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Results
Corrosion of Stainless Steel in Simulated Solid Oxide Fuel Cell Interconnect Environments
Ziomek-Moroz, Malgorzata (US Dept. of Energy) | Cramer, Stephen D. (US Dept. of Energy) | Covino, Bernard S. (US Dept. of Energy) | Holcomb, Gordon R. (US Dept. of Energy) | Bullard, Sophie J. (US Dept. of Energy) | Singh, Prabhakar (Pacific Northwest National Lab)
ABSTRACT Morphology and phase composition of the scales formed on 316L stainless steel in an environment simulating a solid oxide fuel cell (SOFC) interconnect were determined towards the corrosion behavior study of commercial and new alloys for SOFC stack and balance-of-plant (BOP) applications. The simulated SOFC environment consisted of a dual exposure condition with air on one side of the specimen and mixtures of hydrogen and water vapor on the other side at 907 oK. Surface characterization techniques, such as optical and scanning electron microscopy, energy dispersive X-ray spectroscopy as well as X-ray diffraction analysis were used in this study. Also, an attempt was made to correlate the experimental results with thermodynamic calculations. INTRODUCTION Fuel cells are galvanic cells, in which the free energy of a chemical reaction is converted into electrical energy via an electrical current. The anode reaction in fuel cells can be a direct oxidation of hydrogen, or the oxidation of methanol. An indirect oxidation via a steam-reforming step of hydrocarbons into a mixture of hydrogen and carbon monoxide can also occur. The cathode reaction is oxygen reduction, in most cases from air.1 The main characteristics of fuel cells is to convert chemical energy without the need of combustion, giving much higher conversion efficiencies than conventional methods, such as gas turbines because fuel cells are not subject to Carnot limit. Fuel cells utilize electrochemical oxidation so they have much lower carbon dioxide emissions than combustion-based technologies for the same power output. They also produce negligible amounts of environmentally unfriendly SOx and NOx, which are the main constituents of acid rain.1 There are several major types of fuel cells that are currently exist 1-4 namely: Alkaline Fuel Cells (AFC) Proton Exchange Membrane Fuel Cells or Polymer Electrolyte Membrane Fuel Cells (PEMFC) Direct Methanol Fuel Cells (DMFC) Phosphoric Acid Fuel Cells (PAFC) Molten Carbonate Fuel Cells (MCFC) Solid Oxide Fuel Cells (SOFC) The main difference between the different fuel cells is the material used for the electrolyte, and, therefore their operating temperature. An exception to this classification is the DMFC, where the fuel, methanol, is directly supplied to the anode. Table 1 shows an overview of the fuel cells listed above: TABLE 1 Overview of Fuel Cells currently in Use 1
- Energy > Renewable > Hydrogen (1.00)
- Energy > Energy Storage (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.75)
- Health, Safety, Environment & Sustainability > Sustainability/Social Responsibility > Sustainable development (1.00)
- Health, Safety, Environment & Sustainability > Environment > Climate change (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Materials and corrosion (1.00)
High Temperature Electrochemical Corrosion Rate Probes for Combustion Environments
Covino, Bernard S. (U.S. Department of Energy) | Bullard, Sophie J. (U.S. Department of Energy) | Cramer, Stephen D. (U.S. Department of Energy) | Holcomb, Gordon R. (U.S. Department of Energy) | Ziomek-Moroz, Malgorzata (U.S. Department of Energy) | Kane, Russell D. (InterCorr International Inc.) | Eden, Dawn C. (InterCorr International Inc.) | Eden, David A. (InterCorr International Inc.)
ABSTRACT Electrochemical corrosion rate probes have been constructed and tested along with mass loss coupons in an air plus water vapor and a N2/O2/CO2 plus water vapor environment. Temperatures ranged from 200ยบ to 700ยบC. Results show that electrochemical corrosion rates for ash-covered mild steel are a function of time, temperature and process environment. Correlation between the electrochemical and mass loss corrosion rates was poor. INTRODUCTION Increasing the efficiency of the Rankine cycle in coal combustors can be accomplished by increasing heat exchanger steam temperatures and pressures as are done in supercritical and ultrasupercritical units. The benefits of increasing energy conversion efficiencies are a reduced use of fossil fuels (coal, oil, and gas) and a reduced generation of greenhouse gases. In order to achieve both of these benefits, it will be necessary to overcome technological challenges related to materials of construction. New materials or material/coating combinations with adequate strength, creep, fatigue, and corrosion resistance will need to be developed. Additional issues are present when alternate fuels are used. While heat exchanger tubes in a coal-fired plants using clean high quality fuel may last 20 to 30 years, tubes in coal-fired plants using lower quality fuel, in Waste-to-Energy (WTE) plants1, and in some coal gasification plants last only 3 to 5 years. Problems occur when equipment designed for either oxidizing or reducing conditions is exposed to alternating oxidizing and reducing conditions. The use of low NOx burners is becoming more commonplace and can produce reducing environments. Complicating the development of corrosion-resistant materials for fireside applications is the influence of ash deposits and thermal gradients on the corrosion mechanism. Ash deposits and thermal gradients have a synergism that greatly increases the corrosive attack on equipment such as waterwalls, reheaters, and superheaters. One method of addressing corrosion of these heat exchange surfaces is the use of corrosion sensors to monitor when process changes cause corrosive conditions. In such a case, corrosion rate could be a process control variable that directs the operation of a coal or waste combustion or coal gasification system. Alternatively, corrosion sensors could be used to provide an indication of total metal damage and thus a tool to schedule planned maintenance outages. There have been a number of research efforts aimed at developing high temperature corrosion probes for various industries. The majority of the research has been based on the use of electrochemical noise (EN)2-7 techniques. Others have considered the use of electrochemical impedance spectroscopy (EIS)4-6 and linear polarization resistance (LPR)7, zero resistance ammetry (ZRA)5, and electrical resistance (ER)5 There has been, however, only a limited effort reported to quantify3 the operation of corrosion rate probes. Before these probes can be accepted routinely in the power generation industries, it will be necessary to determine if they accurately measure corrosion and the changes in corrosion that are occurring in a variety of environments, if the sensor materials have an optimum composition for the intended exposure, and if the sensitivity or accuracy of the sensor changes with length of time of exposure to fireside environments. Once this is established, electrochemical corrosion rate sensors can be used extensively and will allow corrosion rate to become a process variable for power plant operators. The purpose of the research presented here is an initial attempt to address the quantitative nature of corrosion rate probes. This is a small part of a larger effort aimed at also cha
- Research Report > New Finding (0.66)
- Research Report > Experimental Study (0.48)
Electrochemical Techniques: Investigation of Corrosion in a Major Metropolitan Wastewater Treatment Facility
Tinnea, Jack (Tinnea & Associates) | Covino, Bernard S. (U.S. Department of Energy) | Bullard, Sophie J. (U.S. Department of Energy) | Cramer, Stephen D. (Robert Isaac) | Holcomb, Gordon R. (U.S. Department of Energy) | Ziomek-Moroz, Malgorzata (U.S. Department of Energy) | Isaac, Robert (U.S. Department of Energy) | White, Sarah C. (Metro-King County-WTD) | Kane,, Russell D. (Metro-King County-WTD) | Eden,, Dawn E. (InterCorr International, Inc.) | Eden, David A. (InterCorr International, Inc.)
ABSTRACT This paper discusses the application of electrochemical techniques in the investigation of premature corrosion failure encountered in a major metropolitan wastewater treatment plant. Electrochemical noise, linear polarization, harmonic distortion analysis, electrical resistance and wet chemistry techniques were combined to define the extent and investigate the cause of aggressive corrosion behavior observed at the facility. How these methods were applied and the results of the combined approach investigation are presented. INTRODUCTION In recent years, electrochemical techniques and equipment that once were the province of laboratories are seeing successful industrial application1,2,3. Initially, this took the form of simple voltage logging of either structure corrosion potentials or voltage-like readings such as current measures logged as voltage-drops across a shunt. Field-portable potentiostats and galvanostats followed. More recently, equipment that allows field logging of electrochemical noise has reached the market. The availability of a wide-range of electrochemical equipment provides today?s corrosion engineers and scientists the means to monitor corrosion on-line and in real-time that were unimaginable just a few years ago. SITUATION DESCRIPTION The 32-acre West Point Treatment Plant is located on the shores of Puget Sound approximately four miles north of downtown Seattle, Washington (see Figure 1). It is part of a system run by King County that serves over 1.4 million people. The West Point facility processes approximately 473-million liters (125-million gallons) of wastewater each day. It is located next to Discovery Park, Seattle?s largest and most natural recreational area. To better understand the investigation and its results, a basic understanding of the treatment process is helpful. Following is a brief discussion of the treatment process: ? Wastewater arrives at the plant and undergoes preliminary treatment where screens remove large stick, rocks and rags ? After the preliminary treatment, the wastewater goes to preaeration tanks where the velocity is slowed allowing heavy sands and grit to settle ? Next is primary treatment where flow is slowed further and about 60% of the solids and pollutants settle out ? The primary process is essentially one of settlement, while the secondary process uses aerobic bacteria to digest suspended organic material ? From primary treatment the process stream, now called primary effluent (PE), is pumped to the secondary aeration tanks where oxygen is bubbled through the steam ? From the secondary aeration tanks the stream moves to secondary clarifiers where bacteria and other fine material settles out ? A recursive line returns approximately 25% of the flow back from the clarifier to the aeration tanks ? this is known as the return activated sludge (RAS) line ? After secondary treatment, the effluent is disinfected and discharged into Puget Sound In 1996 major expansion and upgrading to the secondary treatment stream was completed. In December of 2002, a 760 mm (30- inch) diameter mild steel pipe elbow in the RAS line of that upgraded treatment stream deve loped a leak and required repair (see Figure 2). Figure 3 shows a thru-wall pit failure of the RAS elbow. The pipe interior was coated with a quality coal tar epoxy. Figure 4 shows pits concentrating along a weld seam in the pipe elbow. Although pits tended to locate near welds, there were pits located in non-welded areas of the elbows. There was also some blistering of the coating. Some blisters covered corrosion activity and pits and were slightly acidic (pH~6.0). Other blisters covered non-corroded areas and were alkalin
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Treatment (0.61)
- Well Completion > Well Integrity > Subsurface corrosion (tubing, casing, completion equipment, conductor) (1.00)
- Production and Well Operations (1.00)
- Health, Safety, Environment & Sustainability > Environment (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Materials and corrosion (1.00)
Evaluation Of The Use Of Electrochemical Noise Corrosion Sensors For Natural Gas Transmission Pipelines
Covino, Bernard S. (U.S. Department of Energy) | Bullard, Sophie J. (U.S. Department of Energy) | Cramer, Stephen D. (U.S. Department of Energy) | Holcomb, Gordon R. (U.S. Department of Energy) | Ziomek-Moroz, Malgorzata (U.S. Department of Energy) | Kane, Russell D. (InterCorr International Inc.) | Cayard, Michael S. (InterCorr International Inc.) | Eden, Dawn C. (InterCorr International Inc.)
ABSTRACT Corrosion sensors and electrochemistry-based corrosion measurement technology were used to study internal corrosion of environments similar to those in natural gas transmission pipelines. Field tests were conducted at a gas gathering site. Test locations were selected in environments consisting of dry/moist natural gas and the hydrocarbon/water mixture removed from natural gas. Sensors were made using A106 pipeline steel in the form of flange probes. Linear polarization resistance, electrochemical noise, and harmonic distortion analysis were used to measure corrosion rates, Stern-Geary constants, and pitting factors. Results show that the measurements were sensitive enough to detect small rates of corrosion in the selected environments. INTRODUCTION Natural gas transmission pipelines are essential to the economics and security of most nations. In the US and Canada, the 180,000 mile network of steel transmission pipelines is more than 50 years old and has suffered some deterioration due to corrosion. While corrosion can occur on both external and internal surfaces of pipelines, internal corrosion is the subject of interest for this paper. Current methods of determining internal corrosion attack in pipelines rely on after-the-fact inspections using smart pigs. A study1 conducted in the USA from 1970 to 1984 reported that 54% of the service failures to gas pipelines were attributable to outside forces such as earth movement, weather, and third party equipment operation. In addition, 17% were attributable to material failures, and 17% to corrosion. A later study2 in Canada from 1980 to 1997 concluded that 63% of pipeline failures were caused by corrosion, with 50% due to internal corrosion and 13% due to external corrosion. While external corrosion of pipelines is controlled by the use of barriers and cathodic protection, instances of corrosion and stress corrosion cracking have been reported3. External corrosion of gas transmission pipelines is usually controlled by the application of various polymeric coatings augmented with cathodic protection (CP). When corrosion does occur on the outside of the pipeline, the combination of general and localized corrosion with the high stresses in the pressurized pipelines can sometimes lead to stress corrosion cracking (SCC). In cases where CP is inadequate or non-existent, pipelines exposed to ground waters can experience transgranular SCC due to exposure to low pH (6.5) CO2-containing ground water. In cases where CP is adequate, gas pipelines may also be susceptible to intergranular SCC due to higher pH environments created adjacent to the pipeline3. Internal corrosion of gas transmission pipelines is dependent entirely on the purity of the gas. The presence of moisture, salts, organics, CO2, and sulfur containing species such as H2S can initiate and accelerate corrosion of the transmission pipelines. Although corrosion failures represent a significant proportion of the number of total failures of natural gas pipelines, it is now possible, using currently existing technology, to reduce the number of those failures. A proposed corrosion monitoring strategy involves the coupling of advanced corrosion sensors with advanced pigs. Corrosion sensors can be used both internally and externally in critical pipeline sections, in non-pigable pipeline sections, and routinely placed throughout the pipeline network. Corrosion sensors are important because they can be placed in critical pipeline sections, where there is high corrosion activity or where pigs can not be used. They can provide daily information where none is now available. The advantages of placing corrosion sensors in pigable sections of the pipeline network
- North America > United States > Texas (0.29)
- South America > Brazil > Rio de Janeiro > South Atlantic Ocean (0.24)
- Research Report > New Finding (0.34)
- Research Report > Experimental Study (0.34)
- Well Completion > Well Integrity > Subsurface corrosion (tubing, casing, completion equipment, conductor) (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Materials and corrosion (1.00)
Electrochemical Noise Monitoring of Corrosion in Soil near a Pipeline Under Cathodic Protection
Bullard, Sophie J. (U.S. Department of Energy) | Covino, Bernard S. (U.S. Department of Energy) | Cramer, Stephen D. (U.S. Department of Energy) | Holcomb, Gordon R. (U.S. Department of Energy) | Ziomek-Moroz, Malgorzata (U.S. Department of Energy) | Locke, Margaret (Northwest Natural Gas) | Warthen, Michael (Northwest Natural Gas) | Kane, Russell D. (InterCorr Inte) | Eden, David A. (InterCorr Inte) | Eden, Dawn C. (InterCorr Inte)
ABSTRACT Electrochemical noise (EN), linear polarization resistance (LPR), and harmonic distortion analysis (HDA) were used with three-electrode probes to monitor the corrosion occurring in soil near a gas pipeline under cathodic protection. The test site was a cathodic protection (CP) test station where impressed current CP was applied to a 2 in. (5.1 cm) diameter coated steel pipe using an 84 in. (0.2 m) TA-2 high-silicon cast iron anode. Electrochemical measurements were made at two locations inside the CP field and one outside the CP field. One set of measurements was made with the CP system off to obtain base line data and two with the CP system on. Results indicate that CP does not interfere with the measurement of corrosion rate and pitting factor using EN, LPR, and HDA techniques. INTRODUCTION An analysis1 of 5872 pipeline incidents in the U.S. from 1970 to 1984 reported that 54% of the service failures of gas pipelines were attributable to outside forces such as earth movement, weather, and equipment operation by outside parties, 17% to corrosion, and 17% to material failures. A later analysis2 of 12,137 failures in Canada from 1980 to 1997 concluded that 63% of pipeline failures were caused by corrosion, with 50% due to internal corrosion and 13% due to external corrosion. Corrosion failures represent a significant proportion of the total number of failures. Probes that can detect internal and external corrosion in real time before failure occurs will enhance gas transmission pipeline reliability. External corrosion of gas transmission pipelines is usually controlled by the application of various polymeric coatings augmented with cathodic protection (CP). When corrosion does occur on the outside of the pipeline, the combination of general and localized corrosion with the high stresses in the pressurized pipelines can sometimes lead to stress corrosion cracking (SCC). In cases where CP is inadequate or non-existent, pipelines exposed to ground waters can experience transgranular SCC due to low pH (6.5) carbon dioxide containing water.3 Even when CP is adequate, gas pipelines may be susceptible to intergranular SCC due to the higher pH external environment generated by CP3. One method to address this type of corrosion problem is to place corrosion rate probes to monitor the corrosivity of the soil in areas that have a higher risk for corrosion. Laboratory studies have shown that electrochemistry-based corrosion rate probes can be used to monitor the corrosion of steels in soils.4 Corrosion rates were shown to have a good agreement with gravimetric weight loss measurements and were also sensitive to changes in O2, CO2, and moisture content. Others have shown that electrical resistivity probes can be used to monitor the effectiveness of cathodic protection (CP) of pipelines.5 While there are a variety of electrochemical techniques that can be used to measure the corrosion rates of metals in soils, the effect CP will have on the corrosion rate measurements is unknown. The purpose of the research reported here is to verify that corrosion rate and pitting factor measurements can be made in the soil adjacent to a natural gas transmission pipeline under applied CP. This would allow a continuous direct assessment of the corrosivity of the soil and ground water around natural gas transmission pipelines. EXPERIMENTAL DESIGN All of the electrochemical corrosion tests were performed using three-electrode electrochemical probes with electrodes made of the same material and surface area. The first electrode was used as the working electrode, the second as the counter electrode, and the third as the reference electrode.