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.     

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.     

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.     

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.     

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.     

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.     

Trace elements partitioning during co-firing biomass with lignite in a pilot-scale fluidized bed combustor

This study describes the partitioning of 18 trace elements (As, Ba, Cd, Co, Cr, Cu, Li, Mn, Mo, Ni, P, Pb, Sb, Se, Sn, Tl, V, Zn) and 9 major and minor elements (Al, Ca, Fe, K, Mg, Na, S, Si, Ti) during co-firing of olive residue, hazelnut shell and cotton residue with high sulfur and ash content lignite in 0.3 MW(t) Middle East Technical University (METU) Atmospheric Bubbling Fluidized Bed Combustor (ABFBC) test rig with limestone addition. Concentrations of trace elements in coal, biomass, limestone, bottom ash, cyclone ash and filter ash were determined by inductively coupled plasma optical emission and mass spectroscopy (ICP-OES and ICP-MS). Partitioning of major and minor elements are influenced by the ash split between the bottom ash and fly ash and that the major proportion of most of the trace elements (As, Ba, Co, Cr, Cu, Li, Mn, Mo, Ni, Pb, Tl, V and Zn) are recovered in fly ash when firing lignite only. Co-firing lignite with biomass enhances partitioning of these elements to fly ash. Co-firing also shifts the partitioning of Cd, P, Sb and Sn from bottom to fly ash.     

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.     

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.     

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.     

Influence of additives on electrodeposition of bright Zn-Ni alloy on mild steel from acid sulphate bath

The influence of a condensation product (CP) of veratraldehyde (VRTD) and p-amino benzoic acid (PABA) on Zn-Ni alloy electrodeposited onto mild steel was studied in acidic sulphate solutions. Ethylenediaminetetraaceticacid (EDTA) and cetyltrimethylammoniumbromide (CTAB) were used as complexing and wetting agents, respectively. The effect of bath constituents, pH, current density and temperature on nature of deposit were studied through Hull cell experiments. The bath constituents and operating parameters were optimized. Deposit properties and corrosion resistance were discussed. Throwing power, current efficiency and polarization studies were carried out. SEM photomicrographs of the deposit obtained from optimum bath revealed fine-grained deposit of the alloy in the presence of condensation product and hence modified the morphology of zinc-nickel alloy deposit. IR spectrum of the scrapped deposit showed inclusion of addition agent.     

Chemical analysis of solid residue from liquid and solid fuel combustion: Method development and validation

This paper deals with the development and validation of methods for identifying the composition of solid residue after liquid and solid fuel combustion in thermal power plant furnaces. The methods were developed for energy dispersive X‐ray fluorescence (EDXRF) spectrometer analysis. Due to the fuels used, the different composition and the location of creation of solid residue, it was necessary to develop two methods. The first method is used for identifying solid residue composition after fuel oil combustion (Method 1), while the second method is used for identifying solid residue composition after the combustion of solid fuels, i. e. coal (Method 2). Method calibration was performed on sets of 12 (Method 1) and 6 (Method 2) certified reference materials (CRM). CRMs and analysis test samples were prepared in pellet form using hydraulic press. For the purpose of method validation the linearity, accuracy, precision and specificity were determined, and the measurement uncertainty of methods for each analyte separately was assessed. The methods were applied in the analysis of real furnace residue samples.     

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.     

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.     

Stress corrosion cracking of maraging steel weldments

Abstract

The stress corrosion characteristics of 18 wt-%Ni (MDN-250) maraging steel and its weldments made under different welding conditions have been investigated. The threshold stress intensity factor K _ISCC in stress corrosion conditions has been determined in 3.5 wt-%NaCl environment for the base metal and weldments. The fractured surfaces were analysed to study the types of fracture during stress corrosion cracking in base and weld metals. Fracture toughness tests were carried out and the results obtained from these tests have been compared with K _ISCC values.     

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.     

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     

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.     

The surface chemistry of leaching coal fly ash

The utilization of coal fly ash in the construction and non-construction areas has seen a rapid growth in the last decade. As production outweighs the utilization of fly ash, its disposal as a dilute or dense slurry is still practiced in coal fired power stations. In this review the surface chemistry of leaching coal fly ash is presented to highlight the role of mass transfer in providing resistance and consequently delayed leaching of elements, when fly ash is disposed or used for value addition.     

Results of studying atmospheric corrosion in Vietnam 1995–2005

Vietnam is situated in the wet tropical zone; thus, atmospheric conditions are characterized by high temperatures and a long time of wetness (TOW). In addition, the salt air coming in from the sea causes a high chloride concentration in coastal areas. Furthermore, Vietnam is a developing country, which means that air pollution is increasing with the development of industry. These factors result in significant damage to materials by atmospheric corrosion. In this report, the results of a recent study on the corrosion of carbon steel and zinc-galvanized steel at 6–8 testing sites in Vietnam over 10 recent years (1995–2005) are focused on as well as the effects of environmental factors on atmospheric corrosion. The results showed that the corrosion of carbon steel is dominated by TOW, whereas zinc-galvanized-steel corrosion strongly depends on the chloride ion concentration in the air. The corrosion losses of both carbon- and zinc-galvanized steel fit the power model well with high correlation coefficients. In addition, the characteristics of the Vietnamese climate are introduced in the form of distribution maps of temperature (T), relative humidity (RH), total rainfall and TOW. A relationship between TOW, T and RH was found that enabled the calculation of TOW from T and RH data, which are available at meteorological stations. Finally, atmospheric corrosivity is determined on the basis of data on TOW, Cl^– and SO₂ concentrations, and the carbon steel corrosion rate. It is shown that in Vietnam, TOW is so long that the corrosion rate of carbon steel is in the C₃ category; nevertheless, Cl^– and SO₂ concentrations in the atmosphere are not high.