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Results
Epoxy-Coated Rebar Performance in the Deck of the Perley Bridge
Covino, Bernard S. (Albany Research Center) | Cramer, Stephen D. (Albany Research Center) | Holcomb, Gordon R. (Albany Research Center) | Russell, James H. (Albany Research Center) | Bullard, Sophie J. (Albany Research Center) | Dahlin, Cheryl (US Department of Energy) | Tinnea, J.S. (John S. Tinnea and Associates)
ABSTRACT The Perley Bridge spans the Ottawa River between the Canadian provinces of Ontario and Quebec. During a 1979 rehabilitation project, epoxy-coated rebar (ECR) was installed in an effort to extend the service life of span 17. External signs of corrosion were observed in the west lane of span 17 as early as 1985, but none were observed in the east lane. The cover concrete on the east lane was almost twice that of the west lane. A wide variety of techniques were used to evaluate the difference between slabs cut from the east and west lanes. The most useful techniques were potential mapping, chloride profiling, petrographic analyses, adhesion testing, epoxy damage, analyses of reinforcing bar-concrete cross- sections, and electrochemical impedance spectroscopy measurements of epoxy properties. Cover depth and chloride contamination were the most significant factors affecting damage to the rebar. Based on these techniques, results showed that the epoxy coating used on the west lane of the Perley Bridge deck in span 17 provided only 1 to 4 years of additional corrosion protection over bare rebar. INTRODUCTION An experimental bridge built in West Conshohocken, Pennsylvania in 1973 was the first structure constructed using ECR. 1 Between then and the time of an update report 2'3 in 1992, well over 100,000 structures were built in the United States using ECR. The epoxy coating that is applied to rebar was designed to be a physical barrier between the bare rebar and a corrosive environment surrounding the rebar. The need for some type of protection became apparent in the late 1960s and early 1970s during the highway building boom of that period. 4 There was evidence available at the time that typical steel-reinforced concrete construction was not able to protect bare steel in high chloride environments such as coastal environments or locations requiring the application of deicing salts. The protective systems favored at that time were epoxy-coated and galvanized rebar. The US Federal Highway Administration (FHWA) limited the use of galvanized rebar but endorsed the use of epoxy coated rebar. 4 In 1996, the FHWA stated that any type of protection system could be used provided that it would effectively prevent chloride-induced deterioration. 4 Chloride-induced corrosion of steel-reinforced concrete structures usually becomes apparent when rust bleeds from the concrete and when the concrete begins to crack and spall. There are two processes that determine the appearance of cracking and other corrosion damage in steel-reinforced concrete structures. These are the initiation and the propagation processes 5 and they are additive in their effect on concrete. The initiation process is based on the time it takes for the chloride concentration at the rebar to exceed the threshold level of 0.7 kg C1/m 3 (1.2 lb Cl/yd3) 6 necessary to break down the normal passivity of steel in the highly alkaline concrete environment. Factors that affect the initiation time include concrete cover depth, concrete permeability, severity of environment (in terms of chloride and water deposition), and the presence of chlorides in the concrete mix. The propagation time is the amount of time necessary for corrosion to proceed to the point where sufficient rust can form to crack the concrete and cause rust bleeding and spalling. A time of 3.5 years has been suggested by Sagues for the propagation process to occur for bare rebar. 5 Propagation of corrosion damage depends on the rate of corrosion and other structural considerations. Environmental factors that affect the corrosion rate are temperature, moisture, and oxygen availability. Structural factors include concrete cover depth, concrete tensile strength, and re
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- North America > United States > Pennsylvania (0.24)
- Geology > Mineral > Halide (0.68)
- Geology > Rock Type > Sedimentary Rock (0.48)
- Geology > Geological Subdiscipline > Petrology > Petrography (0.35)
- Transportation (1.00)
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- 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 Today, the traditional fusion-bonded epoxy (FBE) coatings used to protect carbon steel reinforcing bar (rebar) and pipe are being placed under increased scrutiny. Concerns have been raised which question the ability of such coatings to abate corrosion in the long term. Researchers have argued that a damaged, FBE coated rebar exhibits poorer corrosion performance than a comparable uncoated, black steel rebar. This reduced corrosion performance and corresponding service life is likely the result of local anodic sites which develop along the coated rebar or pipe in areas where the FBE coating has been removed due to impact or abrasion. A novel coating design has been developed, the implementation of which significantly improves the damage tolerance of epoxy coated components in a variety of high chloride environments, such as an aging concrete bridge deck. In this study, the coating was successfully applied using conventional electrostatic-spray equipment at a commercial applicator. The resulting coated rebar was able to exceed the performance requirements of a coat-after-fabrication application in terms of cathodic delamination. This paper details the results achieved to date, as well as outlining the in-concrete test program currently underway. INTRODUCTION Corrosion of steel in concrete is one of the most costly problems in the United States. ~ Approximately half of the nearly six hundred thousand bridges in the US Federal Aid Highway system have structural deficiencies or are functionally outmoded. According to FHWA estimates, a quarter of US bridge decks are badly deteriorated. With the advent of the widespread application of road-salt, expensive repairs are often required within five to ten years. It's a worldwide problem. Research indicates that the service life of buildings in the Arabian Gulf may be as short as five to fifteen years due to premature rebar corrosion. In some cases, rebar corrosion problems occur before construction is complete. In Japan, reinforced concrete bridges near the seashore show rapid deterioration within ten years of construction. Eleven viaducts in the UK built in 1972 began to decay within two years of construction due to the application of road deicing salts. 2 Parking structures are the most vulnerable of all because automobiles bring in salt, but the deck is not rinsed by rain. 3 The corrosion problems discussed above are caused primarily by chloride-induced corrosion of steel in concrete. Chloride penetrates the concrete from sources such as road de-icing salts or sea exposure. It can also be built in through the use of salt-contaminated aggregate, seawater in the concrete, or chloride- based admixtures. Upon achieving a sufficiently large concentration, the chloride causes the depassivation and subsequent rapid corrosion of the steel. The resulting corrosion products occupy a much greater volume than the iron that they replace, and, as such, cause tremendous internal pressure within the concrete. This internal pressure, in turn, causes the concrete to crack and spall, allowing greater access of corrodents to the steel, further accelerating the deterioration of the structure. 2 BACKGROUND In recent years, FBE has seen widespread use in steel reinforced concrete structures as a solution to the aforementioned corrosion problems. An FBE coating works by acting as a protective barrier, preventing both chloride and moisture from reaching the surface of the steel. Its greatest advantage lies in its applicability to existing designs without changes in load capacity or section size, the only change is in the modification of development length.l Over one-hundred-thousand structures utilizing FBE coated rebar (ECR
- Energy > Oil & Gas (1.00)
- Materials > Chemicals (0.88)
- Transportation > Ground > Road (0.86)
- Materials > Construction Materials (0.75)
INTRODUCTION ABSTRACT Severe corrosion of epoxy coated rebar in the substructure of 5 major marine bridges in the Florida Keys was detected after only a few years of construction. Corrosion occurred underneath the coating and was preceded by loss of adherence between the steel and the coating. Damage surveys of the bridges, which were built around 1980, were conducted from 1986 to 2000. Corrosion resulted in delaminated areas (spalls) typically about 0.3 m 2 each. After Initial detection, damage has been steadily accumulating at a rate of approximately 0.1 spall per bridge pier (bent) per year. An initiation-propagation model for corrosion development reproduced the observed trends. The exploratory model assumes distribution of chloride diffusivity, rebar cover, chloride surface concentration, and propagation time. Interpretation of the results suggests that much of the early damage stemmed from rebar with high levels of coating distress, and that damage development depends mainly on the propagation stage of corrosion. Epoxy-coated rebar (ECR) has been used in approximately 300 Florida bridges, principally in an attempt to control corrosion of the substructure in the splash-evaporation zone of marine bridges. Starting in 1986, severe corrosion of ECR began to be observed in five major bridges built between 1978 and 1983 along US 1 in the Florida Keys (1-3). The development of corrosion damage has been recorded periodically. An update for the first 20 years of structural service life is presented here. Table 1 lists the structures affected, nomenclature, and construction information. Three of the bridges (7MI, NIL and INK) were built with drilled shafts supporting columns with connecting struts. The LKY bridge had capped drilled shafts joined by a strut, and V-Piers rested on synthetic rubber pads placed on the caps. The CH5 bridge had drilled shafts with spread footers and precast, posttensioned box columns. Unless indicated otherwise, the concrete used in the substructure was cast in place (CIP) and conforming to FDOT Class IV specifications at the time of construction. Those specifications established w/c<0.41, cement content = 388 Kg/m 3 (658 Ib/yd3), and 28-day strength >23.5 MPa (3,400 psi). The fine aggregate was sand and the coarse aggregate oolitic limestone. The cement type for each structure is indicated in Table 1. The specified maximum chloride content (acid soluble test) for concrete in these structures was 0.24 kg/m 3 (0.4 Ib/yd~). The design clear rebar concrete cover for the substructure of these bridges was 76 mm (3 in). Substantial deviations from that value were often observed, especially in round columns when the rebar cage was not precisely centered. As a result, it was not uncommon to encounter concrete cover as little as 25 mm (1 in) on one side of the column and 125 mm (5 in) on the other side. Some instances of no cover were encountered. Initial chloride content of the concrete in the bridges (from FDOT records) was small for NIL, LKY and CH5, but that it was considerably higher for 7MI (1.8 kg/m 3 (2.9 Ib/yd3)) and INK (0.7 - 2.1 kg/m 3 (1.1 - 3.5 Ib/yd3)). It has been speculated that the higher values reflected seawater contamination of the coarse aggregate. The ECR had been manufactured and coated following ASTM 775 - 76 and ECR placement guidelines in place at the time of construction (t-2). Those guidelines allowed a maximum of 2% unrepaired surface damage at rebar surface. The coating material and applicators for each bridge are listed in Table 1. Rebar sizes ranged from #3 (10 mm diameter) to # 8 (25 mm). Rebar tie wires, as revealed by direct examination, were bare steel. Conventional patch repairs and corrosion cont
- Energy > Oil & Gas > Upstream (0.47)
- Government (0.31)
- 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 An exploration and production company in Nigeria operates an extensive crude oil trunkline system that connects into an export terminal. One of these pipelines, which extends for 37km, suffered severe internal corrosion soon after being commissioned in 1994. An intelligent pig survey conducted in 1996 revealed a maximum wall loss of approximately 5 mm, equivalent to an average corrosion rate > 4mm/yr. A field campaign was conducted to determine the cause of corrosion, and propose solutions. The main defects were verified with ultrasonics, whereas detailed analyses of the aqueous phase, including on-line measurements were used to investigate the corrosion mechanism. Corrosion was predominantly located at the bottom of the pipeline, at places where the oil/water emulsion breaks down and a continuous water phase can accumulate. Only very small amounts of oxygen were found in the pipeline system and oxygen corrosion was ruled out as the main corrosion mechanism, although oxygen may have played a secondary role through the formation of corrosive species which could stimulate under deposit corrosion. The measured dissolved carbon dioxide content of the water in the pipeline is very low and could not cause significant corrosion in the pipeline. Significant quantities of sulfate reducing bacteria were found in water sampled at all locations. In view of the presence of deposits in the lines, bacterial corrosion is extremely likely to be the main cause of the corrosion in the pipeline. A combination of pigging and a batch biocide treatment has been adopted to control the corrosion. INTRODUCTION An exploration and production company in Nigeria operates an extensive crude oil trunkline system that connects into an export terminal. Figure 1 shows an overview of the operating system. Internal corrosion is a major operational concern in this system based on the results of intelligent pig inspections carried out to date. The most affected of these pipelines are: Nun River to Kolo Creek, Kolo Creek to Rumuekpe, and Rumuekpe to Nkpoku. The current 20 inch Kolo Creek - Rumuekpe trunkline, which is scheduled for replacement due to extensive internal corrosion, was installed in 1994 and commissioned in December of that year. The line was installed as a "like for like" replacement for the previous line, which had been installed in 1973. The first line was replaced because it was extensively corroded. The first intelligent pig survey of the original trunkline was carried out in 1986. This showed that some internal corrosion had occurred resulting in a maximum indicated wall loss of 30% and that the area affected was limited to 10% of the line length. It was assumed that this corrosion had occurred over the production life of the line and the corrosion rate was estimated to be ~0.4mm/yr. A later survey in 1991 showed that the line had suffered further internal corrosion but indicated that the rate and extent of the corrosion had dramatically increased with ~ 1000 grade 3 defects (>50% wall loss) and an estimated corrosion rate of ca.1 mm/yr. The line was no longer fit for purpose and was replaced in 1994. No detailed investigation of the nature of the corrosion was carried out at that time. The new line was inspected in February 1996. This survey showed extensive and severe internal corrosion with up to 55% wall loss indicating a corrosion rate greater than 4 mm/yr. The corrosion patterns were similar to those observed in the old line. In view of this extremely high corrosion rate the wall loss was checked and confirmed by manual ultrasonic inspection. A further intelligent pig inspection in November 1996 showed that corrosion had proceeded, but at a slower rate, estimated about 0.6
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- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Constituents > Bacteria (0.35)
- North America > United States > Louisiana > Standard Field (0.99)
- Africa > Nigeria > Gulf of Guinea > Rivers > Niger Delta > Niger Delta Basin > OML 18 > Alakiri Field (0.89)
- Africa > Nigeria > Bayelsa > Niger Delta > Niger Delta Basin > OML 29 > Nembe Creek Field (0.89)
ABSTRACT Extracts of tobacco plants show considerable promise as environmentally acceptable corrosion inhibi- tors. Use of extracts obtained from stems and twigs, as well as leaves, show significant corrosion inhibi- tion during immersion of aluminum or steel in saline solutions and immersion of steel in strong pickling acids. In several cases, the inhibition is greater than that provided by chromates and is provided over a wide range of extract solution concentrations. When steel was treated in sulfuric acid with tobacco ex- tract to remove mill scale and rust, the steel emerged bright and shiny. When treated in sulfuric acid alone, the steel was blackened and pitted. The tobacco extracts provide corrosion protection from a re- newable resource with little or no environmental impact. The use of waste plant material enables an in- expensive source of corrosion inhibitors. INTRODUCTION There is a continual need to develop environmentally friendly corrosion inhibitors to replace the tradi- tional inorganic corrosion inhibitors, such as chromates and lead, which have significant health, safety, and environmental concerns. Both are listed as persistent, bioaccumulative, and toxic (PBT) chemicals] Because PBT chemicals do not readily break down or decrease in potency in the environment, they ac- cumulate and have greater potential to cause long-term human health or ecological problems. They con- tinue to be an environmental concern long after they are used and the nation's goal is to reduce the gen- eration of these chemicals in hazardous waste by 50% by 2005 with source reduction and recycling, as intended by the Resource Conservation and Recovery Act (RCRA), Clean Air Acts, the Pollution Pre- vention Act, and the Hazardous and Solid Waste Amendments (HSWA), among others. Thus, new, ef- fective inhibitors that are safe and environmentally benign must be found. Extracts from tobacco plants show excellent corrosion inhibition properties for several metals. 2"4 The tobacco plant is a virtual chemical factory with over 4,000 compounds being reported by the USDA. Tobacco is currently being evaluated as a production system for antibiotics, sugars, industrial enzymes, and anti-cancer and AIDS compounds. 59 Some of the tobacco constituents show remarkable corrosion inhibitive properties. Tobacco extracts represent a major new initiative in the corrosion inhibition mar- ket with the following potential advantages: ? Low cost and high effectiveness ? Environmentally acceptable ? Low toxicity ? Readily available and renewable. At the beginning of the twentieth century and earlier, biomass, in the form of wood, was the major source of organic chemicals in the US. It is projected that in the coming years, biomass will again come to be viewed as an important, renewable feedstock for the wide range of needed chemicals. Biomass has a potential advantage over petrochemical feedstocks: it already contains a wide range of naturally- synthesized chemical compounds that can be extracted by straightforward processes, obviating the need for complex manufacturing syntheses from basic, petroleum-derived, building blocks. Tobacco should be viewed as an incredibly rich source of complex chemicals. Extraction of chemicals from biomass is a more attractive approach than merely using biomass to make fuels as the latter destroys these complex molecules. Corrosion inhibitors have been studied for many years [see, e.g., Ref. 10 and 11]. Many types of or- ganic compounds have been found to act as inhibitors [see, e.g., Ref. 12 and 13], but most of these com- pounds have remained as laboratory data. One reason seems to have been that the cost of manufacture of these compounds is generally to
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- 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 > Environment (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Materials and corrosion (1.00)
INTRODUCTION ABSTRACT In order to evaluate the adaptability of hydroxyethane diphosphonic acid (HEDPA) as an environmentally benign alternative rust removal agent, a systematic investigation is being carried out. The effectiveness of HEDPA was thoroughly investigated as a function of acid concentration in the range 2-100 vol.% and at different temperatures in the temperature range 27 - 60°C. The results suggest that the acid HEDPA is very effective in the rust removal process. The rate of rust removal by HEDPA is strongly dependent on the acid concentration and the solution temperature. Once an optimum threshold is reached an increase in either the acid concentration and/or temperature has a negative effect on the reaction kinetics. While the rust was completely removed by the 2 vol.% HEDPA within 3 hours at 27°C, the rust removal was completed within 30 minutes of treatment at 60°C. Similarly, while, the complete rust removal by 2 vol.% HEDPA was noticed after 3 hours, 10 vol.% HEDPA required chemical treatment for 0.75 hours at 27°C. However, chemical treatment with as received 100 vol.% HEDPA did not dissolve even 20% of the rust after 6 hours and the rust removal at 60°C was <2 %. Chemical treatment of rusted steel samples with concentrated HEDPA solution (concentration range 5 - 100 vol.% HEDPA) has produced rust free steel samples with very rough surface topography. In addition, the chemical processing at higher temperatures (40 - 60°C) and higher HEDPA concentrations (5- 100 vol.%) produced strong pungent smell and unpleasant cleaning environment. The most effective HEDPA concentration and temperature for the rust removal appears to be 2 - 4 vol.% and<40°C respectively. The activation energy for the rust dissolution process also appears to increase with an increase in the acid concentration. However, it appears that the increase is not very significant for the concentrations in the range 2 - 4 vol% HEDPA (2 vol.% - activation energy 11 + 1 kcal/mole; 3 vol.% - activation energy 12+ 3 kcal/mole and 4 vol% - activation energy 14 + 2 kcal/mole). The activation energies for rust dissolution by 5, 10 and 20 vol.% HEDPA were found to be 20, 28 and 32 kcal/mole respectively. Above, 20 vol% HEDPA concentrations, a semi-quantitative determined value for the activation energy is 2 + 2 kcal/mole. Prolonged treatment of samples with HEDPA allows the deposition of the reaction products onto the cleaned sample surface. The reaction product contains a mixture of various higher order iron phosphates. The development of new materials with improved hot water and salt water / salt water corrosion resistance is very important. As these materials are being proven, it is also important to develop procedures and methods to maintain the existing materials currently in use. Advanced technological maintenance processes would have applications in several areas, viz. the electric utility communities, for the removal of deposits from the thermal power plant equipment, and in the civilian and military ship building industry where the removal of corrosion products from ship platforms, on-board tanks, etc. is necessary. Recent trends in the industrial and military sectors emphasize a mandated cost savings on material acquisition, results in reduced regular equipment purchases. Therefore, it is even more important to extend the operational life of the presently available systems. In addition, the effects of new environmental policies on maintenance processes have to be considered. The common classical rust and/or paint removal methods are based on the use of inorganic abrasive grits. This is changing to the use of organic grits, fine dry ice particles, and, most recently, the u
- Production and Well Operations > Production Chemistry, Metallurgy and Biology (1.00)
- Well Completion > Well Integrity > Subsurface corrosion (tubing, casing, completion equipment, conductor) (0.89)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Materials and corrosion (0.89)
ABSTRACT Corrosion in a shipboard waste drain system piping resulted in at-sea failures and impacted ships' operations. Metallurgical analyses of pipe sections removed from service identified the failure mechanism to be poultice corrosion enhanced by the presence of sulfides and high flow rates or excessive turbulence. A variety of methods to mitigate the corrosion including water treatment, materials substitution, coatings, and cathodic protection were investigated. Applying coatings to the inside diameters of the piping runs was most attractive from both logistics and cost standpoints compared to the other corrosion control methods studied. A flexible extension for a standard commercial powder coating gun was developed in order to apply coatings to internal piping surfaces. This extension allows application of heat cured epoxy powder coatings to piping runs up to six feet in length that contain multiple short radius elbows. Implementation of the coating process will result in significant corrosion reduction and related maintenance cost savings while ensuring operational readiness of the fleet. INTRODUCTION Routine wall thickness monitoring of a shipboard piping system identified unexpectedly high rates of wall loss in localized areas. In some cases, the localized corrosion actually penetrated the pipe wall, Figure 1. As a result, the U.S. Navy was interested in determining the root cause of the corrosion and developing a cost-effective method to correct the problem. The piping system operates intermittently and carries gray water containing a relatively high level of organic solids. The lack of corrosion in similar systems which carry only seawater indicated that the operation and/or environment in the piping system contributed significantly to corrosion susceptibility. Accelerated corrosion mechanisms consistent with this observation included sulfide-induced corrosion and under-deposit (or poultice) corrosion. High flow rates or excessive turbulence may have also acted to exacerbate corrosion by removing naturally forming protective corrosion product layers. The appearance of the corrosion product films indicated that the pitting primarily initiated on the bottom of horizontal piping runs where debris could readily accumulate. A ready source of organic material and the intermittent use of the system contributed to the accumulation of deposits, leading to putrification and generation of sulfides. Copper-nickel alloys are susceptible to accelerated corrosion in seawater containing high sulfide, low pH concentrations, and high total organics [1]. Sulfide pollution can occur in several ways: (1) bacterial reduction of naturally occurring sulfates in seawater; (2) rotting vegetation; and (3) industrial waste discharge. Hack and Gudas [2] showed that 90/10 Cu-Ni was susceptible to sulfide induced pitting in natural, flowing seawater containing 0.01 ppm or more sulfides. 70/30 Cu-Ni was similarly susceptible to sulfide-induced pitting but required higher sulfide concentrations. Sulfide modified films generally were more loosely adherent than the normal cuprous oxide films; turbulence tended to selectively remove the sulfide-modified films. The exposed surfaces are anodic to the surfaces covered by the films and localized corrosion at the exposed sites is promoted. Depending on water quality, additional sulfide-modified films may form and the process becomes cyclic. The measured corrosion potentials of 90/10 and 70/30 Cu-Ni alloys with sulfide modified films shifted to more noble (electropositive) values than Cu-Ni with the normal Cu2(OH)3C1 and Cu20 corrosion product films [2-4]. The ease by which sulfide-modified films are removed supports the electrochemical/me
ABSTRACT Two green inhibitor formulations have been developed for treating aluminum alloys 2024-T3 and 6061-T6. The formulation consists of the oxoanion MnO4- with a catalytic amount of either Cr(VI) (50Bg/L present as dichromate) or acetic acid. Both formulations are considered green since they contain Cr(VI) concentrations that are below the EPA safe limit for drinking water that is 100Bg/L. The inhibitor formulations have been previously tested on anodized aluminum alloy coupons followed by sealing in a bath containing the inhibitor formulation. The combination of anodizing and sealing lasted over 9 months in a salt fog prohesion test environment 1. Although, this formulation has been shown to work on anodized systems, the largest impact for Cr(VI) replacement will come from conversion (immersion) coating applications. This paper presents the results of how these green inhibitor formulations perform on a non-anodized surface. Aluminum alloy coupons (2024-T3,606 l-T6 and 7075-T6) treated with both formulations along with a matrix of their components were tested using anodic potentiodynamic polarization, electrochemical impedance spectroscopy (EIS) and ASTM B 117 Salt Fog Testing that included unpainted and painted samples with and without scribes. The electrochemical test results are compared against salt spray data, and the correlation between the two approaches is discussed. INTRODUCTION For many years the treatment of aluminum and its alloys for corrosion protection has involved processes where Cr(VI) played a key role in achieving the desired protection. Replacement of hexavalent chromium, Cr(VI), is now a high priority for preservation of the environment and worker safety 2. Although an extensive effort has been and continues to be directed toward the identification of a viable, general use substitute for chromate, successes have been limited 3-16. However, what does emerge from this extensive database is that the action of the Cr(VI)/Cr(III) redox couple provides the corrosion protection and species such as chloride ions disrupt this protection 17. It is the objective of this work to develop chromate-free formulations that have similar or better corrosion inhibition efficiency than Cr(VI) formulations and are alloy and application independent 1,18-19 For the purpose of inhibitor chemistry development, a strategy was chosen that breaks the inhibitor action into two separate components: 1) a portion of the inhibitor is reduced to produce a protective film product and 2) a small portion of the inhibitor serves to mediate this redox reaction and regenerates itself at a high enough rate to sustain production of the protective film as long as trigger ions (e. g.; chloride ions) are present. This strategy has led directly to the study of inhibitors with Cr(VI) concentrations below the EPA limit of 100 l.tg/L allowed in drinking water 20. To further explore the two-component inhibition mechanism presumed to be naturally active in high chromate inhibitors, the oxoanion, MnO4- has been used as the majority component in stock solutions to which small concentrations of Cr(VI) and other mediators have been added. The inorganic analogs of chromate are environmentally acceptable and known to inhibit corrosion in Al-alloys but do not provide the level of protection achieved by chromates 21-23. Extension of this strategy has yielded an effective and fully chromate free corrosion inhibitor formulation by the replacement of the Cr(VI) mediator with acetic acid in an anodized and sealed application 19. This paper presents the effects that small concentrations of Cr(VI), 50 l.tg/L, have on pseudo- passive oxide layers and how both of these inhibitors affect the pola
Assessment of Operating Limits for Critical Dissimilar Metal Welds in a Hydrocracker
Lewis, Keith R. (Global Solutions International BV) | Koers, R.W.J. (Global Solutions International BV) | Van Worter, J.C. (TNO Institute of Industrial Technology) | Krom, A.M.M. (TNO Institute of Industrial Technology)
ABSTRACT The risk of failure of ferritic alloy steel to austenitic stainless steel dissimilar metal butt-welds in a refinery hydroprocessing unit increases with operating temperature and shutdown cooling rate due to the combined effects of hydrogen diffusion and thermal fatigue. Operating limits of this type of weld were assessed with finite element modeling and simulation tests, and the findings from this work were supported by plant inspection results. As a result, both the maximum operating temperature and cooling rate constraints were relaxed for critical equipment and piping in a hydrocracker unit. INTRODUCTION In some recently built hydroprocessing units dissimilar metal welds (DMWs) have been extensively used in hot hydrogen service to join austeniUc stainless steel piping to low alloy (Cr-Mo) steel or internally clad Cr-Mo steel equipment. There are significant safety and process incentives to use such welds rather than have many large high pressure flange connections in these units. Reducing the number of flange connections makes the unit layout more compact and lowers project costs. Figure 1 shows the typical locations for the most critical of these DMWs in hydrocracker feed/effluent heat exchanger train and Figure 2 shows the scale of the heat exchangers evaluated as part of this study. Table 1 shows typical operating parameters and construction details. The risk of failure of DMWS in this service increases with operating temperature and shutdown cooling rate due to the combined effects of hydrogen diffusion and thermal fatigue. The most critical location is the fusion boundary between the austeniUc weld metal and the low alloy steel, with a failure mechanism comparable to disbonding of weld overlay cladding from base material. When such welds are used in hydroprocessing units strict controls on fabrication have been applied along with a restriction on the maximum operating temperature. Inspection of the most critical welds using automated ultrasonic methods during fabrication and shutdowns are considered necessary to ensure freedom from in-service cracking. This paper describes how the results of a recently completed DMW weld Joint Industry Project have been combined with the results from a disbonding research JIP and stress analysis to study if an increase of the service temperature of critical DMWs in a Hydrocracker Unit (HCU) will increase the likelihood of failure. Operating limits were assessed with simulation tests and finite element modeling and the findings from this work were supported by plant inspection results. As a result, both the maximum operating temperature and cooling rate constraints were relaxed for critical equipment and piping in two recently constructed HCUs .The higher operating temperature limit for the DMWs provides more operational flexibility or higher end-of-run temperature and consequently longer run length between catalyst changes. Obviously the refinery margin implications of this increased temperature are significant. BACKGROUND Industry concerns regarding the integrity and reliability of DMWs in corrosive environments found in the oil and gas industries, including high pressure high temperature hydrogen, are well documented in a recently published in the TWl article [1]. Within a DMW the mixture of materials results in a compositional gradient across the weld fusion lines leading to complex microstructures. DMW microstructures usually include Local Hard Zones (LHZ) of martensite. Differential thermal expansion coefficients of the materials in DMWs, combined with cyclic operation between ambient temperature and the operating temperature, can lead to thermal stress and fatigue problems. Hydrogen at high temper
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ABSTRACT Experiments were performed where steel specimens were cathodically polarized in natural sea water by galvanic coupling through an external resistor to an aluminum anode. Temperature was either ambient or 5°C; and pressure was atmospheric or 8.96 + 0.14 MPa (1,300 + 20 psi), which is equivalent to a water depth of 899 m (2,950 feet). For some experiments, dissolved oxygen concentration was controlled at 5.5 + 0.2 mg/1 and pH was 7.8. These corresponded to values that were measured at the above depth for a specific Gulf of Mexico site. The apparent steady-state potential (¢c) and current density (ic) for the different experiments were compared with previously reported ambient temperature and pressure data. Calcareous deposits that formed on specimens from each of the test categories were viewed and analyzed. The long-term Oc-i~ trend for the different tests was the same at the two pressures and for 5.5 compared to 9 mg/l 02. Also, i~ was independent of 0~ over the potential range investigated (approximately --0.80 to -1.10 VSCE) despite differences in the calcareous deposit structure and composition. The results are discussed in terms of, first, design criteria for deep water cathodic protection and, second, experimental testing to develop such criteria. INTRODUCTION Increasingly, the offshore petroleum production industry has focused upon deep water exploration and production, particularly in the Gulf of Mexico. However, while recommended practices regarding cathodic protection (cp) and criteria pertaining thereto have been developed for near-surface ocean waters (1,2)*, comparable information is not available for deep water. This statement must be qualified in view of the recent advent of the slope parameter approach to cp design (3-6) and the unified design equation that was developed there from. Also, appropriateness of existing design current densities has recently been brought into question (7). While the -0.80 VAg/AgCI potential criterion for corrosion protection is considered to apply equally to both deep and shallow water, the current density to achieve this potential and, in particular, to establish the most effective and efficient level of cathodic protection can at the present time only be confidently determined by long-term, in-situ deep water experiments involving prototype specimens, an approach that is both costly and time consuming. This inability on the part of technologists to define the design current density for a particular deep water site results from uncertainties regarding protectiveness of any calcareous deposits that are likely to form (assuming that deposits do form) and, there from, to project oxygen availability and the rate of oxygen reduction. Thus, while considerable past research activity has addressed the precipitation kinetics of calcareous deposits and how these are affected by influential variables (8-14), still the present state-of-knowledge falls short of permitting design current density prediction for frontier deep ocean sites. Reasons for this include the fact that 1) past research programs and experiments were mostly either potentiostatic or galvanostatic, whereas galvanic anode cp systems are of a mixed mode or free running type, 2) addressment of how cp system design is affected by environmental variables relevant to deep water has not been extensive, and 3) uncertainties exist regarding the interactive influence of variables. Based upon current understanding, calcareous deposit formation is most strongly affected by temperature, pH, water composition, and flow; and ocean depth is important primarily as it influences these factors (9). Values for the first three (temperature, pH, and water composition) determine the extent to whi