions.     

Corrosion behavior of candidate heat exchanger materials in oxidizing and reducing gases relevant to oxyfuel power plants

Abstract

In the present paper, the oxidation behavior of potentially suitable construction materials for heat exchanging components in coal fired power plants was studied in the temperature range 550–700 °C. The selected materials (low alloy steel 13CrMo44, martensitic steel P92, austenitic steel S304HCu and Ni-base alloy 617) were exposed in a simulated atmosphere typical for oxyfuel combustion and the results were compared with the behavior in a test gas simulating oxyfuel gas with addition of CO, thus simulating locally occurring reducing operating conditions which may happen due to incomplete combustion. The oxidation/corrosion behavior was studied by gravimetry in combination with a number of characterization methods such as optical microscopy, scanning electron microscopy with energy dispersive X-ray analysis (SEM/EDX) and glow discharge optical emission spectroscopy (GDOES). For the low alloy steel and P92 only minor differences in oxidation rates between the different environments were found. For S304HCu generally smaller corrosion rates were found in the reducing gas, whereas for alloy 617 the effect of gas composition depended on temperature. The obtained results are interpreted on the basis of thermodynamic considerations comparing equilibrium activities of the main species in the gas atmospheres with the thermodynamic stabilities of various possible corrosion products.     

Corrosion behaviour of four high temperature engineering materials exposed to landfill gas engine flue gas

Abstract

Four engineering materials commonly used in high-temperature applications were exposed to landfill gas engine flue gas for 25 days at 411°C. The flue gas was composed mostly of nitrogen and oxygen, although some carbon monoxide and hydrocarbons were detected together with low concentrations of hydrogen chloride gas and sulphur oxides. Hydrogen fluoride was not analysed, but, due to the nature of the fuel, may have been present at low levels. The materials tested were a carbon steel, a low alloy steel, a 12%Cr stainless steel and an austenitic stainless steel. Thin, protective films were formed on the 12%Cr and austenitic stainless steels, however, the corrosion products formed on carbon and low-alloy steels consisted of several layers, the outermost of which were extremely friable and non-adherent, especially on cooling from the flue gas working temperature. The maximum corrosion rate obtained was 70 μm yr^–1 for carbon steel, which may be acceptable for a number of flue gas applications. The exposed coupons were examined using conventional techniques such as X-ray diffraction (XRD), optical microscopy (OM) and scanning electron microscopy (SEM). The predominant scale formation mechanism controlling the corrosion appeared to be simple oxidation type reactions, however, the influence of HCl, as evidenced by the presence of akaganeite (β-FeO(OH)), was hypothesised. A model describing the corrosion mechanism is proposed in order to provide an improved life prediction capability for such flue gas environments.     

Metallographic investigations of the failed superheater tubes used in liquid hydrogen plant

2.25Cr–1Mo low alloy steel tubes of diameter 42.5 mm ID and 46.5 mm OD were used in superheater of liquid hydrogen plant. This superheater had 10 rows of tubes for carrying naphtha and steam and is heated by flue gas. The flue gas directly impinges on the first three tubes of the tube bank. A failure occurred in the first tube leading to the removal of a portion of the material causing to shut down of the plant.Detailed metallurgical investigations were carried out to understand the cause of failure. This paper brings out the metallographic investigations on the failed tubes and the necessary remedial actions thereon.     

Remnant life assessment of service-exposed pendent superheater tubes

Remnant life assessment and life extension has become an integral part of plant maintenance activities, Cr–Mo steels are widely used in thermal power plants at a temperature of about 550°C. This paper deals with the high temperature tensile and creep rupture properties of 1Cr–0.5Mo steels for pendent superheater tubes in a boiler of a thermal power plant after five years service exposure for 43,000 h. Based on stress vs Larson Miller Parameter plot and at the operating hoop stress level, the pendent superheater tubes in general are found to be in a good state of health and can continue to remain in service for a length of 10 years, provided the temperature of the tube is brought down below 500°C. This observation may not be true for those selected tubes where already expansion in the diameter has taken place. Such tubes should be identified and replaced. In the case that it is not possible to bring down the temperature below 500°C, it may be desirable to use a superior grade of material like 2.25Cr–1Mo or 9Cr–1Mo steel. A thicker tube of the same grade may also be considered provided the overall load of the panel does not exceed the limit. It is, however, recommended that a similar health check be carried out after five years.     

Waterwall corrosion in pulverized coal burning boilers: root causes and wastage predictions

Abstract

Waterwall corrosion has become a serious problem in the USA since the introduction of combustion systems, designed to lower NO_x emissions. Previous papers have shown that the main cause of the increased corrosion is the deposition of corrodants, iron sulfides and alkali chlorides, which occurs under reducing conditions. In this paper, the contribution of various variables such as the amount of corrodant in the deposit, the flue gas composition and the metal temperature, is further quantified in laboratory tests, using a test furnace allowing thermal gradients across the deposit and the metal tube samples. Approximate deposit compositions were calculated from the coal composition, its associated ash constituents and corrosive impurities. A commercially available thermochemical equilibrium package was used, after modifications to reflect empirical alkali availability data. Predictions from these calculations agreed reasonably well with the alkali chloride and FeS content found in actual boiler deposits. Thus approximate corrosion rates can be predicted from the chemical composition of the coal using corrosion rates from laboratory tests, adjusted to account for the short duration (100 hours) of the laboratory tests. Reasonable agreement was again obtained between actual and predicted results.     

Determination of correlation functions of the oxide scale growth and the temperature increase

In this paper, a method for estimating the scale growth of superheater and reheater tubes of boiler and generating the constant B which is correlating the scale growth and the increased tube metal temperature, for different operational conditions is reported. This method utilizes an empirical formula correlating the scale thickness with Larson-Miller Parameter (LMP). Finite element modeling to estimate the scale thickness on the inner surface of the tube over period of time is developed. The effects of tube geometry, mass flow rate and temperature of steam, flue gas temperature and the convection coefficient on the external surface of the tube that influenced the temperature increase in the tube metal are examined. The present results provide better estimation of the oxide scale growth and temperature increase over period of time.     

Creep properties and damage behaviour of component-like tubes of Vm12-materials

Abstract

The gap in the energy supply between current availability and the rising demand for electricity worldwide has to be closed primarily by using modern steam and gas power stations with an increased degree of efficiency and decreased CO₂ emissions. Target values for reaching a high degree of efficiency of ≥50% demand increase the steam parameters. The modern creep-resistant steels and their weldments have to have both high creep rupture strength and corrosion resistance.

Within the European research programme COST 536, between 2005 and 2009 research and development work in the field of power plant steels had been carried out for conventional applications. The project was focused on the development of appropriate materials, coatings and surface treatments for components in steam power plants with steam inlet temperatures in the turbine of up to 650°C.

In framework COST 536, Siempelkamp Pruef- und Gutachter-Gesellschaft mbH (SPG) performed component-like creep tests at pressurized tubes made of martensitic steel VM12. This steel was developed by Vallourec & Mannesmann Tubes with the aim of reaching both sufficient creep strength and increased oxidation resistance and is already used for boiler application in new power plants in Germany.

In this paper, the experimental results of uniaxial creep tests, component-like creep tests on tubes with inner pressure and axial loading, metallographic examination and damage characterisation are presented. The tubes are equipped with capacitive high temperature strain gauges for on-line monitoring of strain. All testing data will be implemented as inputs for the numeric FE analysis. The effect of multiaxiality and stress redistribution will be discussed.     

Erosion-corrosion behaviour of Ni-based superalloy Superni-75 in the real service environment of the boiler

The super-heater and re-heater tubes of the boilers used in thermal power plants are subjected to unacceptable levels of surface degradation by the combined effect of erosion-corrosion mechanism, resulting in the tube wall thinning and premature failure. The nickel-based superalloys can be used as boiler tube materials to increase the service life of the boilers, especially for the new generation ultra-supercritical boilers. The aim of the present investigation is to evaluate the erosion-corrosion behaviour of Ni-based superalloy Superni-75 in the real service environment of the coal-fired boiler of a thermal power plant. The cyclic experimental study was performed for 1000 h in the platen superheater zone of the coal-fired boiler where the temperature was around 900°C. The corrosion products have been characterized with respect to surface morphology, phase composition and element concentration using the combined techniques of X-ray diffractometry (XRD), scanning electron microscopy/energy-dispersive analysis (SEM/EDAX) and electron probe micro analyser (EPMA). The Superni-75 performed well in the coal-fired boiler environment, which has been attributed mainly to the formation of a thick band of chromium in scale due to selective oxidation of the chromium.     

Designing P92 grade martensitic steel header pipes against creep–fatigue interaction loading condition: Damage micromechanisms

The boiler tubes and pipes in the present day coal fired power plants are designed against damage arising from the interaction of creep and fatigue. The present investigation reports the microstructural evolution in P92 grade martensitic steel during pure fatigue and hold time fatigue tests conducted at 600 °C. Fatigue life significantly dropped for hold time fatigue tests in comparison with pure fatigue tests. The drop in fatigue life was more for hold time fatigue tests conducted with compressive hold. Grain boundary oxidation and cracking was identified as the major cause for the decrease in fatigue life under compressive hold. Annihilation of dislocations and pinning of dislocations by MX precipitates were observed to be the microstructural changes during cyclic deformation.     

Assessment of polyester and polyvinylester coatings in a simulated FGD scrubbing liquid with EIS

Abstract

Corrosion behaviours of carbon steel coated with polyester and polyvinylester in a simulated flue gas desulphurisation (FGD) fluid (i.e., a mixture of H₂SO₄ and 0.1 wt% Fe₂(SO₄)₃ at pH=2) have been investigated with electrochemical impedance spectroscopy (EIS). The protective nature of the coatings at 25°C has been observed in the following order: polyvinylester primer >> polyvinylester topcoat > polyester topcoat > polyester primer. Coating deterioration occurred and the coating deterioration rate accelerated with increasing temperatures upto 85°C. However, the corrosion resistance sequence has remained the same. Equivalent circuits are suggested for various coatings to discuss their mechanisms in this work.     

Pitting corrosion of steel tubes in an air preheater

Severe pitting corrosion of a carbon steel tube was observed in the air preheater of a power plant, which runs on rice straw firing. Approximately 1450 tubes were removed from Stage 3 of the preheater (air inlet and flue gas outlet) due to corrosion and local bursting. Samples from Stage 2 (where corrosion was low) and Stage 3 (severe corrosion) were taken and subjected to visual inspection, scanning electron microscopy (SEM), X-ray diffraction (XRD), microhardness measurement, and chemical and microstructural analysis. It was determined that extended non-operation of the plant resulted in the settlement of corrosive species on the tubes in Stage 3. The complete failure of the tube occurred due to diffusion of these elements into the base metal and precipitation of potassium and chlorine compounds along the grain boundaries, with subsequent dislodging of grains. The nonmetallic inclusions acted as nucleating sites for local pitting bursting. Nonuniform heat transfer in Stage 3 operation accelerated the selective corrosion of front-end tubes. The relatively high heat transfer in this stage resulted in condensation of some corrosive gases and consequent corrosion. Continuous operation of the plant with some precautions during assembly of the tubes reduced the corrosion problem.     

新疆某电厂#1机组排烟余热回收系统的设计与运行

论述了新疆某厂一期锅炉增设烟气余热回收系统（LLHS）降低排烟温度的技术路线及节能效果,提出热系统参数的优化原则及纯凝-供热联合系统切换运行模式。增设LLHS后排烟温度降低不小于25℃。机组年均供电煤耗降低2.56g/kWh（含供热期）,每台锅炉年节省标煤2270t,年节水量4.37万t,减少烟囱内净烟气含水率24%,为脱硫系统正常运行提供了保证。