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ABSTRACT Modern heat resistant ferritic-martensitic steels are of great interest as superheater materials in fossil fuel power plants or as material for interconnectors in solid oxide fuel cells. The environments of such applications contain high amounts of water vapor, which is known to promote the formation of the volatile chromium species CrO2(OH)2 leading to insufficient oxidation resistance of 9% Cr-steels in such atmospheres. Results pertaining to the enrichment of manganese and chromium in metal subsurface regions without altering the bulk phase are presented. The formation of protective scales during oxidation to suppress the evaporation of chromium oxy hydroxide in water vapor containing environments was achieved. Reference oxide samples were prepared to investigate the kinetics of oxidation of chromia, manganese oxide and MnCr2O4-phase without an influence of the substrate material. The diffusion treatment developed was based on thermodynamic considerations for the design of the pack cementation process to reach different compositions in the enriched diffusion zone. The improved oxidation behavior was illustrated by oxidation experiments in an environment with water vapor (1% O2 - 10% H2O - N2) at temperature of 650°C. INTRODUCTION Modern fossil power plant technology is based on new processes like the oxyfuel combustion and CO2 capture to reduce CO2-emissions while at the same time increase efficiency. The oxyfuel combustion or the combustion of biomass leads to flue atmospheres with 15% water vapor. In order to increase efficiency supercritical steam conditions with temperatures up to 600°C and higher, as well as pressures of 3·107 Pa are necessary. These new technologies lead to extreme demands on superheater components. Under these conditions newly developed 9% Cr-steels, such as P92 have sufficient creep strength.1 These heat resistant ferritic-martensitic steels exhibit general advantages as superheater materials in the temperature range between 600-700°C in comparison to nickel base alloys or austenitic steels, such as improved heat transfer behavior, a lower coefficient of thermal expansion, as well as lower costs.2
ABSTRACT In this paper, solids deposition in 36 inch (0.914 m) x 47 km and 48 inch (1.219 m) x 19 km regions of a transmission oil pipeline are analyzed and several families-of-curves are generated to study the effect of solid particles’ average size; pipeline flow rate, diameter and fluid viscosity; and pipeline length on the deposition rate of solids with average density of 2500 kg/m3. To generate these curves only one variable is changed while other variables are held constant. Obtained family-of-curves may then be used to predict the amount of solids deposition inside the pipeline as a function time. Performed analysis is specifically focused on validating and optimizing the current maintenance pigging schedule under different pipeline operating conditions. INTRODUCTION Oil and Gas transmission pipelines are still the principal tool for transporting fossil fuel between distant locations. Despite all the advances recently achieved in exploiting new sources of energy such as wind, solar, thermal energy and fuel cells (Xiao et al.1, Bahrami et al. 2,3), they are far from replacing the fossil fuel in an effective way. Therefore fossil fuel still remains the main provider of energy in many countries, and as a result, the effective maintenance and operation of current and future energy pipelines is broadly recognized as a strategic objective by most of the major energy producers and consumers. Internal metal loss or corrosion in the form of localized or pitting corrosion is one of the major threats to the integrity of oil and gas transmission pipelines. Solids deposition has long been known as a leading cause of under-deposit pitting corrosion (UDPC) in both sweet and sour pipelines.4 While predictive models to characterize the movement (or stagnation) of oil borne sediment exist, there has been little published work on the rate of solids accumulation in continuously operated.
ABSTRACT Rust preventatives based on sodium, calcium, zinc, or barium sulfonates are commonly employed by manufacturers of metal products to protect their products from a variety of corrosion pathways. Although the films are nearly imperceptible, the protection they provide can last several months to a year or more depending on the environment. Historically, barium-sulfonate-based rust preventatives have been touted as superior products as compared to other alkali metal sulfonates. These barium- based products, however, can be a disadvantage to users and manufacturers due to the higher cost of barium waste disposal. Future environmental regulations are expected to tighten, but there has been a reluctance to switch from barium-based products by the manufacturing segment due to a perceived performance advantage. Accelerated testing methods have been employed to demonstrate that calcium-based rust preventatives can provide equal or better performance than barium-based products. Performance of the materials was measured against industry standard controls. INTRODUCTION Thin-film rust preventatives are temporary protective coatings that have recommended film builds of less than 1.2 μm. These temporary coatings are used across several industries to provide transient protection for ferrous parts, equipment, and metal sheets. After being coated, the protected parts may be stored indoors or outdoors in covered environments without fear of corrosion. In addition, top tier thin-film rust preventative technology may also be used to protect goods during shipping. Rust preventative fluids typically contain an alkyl substituted aromatic sulfonate salt that is thought to provide a thin layer of corrosion protection.1 A wide variety of mono and di valent cations are used to salt the sulfonates, but certain metal cations such as zinc and barium are undesirable because of potential environmental impact and high cost of the waste disposal.
Norsworthy, Richard (Polyguard Products, Inc.) | Heinks, Carsten (Rosen Technology and Research Center GmbH) | Jurgk, Matthias (Rosen Technology and Research Center GmbH) | Grillenberger, Jörg (Rosen Technology and Research Center GmbH)
ABSTRACT One of the major issues in the pipeline industry is that of disbonded coatings that shield cathodic protection (CP) current. This allows potential external corrosion and stress corrosion cracking (SCC) to develop when electrolyte is present under the disbondment. This has been an ongoing problem with coated and cathodically protected pipelines since the beginning of using these two technologies. Until recently the industry has not had an effective method of locating disbonded coatings on in-service pipelines other than exposing the pipeline. With the continued development and improvements of the "Electro-Magnetic Acoustic Transducer" (EMAT) technology to locate SCC and disbonded coatings without having to expose the pipeline gives operators critical, but economically feasible information about their pipeline systems. The "EMAT" technology is also capable of distinguishing between and identifying the various coating types and condition on a particular piping system. Correlating the EMAT data with cathodic protection measurements data enables companies to distinguish between "CP shielded" disbonded coating areas and "CP open" coating holidays. This information tends to be relevant for SCC susceptibility models and Pipeline Integrity Management Systems. Another benefit may be the understanding of the various coating types and their compatibility with CP when disbondments occur. Eventually, this will lead to better selection and use of coatings, as well as, the development of new coating products to effectively control external corrosion in conjunction with adequate CP even if disbondments occur. This protection is established when the coating adheres to the surface of the pipe while preventing the surrounding electrolyte from coming in direct contact with the pipe metal. The development of corrosion and stress-corrosion cracking on the pipe surface is prevented because there is no electrolyte in contact with the pipe. However, the protecting function of coatings can be affected by a variety of failure modes, such as: 1. Microbiological influences 2. Cracks 3. Holidays 4. Laminations (in multi-layer coating systems) between layers If the coating around these defects experiences disbondment from cathodic protection or other forces, the CP may not reach far enough under the disbonded area to protect the pipe from SCC or corrosion.
ABSTRACT Above ground indirect inspection techniques have evolved so rapidly that some of their underlying concepts have almost been forgotten. In fact, there seems to be some ambiguities currently concerning the functionalities and utility of each survey type. In this paper, we undertake a quick review of coating condition surveys, namely AC and DC voltage gradient survey, exploring their founding concepts and their evolution over the last few decades. We also address some supposed limitations of these surveys – such as data acquisition of voltage gradient surveys over paved surfaces – and show that it is possible to acquire usable data in such circumstances, and correlate them carefully to evaluate the pipeline coating condition. Finally, we address some on-going technical issues that require more industry collaborative research to advance the utility of voltage gradient surveys INTRODUCTION There are numerous above ground survey techniques available to assess the potential for external corrosion or to locate holidays or anomalies in protective coatings on buried utilities such as pipelines and cables. These above ground survey techniques are collectively called “indirect inspection techniques” (IIT) because they are non-intrusive and work by measuring magnetic fields or voltage gradients in the environment surrounding the utility without disturbing either. Alternating current and direct current voltage gradient surveys are two popular techniques among others that have been recognized by NACE and other international standards. These techniques are “used to evaluate in detail the coating condition on buried pipelines and identify and classify coating holidays”. 1 They are also recommended for the indirect inspection stage of the ECDA process to identify and define the severity of coating faults and areas where external “corrosion activity has occurred, is occurring, or may occur”.2
ABSTRACT Meeting the growing energy demand will require an improvement in the efficiency of fossil fuels and alternative energy systems. Increasing temperature and/or pressure is a straightforward way to do so but it will necessitate new material solutions to ensure component durability in harsh environments. Coating application represents a cost-effective solution, and some aluminide coatings deposited on Fe and Nibased alloys have indeed demonstrated excellent oxidation resistance in aggressive atmospheres at high temperature. However, the coating impact on the substrate mechanical properties remains a concern. Creep tests have been performed on bare, annealed, and coated Fe and Ni-based alloys at temperature ranging from 600 to 800ºC. Results indicate that coating application has a marginal effect on the substrate creep properties as long as the coating is considered as non-load bearing and is deposited at the appropriate temperature. In light of these findings, the potential benefit of coating application on component durability in aggressive environments will be discussed. INTRODUCTION Satisfying the constant increase of energy demand and reducing air pollution emissions will require development of more efficient energy systems. Increasing operating temperatures and pressures is a straightforward solution to improve systems efficiency,1 and several programs in the USA, Europe, Japan, and China have set ambitious goals for the next generation of coal-fired power plants. For example, the ultrasupercritical (USC) steam program in the USA aims at steam conditions as high as 760°C and 350 bar. Most of the alloys presently used in power plants or combustion engines would see their durability considerably reduced under harsher conditions due to enhanced corrosion and/or high temperature deformation, and new, more expensive materials will be required. When corrosion is the main degradation mechanism, the application of a corrosion-resistant coating is a potential cost-effective solution.
Yang, Di (School of Mechanical Engineering Georgia Institute of Technology) | Singh, Preet M. (School of Materials Science and Engineering Georgia Institute of Technology) | Neu, Richard W. (School of Mechanical Engineering Georgia Institute of Technology)