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Picture for Influence Of Organic Acids Released During Hydrothermal Liquefaction Of Biomass On Corrosion Of Candidate Reactor Alloys
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Influence Of Organic Acids Released During Hydrothermal Liquefaction Of Biomass On Corrosion Of Candidate Reactor Alloys

Product Number: 51321-16612-SG
Author: Minkang Liu/ Yimin Zeng/ Xue Han/ Jing-Li Luo
Publication Date: 2021
$20.00
	Picture for Influence of Pb and Cl in Waste Wood Fuel on Furnace Wall Corrosion of Low Alloyed Steel and Alloy 625
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Influence of Pb and Cl in Waste Wood Fuel on Furnace Wall Corrosion of Low Alloyed Steel and Alloy 625

Product Number: 51324-21033-SG
Author: Annika Talus; Rikard Norling; Alice Moya Núñez
Publication Date: 2024
$40.00
Picture for Influence of Shear Stress on the Pitting Corrosion Susceptibility of Austenitic Stainless Steel in Brine Evaluated in the Rotating Cylinder Electrode
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Influence of Shear Stress on the Pitting Corrosion Susceptibility of Austenitic Stainless Steel in Brine Evaluated in the Rotating Cylinder Electrode

Product Number: 51319-13362-SG
Author: Helmuth Sarmiento Klapper
Publication Date: 2019
$20.00

During drilling operations the drillstring might be subjected to downhole conditions leading to pitting corrosion. State-of-the-art directional drilling technologies are very demanding in terms of material requirements including corrosion resistance. Manganese-stabilized fully austenitic stainless steels in strain-hardened condition own a beneficial combination of high strength high ductility and high toughness by keeping their own non-magnetic character. Therefore CrMn-stainless steels have been extensively used in drilling equipment. Once in contact with high chloride bearing drilling fluids at elevated temperatures however their passivity is compromised leading to pit nucleation and propagation. In consequence the pitting corrosion resistance of these materials becomes a significant limiting factor for their selection as well as for assessing the service life of drillstring components. To date extensive research work has been conducted to characterize the pitting susceptibility of CrMn-stainless steels under static conditions. Little attention however has been paid to the effect of shear stresses introduced by the flow of the drilling fluid on the pitting resistance and damage morphology produced on these materials when exposed to brines at elevated temperatures. To address this electrochemical examinations were conducted using the rotating cylinder electrode (RCE). The present paper discusses the results from potentiodynamic polarization tests and their relation to the hydrodynamic conditions produced in the RCE at different temperatures.

Picture for Influence of Stress and Temperature on Stress Corrosion Cracking of Welded Duplex Stainless Steel Joints under Drop Evaporation Test
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Influence of Stress and Temperature on Stress Corrosion Cracking of Welded Duplex Stainless Steel Joints under Drop Evaporation Test

Product Number: 51319-13420-SG
Author: Neusvaldo de Almeida
Publication Date: 2019
$20.00

Drop evaporation test at three different temperatures were conducted with duplex stainless steel for the study of the influence of temperature strain and welding energy on its stress corrosion cracking (SCC) suitability. Three welding conditions were performed: regular condition according to N133 standard other with low welding energy with the objective of causing high ferrite content in the fusion zone and other with high welding energy in order to induce the precipitation of deleterious phases in the heat affected zone. The specimens were assayed with three different tensile stresses with a bending device and assayed for 500 hours and dripped with synthetic sea water solution with a flow rate of 10 ± 1 drops per minute. All specimens tested with a temperature of 110ºC showed a fracture in the region adjacent to the drip below the salt deposit and away from the weld with the presence of multiple nucleation and branched crack propagation. The fracture surface showed topography similar to cleavage with small regions of decohesion. The test specimens tested at 90ºC only showed localized corrosion preferential of the ferrite it occurred also in the region adjacent to the drip. The results showed that the crevice condition introduced by the salt layer offered more severe conditions than the welding conditions. The same tests were made with the dropping aiming adjacent region at temperatures of 70ºC and 90ºC to induce the crack in critical regions like fusion zone or heat affected zone but there was no evidence of SCC indicating that the critical temperature is higher than 90ºC even with non-standard welding conditions.

Picture for Influence of Structural Features of Scale Inhibitors on the Control of Silica Scaling
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Influence of Structural Features of Scale Inhibitors on the Control of Silica Scaling

Product Number: 51319-12861-SG
Author: Kostas Demadis
Publication Date: 2019
$20.00

Feedwaters for industrial cooling water systems contain a variety of metal cations (such as calcium magnesium barium etc.) and anions (such as carbonate sulfate phosphate etc.) which overall constitute scaling ions. Their combination (depending on the particular water chemistry and solubility products) creates precipitates and deposits. These mineral salts cause enormous operational problems upon their deposition onto critical equipment surfaces (eg. membranes heat exchanger tubing tower fill etc.). Calcium carbonate and calcium phosphates are the most frequently encountered deposits. Other deposits although less common are equally troublesome. These include amorphous (colloidal) silica. Prevention of scale formation is greatly preferred by industrial water users to the more costly laborious (and potentially hazardous) chemical and mechanical cleaning (for example HF is required for the dissolution of silica deposits) of the adhered scale after a scaling event.This paper focuses on amorphous/colloidal silica fouling and its control by additive-driven inhibition. The use of several designed treatment additives will be described with emphasis on the structural elements of inhibitors used. These efforts address the question “what are the chemical moieties that contribute to silica inhibition and why”? Almost all silica inhibitors are polymers (either charged or uncharged). Certain silica scale inhibitors described can maintain up to ~ 400 ppm soluble silica in solution. Attention will also be paid to the designed chemical approaches that should be used to combat silica scale for example the use of inhibitor blends in search for potential synergistic effects. A detailed analysis will be given on the entire chemical treatment process starting from proper selection of the treatment program to proper application to effective monitoring and maintenance of system performance. Finally the general scope of silica chemistry fundamentals will be presented.

	Picture for Influence of the H2 Impurity on the Fatigue Crack Growth and Fracture in a Dense Phase CO2 Pipeline
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Influence of the H2 Impurity on the Fatigue Crack Growth and Fracture in a Dense Phase CO2 Pipeline

Product Number: 51324-20721-SG
Author: B Bezensek; S Hopkin; J Sonke; F Gui; C Taylor
Publication Date: 2024
$40.00
Transport of dense phase CO2 by pipelines needs to account for possible degradation mechanisms arising due to H2 impurity which can be present in (typically) the 0.75 ~ 1 mol% range depending on the specification used. H2 gas can affect fatigue and fracture properties even at low partial pressures and hence the integrity. In this study a complementary experimental and computational modeling program was undertaken. API 5L X65 grade material samples were used for comparable testing in pure H2 gas at low partial pressure H2 and in dense phase CO2 at 100 barg with H2 impurity added in a 2 mol% and 4 mol% increments (i.e. partial pressures of 2 barg and 4 barg). The test results show effect of the H2 impurity in the dense phase CO2 accelerated fatigue crack growth and reduced fracture toughness. These findings are supported by computational simulation using density functional theory and molecular dynamics. A scoping integrity assessment for a dense phase CO2 pipeline with H2 impurity at 2 mol% shows the measured accelerated fatigue crack growth only affects large pressure cycles (pressure range in excess of 70 bar for OD/WT pipelines of ~30). The fatigue life is significantly shortened compared to the pure CO2 pipeline and this is mainly driven by the reduced fracture toughness at low partial pressure H2. The fatigue damage is proportional to the maximum operating pressure (as it increases the pressure range). For a postulated 50-year design life a safe pipeline design window considering a range of conservative inputs (material properties, integrity operating window, geometry, postulated defect size etc.) a safe operating pressure of 2900 psig (200barg) was found for a new build pipeline using modern materials. For a repurposed vintage material pipeline the safe operating pressure was set at 2200 psig (150 barg). An ECA incorporating the deleterious effect of H2 should be conducted to confirm the above postulate unless the project falls within the limits of the conservative inputs (material properties, integrity operating window, geometry, postulated defect size etc.), from a fracture mechanics perspective, of the four case studies that form the basis of this overall study. Other impurities if exceeded their safe threshold may create water drop out and acid formation. It is imperative that the project specifications err on the side of caution and restrict the impurities to safe limits until further understanding of the complex interaction mechanisms is developed.