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ABSTRACT Industrial boilers like kraft recovery boilers experience stress assisted corrosion (SAC) cracks in their carbon steel tubes and other water touched surfaces. The performance of carbon steel in industrial boilers strongly depends upon the formation and stability of the protective magnetite film, Fe3O4, on the waterside surface of boiler tubes. Tests were carried out in a recirculation autoclave under industrial boiling water conditions. Boiler water chemistry was controlled during a series of tests to keep the dissolved oxygen in the range of 5 ppb - 10 ppm. Initial tests were conducted to develop the magnetite film on carbon steel tube samples under different test conditions. Results have indicated that the water chemistry and ratios of anode/cathode have an effect on the magnetite film morphology. Film characterization by atomic force microscopy (AFM) and scanning electron microscopy (SEM) has shown that the magnetite film changes from an irregular-grained compact and protective film to a fine-grained porous (non-protective) film with tetrahedral crystals at the surface when the anode to cathode area ratio decreases. Corrosion fatigue crack initiation and growth mechanisms involved in boiler water environments include magnetite film damage as an important step. Slow strain rate tests were carried out in simulated boiler water environments, using smooth carbon steel samples, to investigate the role of temperature and water chemistry on crack initiation. The mechanism of stress assisted corrosion was proposed here, and an interrupted slow strain rate test was designed and carried out in lab to validate the proposed SAC mechanism. INTRODUCTION Failures of carbon steel boiler tubes from the waterside have been reported in the utility boilers and industrial boilers for a long time. In the utility industry, waterside tube cracking, generally referred to as corrosion fatigue (CF), has been recognized as a major cause for boiler downtime. The typical corrosion fatigue crack that found in utility boiler is generally long and sharp, as shown in Figure 1 a. Cracks in industrial boilers are typically found in areas with heavy attachment welds on the outer surface. These cracks are typically blunt, with multiple bulbous features indicating a discontinuous growth, as shown in Figure 1b. These types of tube failures are typically referred to as stress assisted corrosion (SAC). For recovery boilers in the pulp and paper industry, these failures are particularly important as any water leak inside the furnace can potentially lead to smelt-water explosion. Utility boilers also have waterside cracking in carbon steel tubes but most of the cracks are sharp and are referred to as corrosion fatigue cracks. A significant amount of work has been published on corrosion fatigue crack initiation and propagation. It is clear from the previous published literature, why utility boilers may have sharp corrosion fatigue cracks whereas majority of industrial boilers have blunt and bulbous cracks. Typically, utility boilers operate at higher temperatures and pressures compared to the industrial boilers. It has been speculated that the water chemistry control in utility boilers, during operating and shutdown conditions, may be tightly controlled compared to most low pressure industrial boilers. Some researchers have reported the effect of temperature on corrosion fatigue . Previous work in utility boiler environments has shown that the oxygen concentration has a significant effect on corrosion fatigue cracks in carbon steels. For carbon steel boiler tubes, Dooley reported that the corrosion fatigue is strongly influenced by water chemistry with oxygen concentration being the major factor. Results from ph
ABSTRACT Corrosion testing in black liquors from kraft pulp and paper mill evaporators has confirmed that carbon steel has stable passivity in weak liquors (15% solids content), unstable passivity in intermediate liquors (25% and 33% solids content), and corrodes actively in strong liquors (45% and 49% solids content). The occurrence of rapid corrosion of carbon steels in evaporators handling liquors of intermediate solids content is caused by an abrupt switch from unstable passivity to active corrosion. Sudden changes in the corrosion state may be brought about by relatively small increases in the sulfidity and temperature of the liquor or by the use of modern carbon steels having higher silicon contents than those used in the past. Galvanic coupling of active carbon steel with stainless steel increases the active corrosion rate of the carbon steel. INTRODUCTION This paper is a companion to an earlier paper by the author on the results of inspections of kraft black liquor evaporators that was presented at the 2005 TAPPI Engineering, Environmental, and Pulping Conference held in Philadelphia. Unexpectedly rapid corrosion of carbon steel in evaporator effects handling intermediate-strength black liquors is a significant problem that has resulted in leaks or failures in vapor domes, vapor separators, tube sheets, piping, and nozzles. That carbon steel serves well as a material of construction for many years but then succumbs to rapid corrosion suggests that there has been a change from passive to active corrosion conditions. In many cases the corrosion rate of the carbon steel was evidently accelerated by galvanic contact with stainless steel components. The TAPPI paper contains a comprehensive review of the literature on corrosion of evaporators. In two previously published studies, the author has demonstrated that the corrosion rate of carbon steel in softwood black liquors increases with: - increased solids content in the liquor - increased sulfidity of the liquor - increased temperature of the liquor - increased silicon content in carbon steels - increased velocity of the liquor. Preet Singh has shown in the laboratory that the nature of the wood species being pulped can have a profound effect on corrosion rates in black liquors produced under otherwise identical pulping processes. Pulping of some hardwood species has been found to yield essentially non-corrosive black liquors while pulping of many softwood species yielded black liquors highly corrosive to carbon steel. EXPERIMENTAL Corrosion testing was done in samples of evaporator black liquors from kraft mills in North and South America. Materials tested included carbon steels, stainless steels, and carbon steel-stainless steel galvanic couples. All corrosion tests were carried out in autoclaves of 2-litre volume type constructed using 2205 duplex stainless steel. Liquors The liquors were all from softwood pulping in four different geographical areas: - NE (Northeastern North America). Softwood species pulped (predominantly spruce). - NW (Northwestern North America). Softwood species pulped (predominantly Douglas fir). - SE (Southeastern North America). Softwood species pulped (Southern pine). - SA (South America). Softwood species pulped (Radiata pine). The liquor samples were shipped in plastic bottles that were completely filled to avoid air oxidation of the liquor. The samples were stored under refrigeration. All chemical analyses were done by Econotech in Delta, BC, Canada, a company that specializes in analysis of liquors from kraft pulp mills worldwide. The liquors were analyzed for inorganic constituents hydroxide, sulfide, thiosulf
- Materials > Paper & Forest Products (1.00)
- Materials > Metals & Mining > Steel (1.00)
INTRODUCTION ABSTRACT Cladding/overlay thickness measurements were made on several primary air ports fabricated from alternative composite tubes installed in a kraft recovery boiler to document the fireside corrosion. Laboratory corrosions tests were then conducted to reproduce the relative corrosion rates determined by the field thickness measurments. It was found that all of the major available composite tube systems are suceptible to corrosion. Hydrated sodium sulphide and oxygen in combination with sodium hydroxide are implicated as major components in the liquid environment that causes the corrosion. Prevenative measures discussed include the need for a well-sealed port, and the likely need to avoid having black liquor droplets contacting the port tubes while dehydration is incomplete. Composite 304L stainless steel/SA-210 carbon steel tubes have replaced conventional carbon steel boiler tubes as the construction material for the lower-furnace of kraft recovery boilers to resolve the general fireside corrosion problems experienced with conventional carbon steel boiler tubes. While composite tubes have been very successful in resolving that concern, they have introduced other unanticipated problems. One such problem involves corrosion or balding, which has been observed predominantly on primary air port opening tubes. Corrosion of the 304L stainless steel cladding has occurred on both the cold-side surface and the fireside surface of primary air port opening tubes. Corrosion is a concern because of the potential for a water leak and subsequent explosion resulting from a smelt-water reaction. To resolve the more serious composite tube cracking problem, boiler tube suppliers have promoted the use of alternative co-extruded tubes, weld-overlaid tubes, and chromized tubes. Several North American mills have installed primary air ports fabricated from those alternatives. Based on reported inspection results, those alternatives are susceptible to corrosion, some more so than others. Several mechanisms have been proposed to account for the corrosion, which include corrosion by molten hydroxide, molten smelt and molten pyrosulphate. However, until a consensus on the true mechanism is attained, a resolution to this problem may not be achieved. Paprican has been involved in a collaborative United States Department of Energy research program with Oak Ridge National Laboratory to address the composite tube cracking problem in kraft recovery boilers. One task of the multi-disciplinary research program has been to identify the most likely corrosive environment that causes corrosion of primary air port composite tubes. This was done by conducting careful corrosion surveys within a single North American recovery boiler over an extended time frame to determine relative corrosion resistance of the various composite tubes installed, and by conducting lab-based corrosion testing to reproduce that relative corrosion resistance. This report documents the results of those efforts. RECOVERY BOILER INSPECTION OBSERVATIONS The relative corrosion resistance of composite tubes fabricated into primary air ports was determined from the analysis of inspection data, and from measuring the cladding/overlay thickness as a function of time. Essential design and operation details of the recovery boiler, within which observations and measurements were made, are provided below. The recovery boiler under study is a 1997 Babcock and Wilcox (B&W) single-drum cogeneration unit constructed using 2ยฝ in. (63.5 mm) diameter tubes on 3 in. (76.2 mm) centers in a membrane-type design with a sloped floor. The unit typically burns 3.6 million lbs (1.63 million kg) of black liquor dry solids
- Materials > Metals & Mining > Steel (1.00)
- Government > Regional Government > North America Government > United States Government (1.00)
- Energy (1.00)
- 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)
ABSTRACT The significant problem posed by internal corrosion in natural gas transmission pipelines has been highlighted in many recent publications, and the internal corrosion direct assessment (ICDA) methodology has been shown to be an effective tool in addressing it. An efficient corrosion assessment methodology must aim at quantifying corrosion damage to facilitate development of pro-active inspection and maintenance programs for safe operation of natural gas transmission pipelines. The objective of this paper is to highlight the importance of using current technologies and software systems to effectively quantify possibility of corrosion damage alongside propensity in a pipeline system for water retention and consequently identify critical pipeline components with real potential for damage and failure. INTRODUCTION Internal corrosion has been one of the most significant causes for reported natural gas pipeline failures, causing substantial property damages. Accident reports over the last 30 years highlight the significantly increasing problem posed by internal corrosion in natural gas transmission pipelines. ICDA provides an enhanced framework of complementary solution systems, using latest technologies to implement a successful and comprehensive strategy of direct assessment methodology to help ensure pipeline integrity. Current ICDA methods primarily deal with determining conditions that favor formation of liquid water in a specific pipeline segment, and whether the pipeline segment inclination is adequately low to support water carry through. If the flowing multiphase gas/water fluid has inertial and viscous characteristics that do not support carry through of water, then the segment is labeled as ?critical? for further inspection and integrity analysis. While this approach is better than operating pipelines without a basis for ICDA, it only identifies potential for water hold up, but does not address the more relevant questions of quantification of water hold up and potential for corrosion damage. Assessment of the extent of corrosion damage due to availability of an aqueous phase in the presence of CO2, H2S etc. is a complex task essential for effective ICDA, but typically beyond the scope of most present-day ICDA models. PredictPipe (TM), an easy to use software system, has been developed and is capable of not only determining propensity for water retention, but also the corrosivity of the environment in the presence of the aqueous medium for the identified critical segment. In fact, the software model will not only perform conventional ICDA, but also generate actual corrosion rate predictions for any point along a pipeline segment. The system integrates a number of key functionalities, including water phase behavior determination, pH computation, corrosion modeling, flow modeling and comprehensive pipeline analyses based on lab and field data. The methodology encapsulated within this software system is hence termed as ?Advanced? ICDA. The rest of the paper provides an overview of the various modules in the software, including technical overview of corrosivity prediction, as well as a brief description of the system interface. Efficacy of the approach has been validated through representative case studies. CO2/H2S-BASED CORROSION: TECHNICAL BACKGROUND CO2-based corrosion has been one of the most active areas of research, with several predictive models for carbon steel corrosion assessment. These efforts range from a predictive model that begins with CO2 corrosion to models that focus on specific aspects of the corrosion phenomena (such as flow-induced corrosion or erosion corrosion) to models that empirically relate corrosion
- North America > United States > Texas (0.29)
- North America > United States > Colorado (0.28)
ABSTRACT There has been recent interest in the use of hydrogen flux monitoring at high temperatures to evaluate ?naphthenic acid? and sulfidic corrosion in high temperature process streams associated with crude distillation units. In this report, we present flux and corrosion data obtained from samples drawn from a refinery process stream. INTRODUCTION For the purposes of this paper high temperature acid corrosion is defined as corrosion of steel due to contact with a proton bearing liquid at above 100ยฐC. Of particular interest is naphthenic acid corrosion and sulfidic corrosion of steel, encountered in refinery service equipment processing crude fractions at temperatures between approximately 200 and 400ยฐC. Atmospheric and vacuum distillation, light and heavy vacuum oil (LVGO, HVGO), and coker units are affected. Naphthenic acid is a generic term for a range of aliphatic cyclic mono- and poly-carboxylic acids found in crude oil. It is known that the total acid number (TAN) of a crude or crude derivative, expressing milligrams of KOH required to neutralise 1 g of sample, does not provide a sure indicator of corrosivity since the distribution of naphthenic acids within crude blends varies widely, and the corrosivity of individual acids vary, primarily, with molecular weight, probably in so far as that affects reaction kinetics, the solubility of the iron salt formed, and the ability of the acid to solubilise iron sulfide formed on the iron surface formed as a consequence of sulfidic corrosion; Fe + H2S ยฟ FeS + H2 or 2H [Fe surface] (1) FeS + 2RCOOH (naphthenic acid) ยฟ Fe (OOCR)2 + H2S (2) Naphthenic acid bearing fluids are of low conductivity, and it is considered that naphthenic acid corrosion is predominantly chemical in nature. Schematically, Fe + RCOOH ยฟ Fe-OOCR [Fe surface] + H [Fe surface] (3) Fe-OOCR + RCOOH ยฟ Fe (OOCR)2H [Fe surface] (4) Electrochemical corrosion is conceivable over very small electrolytic pathways within micro corrosion cells: RCOOH + e- ยฟ RCOO- + H [Fe surface] (5) Fe +2RCOO- ยฟ Fe (OOCR)2 2e- (6) In either case atomic hydrogen is liable to be formed on the iron surface. There from, it may diffuse into (and out of) the steel as in (7) or form molecular hydrogen, desorbed into the process stream, by a variety of conceivable reactions such as (8-10): H [Fe surface] ยฟ H [in Fe] (7) 2H [Fe surface] ยฟ H2 [Fe surface, desorbed] (8) Fe + H [Fe surface] + RCOOH ยฟ H2 [Fe surface, desorbed] + Fe-OOCR [Fe surface] (9) H [Fe surface] + RCOOH + e- ยฟ H2 [Fe surface, desorbed] + RCOO- (10) A proportion of hydrogen entering steel via (7) could conceivably permeate through the entire steel wall, to arrive at, form molecular hydrogen at, and desorb from, the exit face, measurable as a hydrogen flux. Such hydrogen flux measurements in the field have been reported, which indicate test site position dependence, and co-trending of flux measurements at different sites during process stream variation over time. Corrosion induced hydrogen permeation has also been demonstrated to occur in the case of mineral acid (Na/K hydrogen phosphate eutectic) at 150-310ยฐC. The objective of this work was to investigate the hydrogen flux induced as a function of corrosivity of some representative crude samples and temperature, to qualify the emergent use of hydrogen flux measurement as an active high temperature acid corrosion indicator in the field. EXPERIMENTAL METHOD Crucibles were manufactured by welding one end of 110 mm inner diameter, 200 mm length of 9 Cr steel tube, to a 150 mm square base plate, of 6.4 mm thickness AISA 1018 carbon steel. A crucible base plate was
ABSTRACT Di-Glycol Amine (DGA) has been utilized for acid removal from hydrocarbon gas for many years by Aramco in Saudi Arabia. Over the years the gas demand increased significantly which resulted in operating some gas treating units in excess of the original design. Running gas treating units over the original design has impact on the process and utilities streams. This paper investigates the impact of operating DGA units over their design on the vessels and piping. This paper will present the methodology that was developed to evaluate the integrity of the units and how to discover wall thinning of piping and vessels. This methodology starts by evaluating the unit process parameters such as pressure, temperature, H2S and CO2 level, and line velocity, and then evaluates unit materials. Potential damage mechanisms and the appropriate locations for inspection are a critical part of the evaluation process. INTRODUCTION The subject plant has four low pressure 150 psig (11.6 kg/cm2) gas treating units. All units utilize DGA for acid gas removal (H2S and CO2). These units worked smoothly, in terms of corrosion problems, for about 20 years. However, the demand on gas processing increased sharply with time. As a result, serious corrosion problems developed at various locations. The material of construction for piping and equipment is principally carbon steel except for some locations such as reclaimer tubes that are made from type 304 stainless steel. DGA can be very corrosive to carbon steel at high temperatures and/or high velocity in the presence of H2S and CO2. Typical damage mechanisms are erosion/corrosion and localized corrosion. Corrosion is most common in heated and/or high velocity areas of the units such as reboilers, reclaimer, stripper column, and rich amine piping. Analysis of process parameters revealed that the low pressure gas treating units were operating at 125-150% of their original design capacity. Also, the acid gas content in the sour gas varies between 13- 17 mole% and sometimes exceeds 17 mole%. Also, it was found that the amine circulation rate has increased by 16% with DGA solution concentration of 47-50 wt%. However, this additional amount of amine solution is still not sufficient to maintain the required rich amine acid gas loading below 0.4 mol acid gas/ mol DGA to minimize corrosion development, as designed. Degradation of DGA to other products is another concern in amine treating units. The most common DGA degradation product is N,N'his (hydroxyethoxyethyl)urea (BHEEU) that has a higher viscosity and boiling point than DGA. Build-up of degradation product in the system will result in lowering the heat transfer, increasing pressure drop, and reducing the sweetening efficiency. In a DGA unit, a reclaimer is used to purify lean DGA from chemical degradation products. BHEEU can be reversed back to DGA in the reclaimer at temperature range of 360-380ยฐF (182ยฐC -193ยฐC), per the following reaction: 2R-NH2CO+ (H2O or H2S) ยฟ 2R-NH2+ (CO2 or COS) Lean DGA target limits are 10 wt% BHEEU and maximum of 6 wt% morphaline. Reclaimer process is limited to 360-380ยฐF to avoid morphaline formation because it cannot be reclaimed back to DGA. Morphaline is usually formed at temperature higher than 380ยฐF (193ยฐC). On-stream inspection program (OSI) using ultrasonic wall thickness (UT) measurements was used exclusively as the corrosion monitoring technique for process streams except utilities lines. This program is a non-destructive technique to measure corrosion rate and remaining life at specific locations of vessels and piping but it is difficult to detect localized corrosion by using UT technique. In 2002, a Risk Based Inspec
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Energy > Oil & Gas > Downstream (1.00)
- Government > Regional Government > Asia Government > Middle East Government > Saudi Arabia Government (0.37)
- 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)
- Health, Safety, Environment & Sustainability > Health > Noise, chemicals, and other workplace hazards (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Materials and corrosion (1.00)
ABSTRACT Adsorption of the corrosion inhibitor, phosphate monoester (PME), on 1045 carbon steel was investigated in pH buffered aqueous solutions with and without 0.395M NaCl. Inhibitor adsorption, as well as adsorption of chloride ions and the formation of the steel?s scale were studied in situ by surface enhanced Raman spectroscopy (SERS). The results indicate that adsorption of PME on steel occurs in acidic and mildly acidic solutions but not in mildly alkaline solutions. In acidic solutions, inhibitor adsorption is impaired by chloride ions. The potential dependency, the pH dependency and chloride ion dependency of inhibitor adsorption correlates with the potential dependency, the pH dependency and chloride dependency of a particular component of the steel?s scale that is similar to a-Fe2O3. INTRODUCTION In the North Slope of Alaska, carbon steel pipelines transport crude oil from wells to separation facilities in which the crude oil is extracted from the gas and brine that accompany the oil. The temperature of the brine is about 65ยฐC. The brine contains approximately 0.4M chloride, is saturated with CO2, and is highly corrosive to the carbon steel pipeline. Corrosion inhibitors are added at the mouth of the wellhead and at various points downstream to lower the steel?s corrosion rate to tolerable levels. One particularly successful commercial formulation contains phosphate ester (PE) and oleic imidazoline (OI) as corrosion inhibitors. Together the PE and OI protect the steel against significant uniform corrosion attack by the CO2-saturated brine. However, on occasion, leaks do occur in inhibited pipelines as a consequence of localized corrosion (e.g., pitting corrosion). Regardless of the precise mechanism(s) by which the PE and OI protect the steel against corrosion, the PE and OI must be present on the steel?s surface in order to inhibit the steel?s corrosion. The present study uses surface enhanced Raman spectroscopy (SERS) to investigate the adsorption of PE on the surface of 1045 carbon steel. In particular, the adsorption is investigated in acidic to mildly alkaline solutions. Determining the influence of pH on the adsorption of PE might identify a critical value of pH below which the PE does not adsorb. The existence of a critical minimum pH for adsorption would suggest PE is not capable of stopping a propagating pit. The approximate composition of the North Slope?s brine is as follows: 0.328M NaCl, 26.5 mM MgCl2, 6.94 mM CaCl2, 12 mM Na2SO4, and 3.33 mM NaHCO3. The total chloride concentration of the brine is 0.395M. The brine has a pH of 5.4 when saturated with CO2 at 65ยฐC. Since the pH within a pit or crevice is typically more acidic than the pH of the bulk solution, the pH inside pits and crevices in carbon steel pipes exposed to the CO2-saturated brine might be significantly lower than 5.4. To explore the adsorption of PE as a function of pH, experiments in the present study were conducted in 0.395M chloride, pH-buffered solutions with values of pH that ranged from approximately 2 to 9. Buffered solutions were made of mixtures of PO4 -3/HPO4 -2/ H2PO4 -1/H3PO4-. The phosphate system was selected because it provided buffered solutions that cover a wide range of pH. The performance of the inhibitor in the phosphate-buffered brine was nearly identical to the inhibitor?s performance in the North Slope brine. Results reported elsewhere indicated that the steel?s polarization behavior and the adsorption of PE on carbon steel in CO2-saturated North Slope brine were similar to the steel?s polarization behavior and adsorption of PE on carbon steel in N2-saturated, phosphate-buffered brine of similar pH. As already mentioned, the present stud
- North America > United States > California (0.28)
- North America > United States > Texas (0.28)
- North America > United States > Alaska (0.24)
- 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)
ABSTRACT Glass cell experiments were conducted to understand kinetics of iron carbonate scale formation in pure carbon dioxide (CO2) corrosion of mild steel. Weight gain and loss (WGL) method was used as a direct approach to investigate kinetics of scale formation. The experiments were done at the temperatures of 60ยฐC to 90ยฐC, and an iron carbonate supersaturation range of 12 to 350. It is found that the calculated results obtained by the previous kinetics expressions using the traditional dissolved ferrous ion concentration method are one to two orders of magnitude higher than the experimental precipitation rates obtained in the present study by the WGL method. The results show that the main source of the ferrous ions which are involved in formation of the protective iron carbonate scale is the iron dissolution process. It has been clearly demonstrated that the precipitation rate of iron carbonate is directly related to the conditions at the steel surface which can frequently be very different from the one in the bulk fluid. INTRODUCTION Surface scale formation is one of the important factors governing the rate of corrosion. In the case of pure CO2 corrosion, when the concentrations of Fe2+ and CO3 (2-) ions exceed the solubility limit, solid iron carbonate precipitates. Insert Formula 1 The iron carbonate scale can slow down the corrosion process by presenting a diffusion barrier for the species involved in the corrosion process and by covering up a portion of the steel surface and preventing the underlying steel from further dissolution. Iron carbonate scale growth depends primarily on the precipitation kinetics. Two different expressions (Equation 2 and 3) are used to describe the kinetics of iron carbonate precipitation in pure CO2 corrosion (proposed respectively by Johnson and Tomson in 1991 and van Hunnik et al. in 1996). In both cases the rate of precipitation PR is a function of iron carbonate supersaturation SS, the solubility Ksp, temperature (via the kinetic constant kr which obeys Arhenius law), and surface area-to-volume ratio A/V. Insert Formula 2 Insert Formula 3 Supersaturation SS is defined as species concentrations and the solubility limit: Insert Formula 4 The equation (2) given by Johnson and Tomson was fitted with experimental results at the very low levels of supersaturation using a temperature ramp method. According to van Hunnik et al. it overestimated the precipitation rate particularly at large supersaturations. The latter group proposed a nominally more accurate expression (3). As a part of a larger project focusing on precipitation of iron carbonate and iron sulfide, expressions (2) and (3) were tested against independently generated precipitation kinetics data. It was found that for the case of iron carbonate precipitation both overestimated the magnitude of the precipitation rate by a large margin (factor 10-100). Therefore, it was concluded that a more thorough examination of the kinetics of iron carbonate scale precipitation in CO2 corrosion needed to be done. EXPERIMENTAL PROCEDURE The present measurements were conducted in a glass cell as shown in Figure 1. The experiments were performed in stagnant solutions and 1 bar total pressure, the temperature varying from 60ยบC to 90ยบC. Initially each glass cell was filled with 2 liters of distilled water and 1% wt. NaCl. The solution was heated and purged with CO2 gas. After the solution was deoxygenated, the pH was increased to the desired pH 6.6 by adding a deoxygenated sodium bicarbonate solution. Subsequently, the required amounts of Fe2+ were added in the form of a deoxygenated ferrous chloride salt (FeCl2-4H2O) solution. In vari
- Europe > Norway > Norwegian Sea (0.24)
- North America > United States > Texas (0.16)
- Research Report > Experimental Study (0.49)
- Research Report > New Finding (0.34)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Well Completion > Well Integrity > Subsurface corrosion (tubing, casing, completion equipment, conductor) (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Materials and corrosion (1.00)
ABSTRACT Previous work has focused on the corrosion initiation behavior of rebar embedded in concrete. However, a complete assessment of the potential benefit afforded by new candidate rebar alloys from a corrosion resistance standpoint must address the corrosion propagation behavior and other factors that might affect the risk of corrosion-induced concrete cracking. In this study various electrochemical techniques were employed to characterize the radial (depth) and lateral (length) corrosion propagation behavior of 316LN stainless steel (S31653), 2101 duplex stainless steel (21% Cr, 1.6% Ni, 0.29% Mo, 4.8% Mn), and MMFX-2 (9.3% Cr, 0.089% Ni, 0.023% Mo, 0.46% Mn) compared to carbon steel in saturated Ca(OH)2 with NaCl additions. Radial corrosion was investigated by monitoring the anodic dissolution rate following propagation of local corrosion in a confined anode area. A pitting factor was also determined for each alloy, which describes the degree of corrosion localization. Lateral propagation was characterized using closed packed microelectrode arrays simulating a continuous electrode in order to monitor the spreading of active corrosion from initiated pit sites to adjacent surfaces. Radial pit growth was ohmically controlled but repassivated more readily at high potentials in the case of S31653 and 2101 stainless steels. Conversely, pit growth on carbon steel propagated at all applied anodic potentials and did not repassivate until deactivation by cathodic polarization. Stainless steel showed the highest resistance to lateral corrosion propagation from an active site during microelectrode array testing. In contrast, carbon steel was found to easily undergo widespread depassivation along the surface compared to stainless steel. 2101 and MMFX-2 duplex steels showed similar radial propagation behavior and corrosion morphology, which was intermediate between carbon steel and stainless steel. INTRODUCTION Chloride induced corrosion of reinforcing bar leads to premature deterioration of concrete structures. Chlorides are introduced from the external environment typically from marine exposure or wintertime application of de-icing salts. For analysis of the life-cycle cost of any concrete bridge member exposed to chlorides, the corrosion-limited service life is considered to be the sum of the corrosion initiation and propagation phases. Currently, new corrosion resistant candidate rebar materials are being considered to extend the lifetime of reinforced concrete structures. In comparison to carbon steel, stainless steel rebar (containing 18% Cr) is passive through a much broader range of pH?s, due to thermodynamic passivity and dynamic passivity when Cr is added to Fe-based alloys. Moreover, Cr, Mo, and Ni containing stainless steels have a much greater resistance to chloride induced local corrosion compared to carbon steels and have a higher chloride threshold and, therefore, a much longer initiation stage prior to depassivation. However, once the chloride threshold is exceeded and local corrosion begins, it is not known how the corrosion propagation behavior of new rebar materials will affect the remaining service life of reinforced concrete. Some of the observations made during a previous study of the corrosion initiation behavior in saturated Ca(OH)2 have hinted that different composition rebar materials may also have different corrosion propagation characteristics. A bar which exhibits the highest chloride threshold and longest initiation time may not necessarily also yield the best resistance to corrosion propagation nor optimal conversion of parent-metal into solid corrosion products that ultimately can damage concrete. It is suspected that, once the chloride threshold concentration is
- North America > United States > Virginia (0.28)
- North America > United States > Texas (0.28)
ABSTRACT This paper describes the testing and use of a multiple-array-sensor (MAS) probe to investigate one form of microbially influenced corrosion (MIC); namely that associated with sulphate-reducing bacteria (SRB). The MAS probe was developed by Southwest Research Institute to monitor localized corrosion. Subsequent work by Atomic Energy of Canada Ltd. (AECL) determined that the probe responded well to MIC giving the desired on-line, real-time corrosion rate data. Using the MAS probe it was demonstrated that the rate of MIC is directly related to the specific microbial activity. Therefore, the optimum conditions for growth of the bacteria are the optimal conditions for MIC. It was found that there was a sharp increase in the rate of MIC at the optimum temperature for growth of the SRB used in this test. Within the test system it was also found that nutrient loading (amount of nutrient entering the system, or flow rate) strongly affected MIC rates. INTRODUCTION Many industries that use large quantities of minimally treated water have experienced a wide variety of degradation in the service water components. Microbiologically influenced corrosion (MIC) has historically been the most significant degradation mechanism. Industry has expended tens of millions? perhaps even hundreds of millions?of dollars for repairs, inspection and mitigation programs. For years now there has been much discussion on how a suspected MIC failure can be shown to be MIC. In most suspected MIC failures the actual physical characteristics of the failure are also representative of other failure mechanisms. Often the only major difference is the presence of micro-organisms associated with the corrosion products. However, in previously reported work, Angell and Urbanic were able to show that the corrosion rate of Alloy 800 by the sulphate-reducing bacteria (SRB) was not a simple function of the population density. Instead it was concluded that microbial activity was a key factor in determining whether MIC would initiate. Although MIC is undeniably a valid corrosion mechanism, it must be recognised that MIC cannot typically be disentangled from other corrosion mechanisms. There are very few, if any, corrosion mechanisms that can be characterized as purely MIC. Rather MIC is best viewed as the microbial involvement in other traditional corrosion mechanisms. Just as the electrochemical corrosion mechanisms can vary depending on the metal, in the same way the MIC mechanism will vary depending on both the metal and the microorganisms involved. Our understanding of MIC has evolved over the years; MIC is now increasingly viewed as a process whereby microbial action alters the local chemistry conditions which, in turn, supports or induces localized corrosion. This alteration of the local chemistry results from the normal metabolic processes of the micro-organisms. Therefore, an understanding of the corrosion mechanisms and the microbial metabolic process involved allows strategies to be developed for controlling microbial growth kinetics and consequently the corrosion processes to be controlled. Given the monitory scale of the losses associated with MIC and the fact that biocide and other treatments can lessen the impact of MIC, the need for on-line monitors for MIC has long been recognized. Many potential MIC probes have been reported in the literature this paper discuss the use of one such localized corrosion probe that has been shown to function well for pitting of carbon steel in the presence of the sulphate-reducing bacteria (SRB). The multiple array sensor localized corrosion probe was developed by Southwest Research Institute (San Antonio, Texas) and its description has been given elsewhere.