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The Role Of Coatings In The Generation Of High-And Near-Neutral Ph Environments That Promote Environmentally Assisted Cracking
Been, Jenny (NOVA Chemicals Corp) | King, Fraser (NOVA Chemicals Corp) | Yang, Lin (NOVA Chemicals Corp) | Song, Fengmei (Southwest Research Institute) | Sridhar, Narasi (Southwest Research Institute)
ABSTRACT Accurately predicting where high- or near-neutral pH stress corrosion cracking (SCC) of buried pipelines is possible requires a prediction of the environmental conditions at the pipe surface under the disbonded coating. This is a challenging task since traditional above-ground measurements give little information about the pipe-surface environment. If such predictions could be made, however, the success of selecting locations for direct examination as part of the direct assessment methodology or for other maintenance activities would be greatly enhanced. The nature of the coating degradation has a significant impact on the development of environmental conditions for SCC. A series of soil box tests has been performed to determine the evolution of the trapped water environment under disbonded shielding polyethylene tape coating. The effects of soil type, moisture content and drainage, and CP level have been studied. In a second series of tests, the relative effects of current demand and coating permeability on the generation of high-pH SCC conditions under disbonded permeable coating have been studied. The results of the tests on shielding coating have been analyzed using two computer models; a Transient ElectroChemical TRANsport model (TECTRAN) for shielding coating and the Permeable Coating Model (PCM) for permeable coatings. The aim is to use such codes to predict the pipe surface environment based only on above-ground measurements and other readily available information. INTRODUCTION Direct Assessment (DA) is being increasingly used for managing various internal and external integrity threats for liquid and gas pipelines. One of the key requirements of the DA process is the selection of suitable field locations for direct examination of the pipe. Above-ground electrical measurements are typically used to select sites for excavation and direct examination, ~ although observations of the terrain conditions can also be used, especially for stress corrosion cracking (SCC). 2 What determines whether corrosion or SCC will occur, of course, is the environmental conditions underneath the disbonded coating. Therefore, any technique that determines or predicts the composition of the trapped electrolyte and the distribution of potential on the pipe surface will improve our ability to select sites for direct examination. SCC, or environmentally assisted cracking (EAC), is known to be associated with specific environmental conditions at the pipe surface. 3 Figure 1 shows the range of potentials and pH associated with the two forms of EAC on pipelines, commonly referred to as near-neutral and high-pH SCC. Near-neutral pH SCC occurs in dilute bicarbonate solutions (typically-0.01 mol.dm 3) at potentials close to the corrosion (or native) potential in deaerated solution. As the name suggests, the pH of the trapped water in contact with the pipe surface under the disbonded coating is in the range pH 5.5-7.5. 3 Both the potential and pH for this form of cracking imply that current from the cathodic potential (CP) system does not reach the pipe surface. In practice, near-neutral pH SCC has often been found under disbonded polyolefin tape coating, which is electrically insulating and is known to "shield" the pipe from the CP system. Near-neutral pH SCC, however, has also been reported for coatings that are traditionally believed to allow CP to reach the pipe surface, so-called "permeable" or "CP-compatible" coatings, 4 such as asphalt. 5 High-pH SCC occurs in concentrated (0.1-1 mol-dm -3) carbonate-bicarbonate solutions in the range pH 9.5-11.5. 3 Cracking occurs over a specific range of potentials that corresponds to the active-passive transition for C-steel in this environment. The
- Energy > Oil & Gas > Upstream (1.00)
- Energy > Oil & Gas > Midstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.34)
ABSTRACT Salt-induced hot corrosion is an accelerated mode of degradation that is known to occur in various high temperature engineering applications, including marine gas turbines. In order to improve the life of hotsection superalloy components, they are often coated with an aluminide. In this study, the hot-corrosion resistance of different types of â-NiAl aluminides and CoCrAlY-based coatings on nickel-based superalloys 247 and 792 was assessed. The coatings were tested under cyclic high-temperature (HTHC- 900oC) and low-temperature (LTHC-705oC) hot corrosion conditions using a laboratory-based Dean rig. The hot corrosion conditions were simulated by depositing Na2SO4 salt on the coated samples and then exposing the samples to a O2 + 0.1%SO2 flowing gas environment. HTHC testing was performed for up to 500 hours, while LTHC testing was performed for up to 200 hours. The effect of pre-oxidation on LTHC resistance was also studied. Coating performances under both HTHC and LTHC conditions were ranked by assessing the extents of attack around the circumference of each coated sample, together with maximum depth of attack. The corrosion products and phases present in the as-received and corroded coatings were characterized. Finally, was found that pre-oxidizing at 1050oC improved the resistance of the coatings to LTHC. INTRODUCTION The surface degradation of marine gas-turbine components can occur by high temperature oxidation (>1000ºC) and/or hot corrosion (~ 850-1000ºC for type I and 600-800ºC for type II) 1. Salt-induced hot corrosion is an accelerated mode of surface degradation in marine environments. The severe environments encountered from hot corrosion in turbines generally require that the nickel-base superalloy components be protected by diffusion or overlay coatings2. The most widely used diffusion coatings are based on the aluminide â-NiAl, while overlay coatings are typically based on an MCrAlY composition in which M represents Ni, Co or Ni + Co. The performance of coatings depends upon their chemical composition and microstructure. Hot corrosion resistance of aluminide coatings is often improved by the addition of modifying elements like Pt, Cr and Si 3-10. Addition of Pt to aluminide coatings improves HTHC and oxidation resistance, but it is not as beneficial at low temperatures. Indeed, addition of Pt tends to reduce surface spallation by promoting the slow growth of extremely adherent á-Al2O3 scale11. Haynes et al.12 and Zhang et al.13 found that, along with improved scale adhesion, Pt also helped in decreasing detrimental effects of high S levels in the substrate and reducing the amount of voids at the scale/metal interface. Addition of Cr has been shown to improve hot-corrosion resistance at both low and high temperatures3, 4. In addition, Cr can be beneficial to oxidation resistance by decreasing the amount of Al in the alloy required to form a protective Al2O3 scale layer14, 15. As discussed by Rapp16 the basic dissolution of Cr2O3 and Al2O3 results in the formation of CrO4 2- and AlO2 - ions respectively, and produces a positive solubility gradient thereby inhibiting further basic fluxing.
- 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 Two distinctly prepared epoxy coating systems characterized primarily by Electrochemical Impedance Spectroscopy (EIS) after having been exposed for 2 weeks to ASTM D 1141 electrolyte (substitute ocean water), were subjected to various laboratory environment drying periods. The coating types were a conventional solvent based MIL-DTL-24441, Type IV system and a "100% solids" type system reported to satisfy MIL-P-23236. The EIS data show both fully water saturated coating systems lose approximately 50% of the absorbed water within 48 hours of drying, which significantly affects the EIS parameters. Approximately 10 days' re-exposure to the test electrolyte was required to reestablish the near-saturated water level and EIS characteristics. Electrochemical differences between the two types of epoxy coating systems are presented and discussed. BACKGROUND AND INTRODUCTION The task of characterization of organic coatings applied to metallic substrates (for protection from environmental exposures) via electrochemical means within a modem laboratory environment is normally a straight forward procedure. Conventional testing protocols are established for the monitoring of certain electrochemical characteristics while the samples remain in continual immersion in the test environment of interest. For applied-research testing of U.S. Navy applications, the test electrolyte is normally substitute ocean water per ASTM D 1141, with or without the trace dissolved heavy metals. Typically, o-ring sealed, glass cylinders are placed onto a selected flat area of a painted metal plate and the electrolyte of interest is added and retained on the test area throughout the exposure time of interest. This test cell approach avoids problems associated with thin coating areas at the sample edges and has been successfully used for monitoring epoxy- polyamide coating formulations over several years of continuous exposure 1. Field evaluation of marine coatings especially on actual hardware presents additional challenges. A ship comes into drydock. If the hull coating system is the issue, one question that needs resolving is how much time does one have before the air exposure dries the coating system so as to make any electrochemical measurements relatively meaningless. The related question then is if drying has occurred, how much re-wetting time must pass to result in the 'as-arrived', wet-coating condition. The questions on how the U.S. Navy marine service coatings would respond to drying and re-wetting arose from a recent study of the wetting and drying of thin, somewhat complex coil coatings applied to galvanized steels 2'3. Those particular 25 to 50 micron thick coating systems were found to lose approximately 40% of the absorbed moisture within 30 minutes of exposure to an ambient laboratory environment. A drying period of no more than 10 minutes was recommended to minimize the effect of drying on the EIS parameters that would include the coating electrical capacitance (Ccoat), the upper coating impedance limit measured at low frequencies (Zmax), and the high, break-point frequency (fhi). Once drying had occurred, at least 10 hours' re-wetting was found to be required to approach about 80% of the previously absorbed moisture. Those findings then led to this effort. In addition to acquiring drying/re-wetting data with respect to the thicker Navy hull and tank coatings, a second goal was to attempt to determine what differences might be observed in the testing of the organic solvent-based epoxy/polyamide coating system as defined within MIL-DTL-24441, (the Type IV version), and the 'newer', solvent-free, 100% Solids type epoxy coating system (dubbed 100% Solids hereafter) per MIL-P-23236. EIS testing of conti
- Transportation > Marine (0.88)
- Materials > Chemicals (0.75)
- Government > Military > Navy (0.68)
- (2 more...)
- 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)
Practical Experiences In Validating The Ecda Process ? Comparing Indirect Inspection Results And Direct Examinations
Powell, Daniel E. (Corrpro Companies Inc.) | Miller, Marvin L. (Corrpro Companies Inc.) | Rankin, Larry (Corrpro Companies Inc.) | Bongiovi, Mike (Corrpro Companies Inc.) | Baezner, Michael A. (Corrpro Companies Inc.) | Houder, Delyn (Corrpro Companies Inc.)
ABSTRACT This paper provides an overview of the external corrosion direct assessment (ECDA) process by presenting the practical application of the process to a gas transmission pipeline owned by Company A. The paper describes each of the indirect inspection techniques used to assess the condition of the external coating on the buried pipeline, and then compares those results to results from direct examinations of selected sections along the pipeline. In addition, comparisons are also made to results from in-line inspections of that same pipeline. Note that the results from the in-line inspection results were not made available until after the selection of the locations for excavation and direct examinations. Close agreements were found between the location and severity of damage to external coatings, based on indirect inspections and direct examinations. Additionally, close agreements were found between the severity of corrosion, as determined from direct examinations, and that indicated by in-line inspections. As such the ECDA process was validated by these studies on Company A?s pipeline. The Pipeline Research Council International (PRCI) has overseen the validation of the ECDA process, based on the studies of multiple pipelines. This paper provided an overview of just one of these studies. When competent personnel follow the ECDA process, it will provide an accurate assessment of the condition of possible external corrosion on buried pipelines. INTRODUCTION There are approximately 322,000 miles [518,200 Km] of gas transmission pipelines throughout the United States. The Pipeline Safety Improvement Act of 2002 was signed into law December 17, 2002, and requires pipeline operators to inspect the natural gas transmission pipelines in High Consequence Areas (HCAs) within the next ten (10) years. This is to confirm the integrity of each of the pipelines, and the legislation allowed for the inspections or integrity assessments to be conducted by (a) hydrostatic pressure testing, (b) in-line inspections (intelligent pigging), (c) External Corrosion Direct Assessment (ECDA), or (d) comparable methods, which may be developed in the future. The legislation effectively recognized the ECDA process as the functional equivalent to the traditionally used hydrostatic pressure testing or in-line inspections. Although the name ECDA process is relatively new, indirect inspection tools have been used for many years to identify the location of coating flaws on the exterior surface of pipelines and possible external corrosion. The obvious question is whether the ECDA process is as effective as in-line inspections or hydrostatic pressure tests in confirming the integrity of sections of natural gas transmission pipelines. This paper compares the results from indirect inspection tools to results from in-line inspections and direct examinations of excavated sections of pipeline. Note that results from the ILI were not available until completion of the ECDA process, such that a valid, unbiased comparison of results was possible.
- Research Report (0.68)
- Overview (0.66)
- Well Completion > Well Integrity > Subsurface corrosion (tubing, casing, completion equipment, conductor) (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Piping design and simulation (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Materials and corrosion (1.00)
ABSTRACT Corrosion costs for United States (U.S.) Army ground vehicles are estimated at $2 billion per year. A study was conducted to evaluate how sacrificial metallic coatings applied on steel by electroplating, galvanizing, spray painting, flame spray (FS), arc spray (AS) and high-velocity particle consolidation (HVPC) enhance the corrosion protection afforded by coating systems. The coatings in this study were Zn, Zn-1Co and Zn-12Ni electroplates; Zn, Zn-5Al and Al-44Zn-1.6Si galvanized coatings, zinc-rich primers, Zn, Al, and Zn-15Al thermal sprays and Zn and Al HVPC. Thickness of the metallic coatings ranged from 4.8 µm for electroplated Zn-1Co to 279.4 µm for FS Zn-15Al. A salt fog test and a cosmetic corrosion laboratory test were carried out on scribed steel panels with the above coatings. Atmospheric exposure tests of these metallic coating systems are underway at an oceanfront test site. The top twelve coatings in the cosmetic corrosion laboratory test included eight thermal sprayed Zn, two HVPC-Zn, and a flame sprayed Zn-15Al and Al. Keywords: electroplate, galvanize, flame spray, arc spray, high-velocity particle consolidation, zinc, aluminum, nickel, cobalt, chromate, zinc phosphate, hexavalent chromium, trivalent chromium, zincrich primer, galvanic protection, ASTM B117 continuous salt fog, SAE J2334 INTRODUCTION In 1995, the Department of Defense (DoD) estimated its yearly cost of corrosion prevention and control at $10 billion1. A more recent study2 showed that the total annual cost of corrosion incurred by the military services for both systems and infrastructure was estimated at $20 billion. U.S. Army ground vehicles are estimated to account for $2 billion per year of these corrosion-related costs. In the original design of the High-Mobility Multipurpose Wheeled Vehicle (HMMWV), the frame rails were made of 1010 carbon steel with no galvanizing protection and no provisions for draining water out of the interior cavities in the rails. Water, salt, and mud could accumulate in the cavities within the frame rails and cause corrosion of the painted steel. Newer HMMWV frame rails are now being galvanized and electrocoated. An Inspector General?s audit3 identified various areas such as uncoated steel, galvanic couples, and rivets where corrosion was occurring on these vehicles. A General Accounting Office (GAO) report4 on the investigation of 275 ground vehicles showed that approximately one third of various components in the vehicles were suffering from corrosion damage. Corrosion-related problems can also impact mission readiness.
- Government > Regional Government > North America Government > United States Government (1.00)
- Government > Military (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 corrosion of steel pilings in seawater was investigated during the past 30 years at two field locations in the United States, one in the Gulf of Mexico at La Costa Island, Florida (1971), and the other in Buzzard?s Bay, Massachusetts (1974). Three rows of 22 test steel H piles, 20.3 cm x 20.3 cm and 12.2 meters long, were installed at the Buzzards Bay, Massachusetts test site, where the test temperature varies from ?1° C to +19° C. The steel H-plies were coated with various protection systems, such as coal tar epoxy, polyurethane, flame sprayed zinc and aluminum. Several of the piles were left uncoated for baseline comparison. Sacrificial cathodic protection was provided by anodes to some of the bare and coated steel pilings. Periodic inspections were conducted and a row of pilings was pulled out after 5 years for detailed inspections. The results of the long term coating evaluation showed that flame sprayed aluminum coating with a topcoat sealer performed best in the cooler temperature at Buzzard?s Bay and the thick polyester glass flake coating was the best performer in Florida. Coal tar epoxy coatings with zinc rich primers also performed well at both locations. The average corrosion rates at the two test sites were determined by measuring the thickness of the flange after the steel piles were pulled out for detailed evaluation. Measurements indicate that, in some cases, concentrated corrosion was encountered, where the corrosion rates were more than twice as much within 1 m below the mean low water line, compared to corrosion rates in other regions of the immersed zone. These higher corrosion rates could be attributed to accelerated low water corrosion (ALWC), a rapid form of microbial assisted corrosion. The solutions include thicker steel, protective coatings, cathodic protection and design considerations. INTRODUCTION Steel pipes and H-piling have been used most often for foundations in coastal areas. The designers can choose from among many types of coatings to protect these structures. Cathodic protection must also be considered. In brackish or seawater applications, where the life of even the best coating systems are limited, cathodic protection can provide supplemental protection. For rapid screening of these coatings and primers, nondestructive measurement techniques, capable of predicting long-life (50-year) performance based on test of shorter duration, are valuable. However, such tests conducted in the laboratory do not simulate actual field performance. Field tests at various geographic locations are necessary because environmental effects such as marine growth, temperature and tidal conditions are important parameters that cannot be simulated in the laboratory. In response to this problem, the U. S. Army Corps of Engineers Construction Engineering Research Laboratory (CERL) installed pilings at LaCosta Island in January 1971 and at Buzzards Bay in October 1974. Inspections of the piles have been conducted periodically since then.1-8 For the study of corrosion of these pilings, six areas or separate zones9 along their length are considered as shown in Figure 1. These zones are: (1) atmospheric zone, in the dry, exposed only to the salt laden atmosphere; (2) splash zone, above the mean high water spring (MHWS) tide line, which is subjected to the corrosive effects of salt spray and salt laden atmosphere; (3) tidal zone, which is alternately wet and dry due to MHWS tides and mean low water spring (MLWS) tide respectively; (4) intertidal low water zone, located 0.5 m below MLWS down to the lowest astronomical tide (LAT) lines; (5) continuous seawater immersion zone, which is always underwater; (6) the embedded zone, which is buried in the mud. Corrosi
- Geology > Mineral (0.69)
- Geology > Sedimentary Geology > Depositional Environment (0.35)
- Materials > Metals & Mining (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.89)
- North America > United States > Ohio > Denmark Field (0.89)
- Europe > Netherlands (0.89)
- 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)
Research of New Anti-Corrosion Coating for Equipment in Littoral
Jie, Zhi- (Academy of Armored Force Engineers) | Gang, De- (Academy of Armored Force Engineers) | Bin, Huang Yan- (Academy of Armored Force Engineers) | Zhao, Huo ying (Academy of Armored Force Engineers) | Kong, Ming (Academy of Armored Force Engineers) | Ma, Yong- li (Academy of Armored Force Engineers)
ABSTRACT In littoral many equipments are eroded seriously by the special ocean environment. In order to develop a new organic anti-corrosion coating, this paper describes choosing silicone resin with better waterproof and weatherability as main material, and epoxy resin and polyester as modifiers. By researching the rule of modifying reaction, the new modified resin develops better adhesion to metal. In order to make components of modified resin completely solidified, the matching curing agent with polyfunctional groups was prepared. By researching the relation between content and property, the relative mass of pigments is chosen. A new anti-corrosive paint TES-01 with superior rust and abrasion resistance is developed. Properties testing and analys is of the new coating is applied, and compared with two kinds of anti-corrosion paints in use. The results indicate the newly developed coating takes on superior resistance to salt fog and salt water corrosion, better surface abrasion resistance and improved high-temperature resistance. So it will be widely applied in the area of anti-corrosion, especially in littorals. INTRODUCTION In littoral many equipments, especially metal parts, are eroded seriously by the special ocean environment. Our state has to devote much manpower and financial in maintaining the eroded metal equipments, which makes a large loss to national economy and people?s living. So it is important to develop new efficient anti-corrosion material for the equipments in littoral. Presently, most domestic organic protecting coatings are single resin, such as polyester, chloroethylene, epoxy, etc. But because of the high permeability, corrosive medium, e.g. chlorine ion can penetrate the paint film, sedimentate on the surface of metal, and cause corrosion by the chemical and electro-chemical reaction. In order to develop a new organic anti-corrosion coating, this paper describes choosing silicone resin with better waterproof and weatherability as main material, and epoxy resin and polyester as modifiers. By researching the rule of modifying reaction, the new modified resin develops better adhesion to metal. The matching curing agent with polyfunctional groups is also prepared. By researching of the relation between content and property, the relative mass of pigments is chosen. A new anti-corrosive paint with super rust and abrasion resistance will be developed.
- Well Completion > Well Integrity > Subsurface corrosion (tubing, casing, completion equipment, conductor) (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (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 This paper describes an application of the ECDA methodology detailed in Industry Standard ASME B31.8S and in NACE Standard RP0502-2002 to a non-piggable section of 30 (76.2 cm) liquid CO2 pipeline. The segment selected was a High Consequence Area (HCA) approximately 10 miles (16.1 Km) long. All field measurements were georeferenced to the pipeline centerline by Latitude/Longitude (GPS) coordinates, integrated and spatially synchronized for analysis. Dedicated software was used for the integration of all survey data. A data integration procedure was developed and utilized to evaluate the indirect examination results, resulting in a refined procedure for spatial control. Spatial synchronization was found to be an important factor to control and log each indirect examination. Analysis of the integrated field inspection results did not reveal any areas with potential for external corrosion activity. Since this is the first application of ECDA in this HCA, two direct examinations were considered. No active corrosion was observed in either of the two excavation sites. In the event that external corrosion had been identified at the initial sites, A sampling plan was also developed resulting in a dig schedule for the additional direct examinations. The application of these techniques was successful in demonstrating the appropriateness of the ECDA approach in locating corrosion concerns on this pipeline. INTRODUCTION In-line Inspection of pipelines can be constrained by issues relating to the ability of flow conveyed tools to navigate tight radius bends, diameter constricting valves, lack of launch and receiver facilities, the ability to gather data at normal product flow velocities and possibility of the current in-line inspection techniques to work in liquid CO2. Hydrostatic Testing of pipeline segments is an established method of determining immediate integrity, but aside from direct testing cost, the potential for disruption of distribution and above ground locations in urban areas, in order to implement wide spread testing is a serious concern.
- Well Completion > Well Integrity > Subsurface corrosion (tubing, casing, completion equipment, conductor) (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Materials and corrosion (1.00)
- Data Science & Engineering Analytics > Information Management and Systems (1.00)
Formulation of a Joint Test Protocol for the Corrosion Assessment of Magnesium Components on Military Assets
Mason, Robert B. (Concurrent Technologies Corp) | Gintert, Lawrence A. (Concurrent Technologies Corp.) | Nguyen, Judy (Concurrent Technologies Corp.) | Miller, R. Gerry (Concurrent Technologies Corp.) | Skelton, Donald R. (US Army IEC) | Adler, Ralph (Army Research Laboratory)
ABSTRACT A Joint Test Protocol (JTP) is a document that outlines screening and performance tests for new products to be considered for use on military materiel. The JTP enables program managers to compare a new product to not only the requirements of the JTP, but also to existing products that may have gone through the same testing protocol. Corrosion JTPs are designed to assess the performance of any potential corrosion-preventative candidate (e.g., a material, coating, repair process, or maintenance process), as well as an entirely new system. Implementation of these JTPs will help identify and validate candidates to improve corrosion control on DoD materiel, thereby reducing life-cycle operational costs and maximizing equipment sustainability for the war fighter. JTPs may be particularly effective for the assessment of new technologies on corrosion-prone components, such as those made from magnesium alloys. This paper discusses the effort conducted under the U.S. Army Corrosion Measurement and Control Program to formulate and implement a JTP for the corrosion assessment of magnesium components incorporating corrosion-preventative candidates. INTRODUCTION Magnesium has been a material of interest within the engineering design community for many years. Magnesium alloys impart good mechanical properties and specific fatigue strength, while providing low density and high strength-to-weight ratios at a relatively moderate cost. As a result, these alloys have been considered and utilized for many components in automotive, aircraft, and aerospace systems. Corrosion Characteristics of Magnesium - While the mechanical characteristics of magnesium are tantalizing to the design engineer, the relatively poor corrosion performance of magnesium alloys (compared with materials such as steel or aluminum) can be a deterrent to their consideration for many applications. This is due in large part to the fact that magnesium is the most electrochemically negative structural metal, occupying highly active positions in both the electromotive force series and the galvanic series for seawater. It is anodic to all other structural metals and will corrode preferentially when coupled with virtually any other metal in the presence of an electrolyte. A cursory review of the literature reveals that the corrosion characteristics of pure magnesium and many of its alloys are fairly well characterized1, 2, 3, 4. Untreated magnesium forms a protective oxide layer under atmospheric exposure, but this oxide is not stable in acidic or even neutral pH environments, as demonstrated in the Pourbaix diagram for unalloyed (pure) magnesium in water presented in Figure 1. Furthermore, contaminants from the manufacturing process (specifically iron, nickel, or copper) on the surface of magnesium alloys act as cathodic sites and further decrease the corrosion resistance1. As a result of these issues, it is generally recognized that magnesium alloys exhibit poor corrosion resistance in many environments, with corrosion rates of some commonly used alloys, such as ZE41A, reported to be greater than 400 mils per year5.
- Materials > Metals & Mining > Magnesium (1.00)
- Government > Regional Government > North America Government > United States Government (1.00)
- Government > Military (1.00)
- Energy > Oil & Gas > Upstream (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)
INTRODUCTION ABSTRACT A cost-benefit analysis or Life Cycle Costing (LCC) of flowline replacement was recently undertaken for a major oil producing company in the Middle East because of frequent corrosion failures in the pipeline network. The company has more than 2,000 production wells (consisting of oil wells, water wells, injectors and disposal wells) distributed throughout the country. Thousands of kilometers of 101.6 mm (4-inch) and 152.4 mm (6-inch) bare carbon steel (API 5L Grade B) flowlines are used to convey products to some 20 Gathering Centers (GCs). A number of different alternative replacement options and/or materials in lieu of bare carbon steel may be considered. However, as stipulated by the company, the cost-benefit analysis was limited to the following 4 items: (a) Carbon steel with corrosion inhibitor, (b) In-situ coatings, (c) In-situ HDPE linings, and (d) Corrosion resistant alloys (CRAs). Alternative materials such as GRP, GRP-lined steel, and composites were not considered. The cost-benefit analyses showed that when equal life expectancies of 25 years are considered for the various options, the in-situ coating option is the most economical based on present worth (PW). However, on an annualized basis, bare carbon steel is by far the most economical. Hence, in situations where the flowline is not exposed to very corrosive conditions (e.g. corrosion rates of <5 mpy), the use of bare carbon steel would be adequate and most cost-effective. In environments where carbon steel corrodes at about 10 mpy or greater, the use of an alternate option is advisable. According to the annualized costs, the use of HDPE linings when used alone appears to be the most economical followed by in-situ coatings when used alone. The LCC calculations further showed that the use of corrosion inhibitors or CRAs as replacement options for flowlines do not appear to be attractive from an economic standpoint. A major Middle East oil producer has more than 2,000 production wells (consisting of oil wells, water wells, injectors and disposal wells) distributed throughout the country. Thousands of kilometers of 101.6 mm (4- inch) and 152.4 mm (6-inch) diameter bare carbon steel (API 5L Grade B) flowlines are used to convey products from these wells to some 20 Gathering Centers (GCs). The vast majority of these flowlines are laid above ground but small sections are buried underground particularly in and around the GC?s. The crude oil obtained is accompanied by produced water, natural gas and acid gases (carbon dioxide and hydrogen sulfide). In the absence of water to create a water-wet surface, crude oil at a typical production temperature is not, by itself, corrosive. However, even a thin film of water on the metal surface is sufficient to create corrosion problems, in part because the acid gases dissolved into the water phase produce corrosive acids. .As oil and gases are removed from the well the pressure of reservoir slowly drops. To maintain the pressure, water is often injected into the reservoir either from the produced water or from seawater flooding. As the well ages, water is produced along with the oil, and the percentage of water in the oil product increases. As reservoirs age, more areas will produce significant water volumes. Corrosivity of the produced fluid from the wells is expected to increase due to the increase in water production up to a certain level. Internal corrosion can be expected occur anywhere water can condense, flow or collect in wells, flowlines, pipelines, vessels and other equipment. The exact corrosion status of the subject flowline network is currently unknown as there is very little corrosion monitoring instrumentation on the flowlines. However, base
- 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 (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Materials and corrosion (1.00)