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.     

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.     

Field test corrosion experiences when co-firing straw and coal: 10 year status within Elsam

Abstract

In Denmark, straw is utilised for the generation of energy and district heating in power plants. Combustion of straw gives rise to high contents of potassium chloride and some sulphur dioxide in the flue gas. These compounds can lead to deposits with high content of potassium chloride and potassium sulphate on superheater tubes resulting in increased corrosion rates. From field experimental results this paper show, that by co-firing straw with coal, corrosion rates can be brought down to an acceptable level.

This paper firstly deals with the results from a demonstration program co-firing coal and straw at the 150MW pulverized coal fired boiler Studstrup unit 1. Two exposure series lasting 3000 hours each were performed for co-firing 10 and 20% of straw (% energy basis) with coal. Using built in test tubes in the hot end of the actual superheaters and air/water cooled corrosion probes, the corrosion during these experiments was monitored. Various ferritic and austenitic materials were investigated at steam temperatures ranging from 520 to 580°C and flue gas temperatures ranging from 925 to 1100°C.

The results obtained in the demonstration program led to the rebuilding of the 350MW pulverized coal fired boiler, Studstrup unit 4, into a co-firing boiler with straw in 2002. During the rebuilding, test tube sections of X20CrMoV12 1 and TP347H FG were built into the superheater and the reheater loops. The temperature ranges during these exposures was for the steam from 470 to 575°C and for the flue gas from 1025 to 1300°C. All these test tubes have been removed during the last three years at one year intervals for corrosion studies.

The corrosion studies performed on all investigated tubes included measurements of the corrosion attack, light optical microscopy and scanning electron microscopy of the corrosion products.     

Effects of Pb–B–Si–O glass on the microstructures and electrical properties of silver electrode for LTCC application

The co-firing compatibility between green tape and the Ag electrode is a crucial characteristic in low-temperature co-fired ceramic (LTCC) technology and plays a vital role in improving the performance and application status of LTCC device modules. In this work, we studied the effects of lead content on the glass viscosity, the microstructure, and co-firing compatibility of silver electrode film. It was found that the softening point and viscosity of the glass were decreased, and the wettability between the glass and silver was improved with the increase of the lead content, which promoted the co-firing densification and interfacial bonding between the silver electrode film and the ceramic layer. The film presented the best electrical properties co-firing at 875 °C for 15 min, with the resistivity of 1.21 mΩ/sq. And the film was densified. The sintering interface was clear and well bonded. The results showed that an appropriate lead content in glass could effectively improve the interfacial bonding and the electrical properties during co-fired process, providing a new control methodology for realizing co-fired matching of the silver electrode film with low-temperature co-fired ceramics.

     

Simulated fireside corrosion of T91 in oxy-combustion systems with an emphasis on coal/biomass environments

Oxy-combustion is the burning of a fuel in oxygen rather than air for the ease of capture of CO₂ for reuse or sequestration. Corrosion issues associated with the change in heat exchanger tube operating environment (replacement of most of the N₂ with CO₂ and potentially higher SO_x levels) from air- to oxy-combustion were examined. The ferritic-martensitic alloy T91 was used in accelerated fireside corrosion tests using several different gas compositions and ash deposit overcoats to simulate air-fired, oxy-fired coal, and oxy-fired co-fired coal/biomass conditions. Initial corrosion was observed after 240 h of exposure by examining cross-sections with retained ash. Metal section losses were determined after exposures of up to 1440 h at 600–700°C. Severe corrosion was observed, and a corrosion response with respect to ash deposit chemistry was observed. Corrosion response differences with respect to gas phase chemistry were minimal. Alloy-oxide scale-ash morphologies were consistent with oxide fluxing mechanisms.     

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.     

竹材废弃物作为工业锅炉燃料的研究

我国竹材资源在传统制作和工业加工过程中的重量利用率低于40%,有60%以上的竹材成为加工剩余物,竹材生物资源量巨大.竹材的硫和灰分含量仅为洁净煤质燃料的1/5~1/3,是一种非常洁净的燃料.竹材作为工业锅炉燃料时,含水量应控制在20%以下.燃煤锅炉改烧竹材燃料时,需对配风方案、进料机构和局部结构进行改进.竹材废弃物代油燃烧,具有明显的价格优势和环保效益.经济性分析结果表明,在竹材废弃物丰富的地区,开发燃用竹材废弃物的工业锅炉具有良好的经济性.     

Development and application of a methodology for the measurement of corrosion and erosion damage in laboratory,burner rig and plant environments

Abstract

Fuel gases derived from solid fuels such as coal, biomass and waste and their mixes have the potential to cause both erosion and corrosion damage to components in gas turbines and diesel engines. To allow the statistically valid assessment of materials performance in short term plant runs, burner rig tests and laboratory simulated environments a methodology has been developed to collect compatible quantitative data on materials degradation. Accurate measurement techniques based on pre-exposure contact metrology and post-exposure optical microscopy/image analysis have been developed. These take into account both the low level of damage required for practical systems and the localised nature of hot corrosion damage. The data produced have been used to derive and test quantitative models for the prediction of the performance of candidate materials in such power systems. For these models to be used with confidence, similar damage morphologies must be produced in both the real and simulated conditions, as well as similar damage rates.     

The effect of deposits on waterwall corrosion in fossil fueled boilers

Abstract

Corrosion of water walls in fossil fueled boilers and gasifiers has traditionally been considered the result of gaseous corrodants, such as H₂S and HC1, reacting with the heat exchanger tube surfaces. Under reducing conditions these corrodants prevent the formation of a protective oxide scale, leading to increased metal loss. Recent field experience in boilers, using staged combustion systems, has shown much greater corrosion rates than predicted by simple gas/solid corrosion processes. The presence of large quantities of unoxidized iron sulfide in deposits in areas where high corrosion rates were found, suggests that deposits play a role as well. Subsequent laboratory corrosion studies found that the presence of FeS can indeed lead to very high corrosion rates, but only under oxidizing conditions. Since FeS usually deposits only where reducing conditions are present, the accelerated corrosion observed requires alternating reducing and oxidizing conditions. These are usually found in load following boilers. It is also shown that chlorine corrosion may be caused or at least accelerated by chloride containing deposits in fossil fueled boilers, similar to waste incinerators, where the role of chloride rich deposits has been well established. Due to the relatively high sulfur content of fossil fuels, chloride deposits most likely form under reducing conditions only. However, once formed they can be highly corrosive under oxidizing conditions.     

Development of oxides at TBC – bond coat interfaces in burner rig exposures

Abstract

There is a desire to use gases derived from increasingly ‘dirty’ fuels (e.g. coal and biomass) in industrial gas turbines. The contaminants in these fuels have the potential to cause significant damage to the gas turbine hot gas path materials, many of which were developed and selected for natural gas fired conditions. This paper reports results of a study investigating the performance of thermal barrier coatings (TBCs) and bond coatings, applied to current industrial gas turbine materials, within clean and ‘dirty’ gas environments generated within a burner rig.

The materials covered by this study included: ? TBCs based on 8%Y₂O₃–ZrO₂ applied by both air plasma sprayed (APS) and electron beam – physical vapour deposition (EB–PVD) routes.

? Bond coats of the overlay and diffusion classes, applied by vacuum plasma spraying (VPS), electroplating (EP), chemical vapour deposition (CVD) and high velocity oxy-fuel (HVOF) spraying

? Base alloys of IN6203, CMSX-4 and Haynes 230

The required TBC/bond coat combinations were applied by commercial coating processes to cylindrical samples of base alloys manufactured for use in a burner rig.

The burner rig used in this study is designed to enable air-cooled probes of cylindrical samples to be exposed to a natural gas combustion environment. In this study, this enabled specific metal temperatures (~800 and ~900°C) to be targeted within a much higher temperature combustion gas stream (~1150°C). ‘Dirty’ fuel gas environments were simulated by introducing gaseous (SO₂ and HCl) and vapour phase (Na, K, Pb, Zn) contaminants into the burner rig just upstream of the edge of the gas flame. These conditions enabled continuous tests to be performed for 1,000 hours in both natural gas and ‘dirty’ fuel environments.

The relative performance of the materials was determined from cross-sections prepared after the 1000 hour exposures. These cross-sections were examined by optical and SEM/EDX to determine the thicknesses of the oxides at the TBC – bond coat interfaces, the morphologies of these interfaces and to characterise the elemental distributions in these regions.     

Evaluation of the emission characteristics of trace metals from coal and fuel oil fired power plants and their fate during combustion

Coal as well as fuel oil combustion generates emissions of potentially toxic trace pollutants including organic and inorganic chemical compounds besides major pollutants. A study on As, Cd, Co, Cr, Cu, Hg, Fe, Mn, Ni, Pb, Se, and Zn emissions from a 220 MW coal-fired power plant equipped with a electrostatic precipitators (ESPs) and 6 MW oil fired-power plant was carried out, using stack monitoring kit, Envirotech APM 620, which is similar to EPA Method 29. Simultaneous sampling of coal, fuel oil, oil waste, bottom ash, fly ash, flue gases, and particles associated with the gas phase has been performed. This sampling method was used for trace metal sampling. The content of all these metals in coal, oil, oil waste, bottom ash, fly ash have been determined by XRF, whereas their contents in the flue gases, and particles associated with the gas phase has been analyzed with ICP-AES. The mass balances obtained for trace elements were satisfactory in case of fuel oil based power plant, whereas in case of coal fired power plant, the mass balance for all the trace elements were below 50% except for the As, Se, and Hg. The enrichment factors for all trace metals was <1 in both cases. The above sampling method is moderately adequate method for trace element sampling in coal as well as oil fired power plants except for Hg. The results indicate that trace metals emissions were higher in coal-based power plant than the fuel oil-fired power plant.     

Alkali-activation potential of biomass-coal co-fired fly ash

Co-fired fly ash, derived from the co-combustion of coal and biomass, is examined as a potential precursor for geopolymers. Compared to a coal fly ash, two co-fired fly ashes have a lower vitreous content and higher carbon content, primarily due to differing combustion processing variables. As a result, binders produced with these co-fired fly ashes have reduced reaction potential. Nevertheless, compressive strengths are generally highest for all ashes activated with solutions with a molar ratio of SiO₂/(Na₂O + K₂O) = 1, and these mixes reach the highest extent of reaction among those studied. Activation with sodium hydroxide solution forms zeolitic phases for all ashes. The thermal and dilatometric behavior of the coal and co-fired fly ash geopolymers is similar between equivalent mix designs. These results indicate that co-fired fly ashes can be viably used to form alkali-activated geopolymers, which is a new beneficial end-use for these emerging waste materials.     

Corrosion evaluation of one dry desulfurization equipment – Circulating fluidized bed boiler

As a clean fuel combustion technology, circulating fluidized bed (CFB) possesses various advantages. Among them, flexibility in fuels and superiority in desulfurization are the two prominent ones and can hereby facilitate sufficient utilization of high-sulfur fuels. But unfortunately, these low-grade fuels always introduce harsh service environment within the CFB boilers and consequently result in severe degradation extent on relevant equipments, especially the high-temperature sulfur corrosion. In this event, by nearly ten characterization methods, comprehensive investigation was carried out on a whole CFB boiler during downtime, and special emphasis was particularly laid on the failure components including one perforated nozzle along with its fractured inlet tube for primary air, and one perforated manhole door of refeed valve. Finally, countermeasure and suggestion was put forward, which can provide instructive significance in corrosion prevention for the CFB boilers, even other desulfurization equipments, running under similar aggressive conditions in engineering practice.     

Performance limitations in electric power generating systems imposed by high temperature corrosion

The increasing cost of fuel has resulted in a renewed interest in improving the efficiency of electric power generating equipment. In most cases, this involves increasing the maximum temperature in the cycle. Examples include the increase in gas turbine inlet temperatures, the increase in steam temperature and pressure in boilers and the move towards higher temperature gasification in combined-cycle plants. In all these cases, the limits are set by the properties of the available materials. Among these limiting properties, the high temperature corrosion resistance ofmetals and alloys is vel}' significant.

High temperature oxidation rates set an absolute limit, but there are processes which can lead to accelerated corrosion, often associated with impurities in the fuel or air, which lower the available temperatures still further. A number of specific cases are discussed, the underlying principles are outlined and methods of overcoming the various problems are suggested.     

Possibilities and sustainability of “biomass for power” solutions in the case of a coal-based power utility

This paper investigates the possibilities and the sustainability of “biomass for power” solutions on a real power system. The case example is JP Elektroprivreda BiH d.d.—Sarajevo (EPBiH), a typical conventional coal-based power utility operating in the region of South East Europe. Biomass use is one of the solutions considered in EPBiH as a means of increasing shares of renewable energy sources (RES) in final energy production and reducing CO₂ emissions. This ultimately is a requirement for all conventional coal-based power utilities on track to meet their greenhouse gas (GHG) cut targets by 2050. The paper offers a discussion of possible options as a function of sustainability principles, considering environmental, economic and social aspects of biomass use. In the case of EPBiH, the most beneficial would be waste woody biomass and energy crop co-firing on existing coal-based power plants, as suggested by biomass market analyses and associated technological studies. To assess the sustainability of the different biomass co-firing options, a multicriteria sustainability assessment (MSA) and single criteria analysis (SCA) were used. Four different options were considered, based on different ratios of biomass for co-firing: 0 wt%-reference case, and 5, 7 and 10 wt% of biomass. Both the MSA and the SCA confirmed that the option with the highest share of biomass is the most preferable one for the considered case. In addition to that, the CO₂ parameter proved to be a key sustainability indicator, effecting the most decision making with regard to preference of options from the point of sustainability. Following up on the results of the analyses, the long-term projection of biomass use in EPBiH has shown an increase in biomass utilization of up to 450,000 t/y in 2030 and beyond, with associated CO₂ cuts of up to 395,000 t/y. This resulted in a 4 % CO₂ cut achieved with biomass co-firing, compared to the 1990 CO₂ emission level. It should be noted that the proposed assessment model for biomass use may be applied to any conventional coal-based power utility as an option in contributing to meeting specific CO₂ cut targets, provided that the set of input data is available and reliable.     

Application and optimisation of materials in valve train

Abstract

Recently the requirements imposed on parts in the valve train have significantly increased and different trends are apparent for different fuels. These fuels can be defined as conventional fuels, heavy fuels, and (natural) gas. For conventional fuels, no major differences exist between truck and marine engine applications. Owing to an increase in peak pressure and process temperature, new designs and materials are required in these fields of application. For heavy fuel applications, corrosion presents a continuing problem because of further increasing temperatures. Improved materials, surface protection, and heat transfer could reduce problems such as seat burning and corrosion on valve stems, valve heads, and guides. Varying compositions of natural gas and problems with the mixture control require the optimisation of the tribological system of valve seat–valve seat insert and an improvement in the behaviour of valve materials at elevated temperatures. Both technically and economically there are many problems to solve. This paper addresses the techniques and results of improvement and optimisation, for example, finite element analysis and test facilities, improvement and optimisation of valve steels, and the surface protection, heat transfer, design, and interactions between valve stem guide and the valve seat-seat insert.

MST/3156     

Amine versus ammonia absorption of CO<Subscript>2</Subscript> as a measure of reducing GHG emission: a critical analysis

Carbon dioxide (CO₂), one of the green house gases (GHGs) is well known for more than a century. Its emission from the combustion of fossil fuels in addition to other industrial sources is adversely affecting the climate on earth. Climate change is emerging as a risk all over the world that has generated public concern. Estimates have indicated that power production contributes to the tune of 70% of the total CO₂ released into the atmosphere from fossil fuel combustion worldwide. Capturing and securely storing CO₂ from the global combustion systems thus constitutes an important and achievable target. A legion of researchers have thus far developed absorbents to remove CO₂ from combustion facilities that are currently recognized globally as most effective. The cost of capturing CO₂ can be reduced by finding a low-cost solvent that can minimize energy requirements, equipment size, and corrosion. Monoethanolamine is being used for removing CO₂ from the exhaust streams and is a subject inculcated over a period of about last 80 odd years. Host of such other amines are being investigated and put into practice. However, commercializations of such operating plants for capturing CO₂ from power plants in the world are few and far between. On the other hand, aqueous ammonia is the other chemical solvent for capturing CO₂ that has proven experimentally to be more effective than amine-based processes. This communication aims at critically elucidating relative merits and demerits of ammonia and amine-based CO₂ capture options from the exhausts of coal fired thermal power plants (TPPs). It includes the life cycle CO₂ emissions for both the processes. Finally, it is estimated that a total emission of about 152 Mt CO₂-equivalent could occur after use of 100 Mt ammonium bicarbonate (NH₄HCO₃) as synthetic N-fertilizer that is about 50% of the total CO₂ captured (315 Mt) for producing the fertilizer, NH₄HCO₃. Clearly, this estimate demonstrates that the synthetic N-fertilizer, NH₄HCO₃, produced by NH₃ scrubbing of CO₂ from fossil fuel (e.g., coal) fired TPP could have a significant beneficial environmental impact so far as GHG emission is concerned.     

Assessment of accidental refinery wastewater discharge: a case study

Carbon dioxide (CO₂), one of the green house gases (GHGs) is well known for more than a century. Its emission from the combustion of fossil fuels in addition to other industrial sources is adversely affecting the climate on earth. Climate change is emerging as a risk all over the world that has generated public concern. Estimates have indicated that power production contributes to the tune of 70% of the total CO₂ released into the atmosphere from fossil fuel combustion worldwide. Capturing and securely storing CO₂ from the global combustion systems thus constitutes an important and achievable target. A legion of researchers have thus far developed absorbents to remove CO₂ from combustion facilities that are currently recognized globally as most effective. The cost of capturing CO₂ can be reduced by finding a low-cost solvent that can minimize energy requirements, equipment size, and corrosion. Monoethanolamine is being used for removing CO₂ from the exhaust streams and is a subject inculcated over a period of about last 80 odd years. Host of such other amines are being investigated and put into practice. However, commercializations of such operating plants for capturing CO₂ from power plants in the world are few and far between. On the other hand, aqueous ammonia is the other chemical solvent for capturing CO₂ that has proven experimentally to be more effective than amine-based processes. This communication aims at critically elucidating relative merits and demerits of ammonia and amine-based CO₂ capture options from the exhausts of coal fired thermal power plants (TPPs). It includes the life cycle CO₂ emissions for both the processes. Finally, it is estimated that a total emission of about 152 Mt CO₂-equivalent could occur after use of 100 Mt ammonium bicarbonate (NH₄HCO₃) as synthetic N-fertilizer that is about 50% of the total CO₂ captured (315 Mt) for producing the fertilizer, NH₄HCO₃. Clearly, this estimate demonstrates that the synthetic N-fertilizer, NH₄HCO₃, produced by NH₃ scrubbing of CO₂ from fossil fuel (e.g., coal) fired TPP could have a significant beneficial environmental impact so far as GHG emission is concerned.     

Prediction and real-time monitoring techniques for corrosion characterisation in furnaces

Abstract

Combustion modifications to minimise NO_x emissions have led to the existence of reducing conditions in furnaces. As regulations demand lower NO_x levels, it is possible (to a degree) to continue to address these requirements with increased levels of combustion air staging. However, in most practical situations, a number of adverse impacts prevent the application of deep combustion air staging. One of the more important limitations is the increased corrosion that can occur on wall tubes exposed to fuel rich combustion environments. Current boiler corrosion monitoring techniques rely on ultrasonic tube wall thickness measurements typically conducted over 12 to 24 month intervals during scheduled outages. Corrosion coupons are also sometimes used; typically require considerable exposure time to provide meaningful data. The major drawback of these methods is that corrosion information is obtained after the damage has been done. Management of boiler waterwall loss and system optimisation therefore requires a real-time indication of corrosion rate in susceptible regions of the furnace. This paper describes the results of a program of laboratory trials and field investigations and considers the use of an on-line technology in combination with innovative applications, also modelling and precision metrology to better manage waterwall loss in fossil fuelled boilers while minimising NO_x emissions.     

Co-Firing Characteristics of Cordierite Tapes with Ag/Pd for High Frequency Chip Inductors

As a new electronic material, low-temperature sintering, low-dielectric cordierite tapes exhibit great potential in the manufacturing of high frequency inductors. While the co-firing of cordierite dielectric material with conductive metal in lower sintering temperature is always a difficulty, and it directly affects the practical application of the inductors. In this paper, the prepared cordierite tapes with low-sintering temperature, low dielectric constant, and low losses were used as matrix material, and the co-firing characteristics of cordierite tapes with Ag/Pd was preliminary studied to investigate the feasibility in the manufacturing process. Deformation, pores, and delaminations are three main defects of the co-fired samples. With an Al₂O₃ powders and press blocks assisted process, good co-firing effect of cordierite tapes with Ag/Pd can be obtained at 900 °C. The co-firing interface of cordierite tape and Ag/Pd is very dense and no obvious element migration is detected. The paper is contributed to the manufacture of high frequency inductors.