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51395-95088-SG

Product Number: 51395-95088-SG

Author: A. Valdes, M.E. Afonso

Publication Date: 1995

$20.00

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75067 The Effect of Microstructure on Corrosion Resistance of Several Cast Alloys

Product Number: 75067-SG

Author: R.M. Forbes Jones, R.M. Kain

Publication Date: 1975

$20.00

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84169-Corrosion related failures in feedwater heaters

Product Number: 84169-SG

Publication Date: 1984

$20.00

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A Case Study On Microbiologically Influenced Corrosion In Oil Producing Well Flowlines

Product Number: 51322-17924-SG

Author: Amer Jarragh, Sandip Kuthe, Sharad Londhe, Akhil Jaithlya, Abeer Rashed, Nadine El-Kaouri

Publication Date: 2022

$20.00

Oil field operating company’s ⁽¹⁾ flowline network in North and West Kuwait (NWK) has over 3000 wells connected through 6” carbon steel pipelines flowing from wellhead to the nearest Gathering Center (GC). Untreated wet crude is transported through the flowlines to GC’s directly or passing through the Remote Headers and Manifold (RHM) to GCs. In RHM, mixing of the wet crude takes place before it is sent to GC’s via transfer lines for further separation. The flowlines are laid aboveground except at road crossings where they are buried.

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A Case Study on the Failure of Fiber Reinforced Epoxy (FRE) Lining on Condensate Storage Tank

Product Number: 51323-19193-SG

Author: Ahmad Raza Khan Rana, George Jarjoura, Syed Umair Niaz Bukhari

Publication Date: 2023

$20.00

A remarkable amount of financial loss is incurred every year because of premature failures of paints and coatings. The budget to repair such failures extremely outweighs the initial cost of coatings, since excessive engineering may be looked-for to access the deteriorating areas of a coating system. Additional accountability may also be anticipated if a facility stops operation for the essential repairs to be made.

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A Case Study: Piecewise vs. Holistic Pipeline AC Mitigation Design

Product Number: 51323-19307-SG

Author: Perry Ross

Publication Date: 2023

$20.00

AC interference analyses are an important part of designing an adequate cathodic protection system on a pipeline when collocations with high voltage powerline(s) occur. Modeling software has been developed to create accurate simulations of what is occurring in the real world to create the best mitigation designs for operators. Many of these studies are proposed due to pipeline replacements that update pipelines from coatings with coal tar to fusion bonded epoxy (FBE).

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A Case Study-Caustic Gouging Of Boiler Tubes

Product Number: 51322-17780-SG

Author: Suresh Divi, Sri Krishna Chimbli

Publication Date: 2022

$20.00

Caustic corrosion is sometimes referred to as “caustic attack or “caustic gouging.” Corrosion of this type may result from internally fouled heat transfer surfaces and the presence of sodium hydroxide in the boiler water; and concentrated solutions of alkali where the normal washing of the tube metal ID is restricted after Departure from Nucleate Boiling (DNB), i.e., when the steam bubble release exceeds the rinsing rate.

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A Comparative Assessment of Environmental Severity Monitoring Techniques

Product Number: 51323-18887-SG

Author: Steven Kopitzke, Christine E. Sanders, Alexander Lilly, Raymond J. Santucci

Publication Date: 2023

$20.00

Evaluating the location-based risk of corrosion is critical to a number of fields of industry. Within naval aviation, knowing the risk of corrosion from environmental factors can be used to ensure that maintenance intervals are properly planned. From a basic research aspect, understanding how different sites behave allows researchers to better correlate how performance at a standard test site can be extrapolated in future research efforts. However, a survey of literature and conversations with many corrosion experts has shown variability in how environmental factors are assessed.

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A Comparative Study between Corrosion in Sour Environments Generated by Na2S.9H2O Salt and H2S Gas

Product Number: 51324-20762-SG

Author: Hunter Thomson; Scott Fairley; Caroline Simpson; Dario M. Frigo; Gordon Graham

Publication Date: 2024

$40.00

Corrosion tests in laboratories to investigate the corrosion rate and to qualify production chemicals are only valid and applicable if the conditions and chemical environment (pressure, temperature, wall shear, pH, CO2 and H2S partial pressures, electrolyte composition) are representative of the field conditions. Representative sulfide concentrations are sometimes achieved by adding a sulfide salt (e.g., Na2S.9H2O) to minimize health and safety risks associated with the direct use of H2S gas. The current study compares the corrosion of carbon steel in nominally comparable sour conditions generated either using H2S gas or sodium sulfide salt. Tests were performed at 90 °C/101.3 kPa and at 120 °C/20 MPa using H2S partial pressures (pH2S) of 0.1 kPa (0.1 mol% H2S at 1.013 bar), 0.2 kPa (0.2 mol% at 1.013 bar) and 40 kPa (0.2 mol% at 200 bar). The corrosion rate was monitored by linear polarization resistance at ambient pressure and by weight loss measurement at higher pressure. Surface morphology of the coupons was assessed by optical microscopy, scanning electron microscopy (SEM) and energy dispersive X-ray spectroscopy (EDX). Ambient pressure linear polarization resistance (LPR) measurements with low H2S partial pressures showed comparable corrosion rates obtained using either H2S gas or sodium sulfide. In contrast, in the tests at higher pressure, significantly lower corrosion rates were measured when using H2S gas than with sodium sulfide. Moreover, microscopy showed pitting when sulfide was introduced as the salt, but pitting was absent when the sour environment was generated by H2S gas. Supportive work on other systems has shown that small changes in in situ conditions, particularly at elevated pressure (high H2S partial pressure), have a significant impact on the recorded corrosion rates, and therefore the ability to accurately match the environment within the test cell between generating the in situ sulfide via salt addition versus H2S gas is likely to be the root cause. In summary, therefore at high H2S partial pressure, particularly where the corrosion becomes dominated by sour corrosion, such issues related to the test methodology, and the ability to achieve representative in situ conditions, may lead to disqualification of corrosion inhibitor candidates that otherwise could have achieved the pass criteria were testing performed using H2S gas.

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A Comparative Study on Coating Performance of Inorganic Zinc Primer System and Inorganic Copolymer System by Long-Term Durability Test Including High Temperature Exposure at 540℃

Product Number: 51323-18820-SG

Author: Chuljung Kim

Publication Date: 2023

$20.00

Bulk items such as cast and forged valves are installed under various temperature conditions. It is exposed to a wide range of temperatures, therefore the coating product applied to bulk items should have appropriate heat resistance performance. However, it is very difficult to select a suitable coating system since the temperature condition is not determined in the valve manufacturing stage. For this reason, unsuitable coating systems are often applied, causing coating defects in the field operation. Therefore, it is necessary to apply a coating system that can cover a wide temperature range to prevent this problem.

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A comparison among different electrochemical hydrogen charging methods tested on low alloy steels

Product Number: 51323-18866-SG

Author: Luca Paterlini, Luca Casanova, Giorgio Re, Marco Ormellese, Fabio Bolzoni

Publication Date: 2023

$20.00

Atomic hydrogen can enter metallic microstructures from deposition processes like Cr plating or phosphatizing, chemical and electrochemical pickling treatments, during welding operations if the humidity of consumables is too high, by cathodic processes resulting from corrosion phenomena or contact with high pressure gaseous hydrogen. According to different chemical-physical mechanisms, atomic hydrogen can enter the metallic structure resulting in damages of various forms, such as HIC (hydrogen induced cracking), SOHIC (stress oriented HIC), delayed fracture and hydrogen embrittlement (HE).

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A Comparison of the Pitting and Crevice Corrosion of Directional Drilling Alloys With Oilfield Production Alloys

Product Number: 51320-14432-SG

Author: Manuel Marya

Publication Date: 2020

$20.00

The pitting corrosion and crevice corrosion of oilfield production alloys (e.g., 13Cr/UNS S41000, 17-4PH/UNS S17400, 25Cr/UNS S32750, A286/UNS S66286, 718/UNS N07718) and proprietary austenitic stainless steels for directional drilling (PREN between ~20 to ~45) has been investigated. Specifically, series of electrochemical tests have been conducted to rank the alloys, establish simple correlations between electrochemical parameters, PRENmod, and 3-to-60-day immersion tests in 3.5% NaCl at ambient temperature. For all but one alloy, pitting was absent in stark contrast to crevices. Upon tracking populations and dimensional characteristics of crevices over time, trendlines comparing the susceptibility of the alloys towards crevice corrosion were established. Practical conclusions were reached, including the following: (1) 13Cr consistently developed crevices within days, (2) 17-4PH as well as all traditional directional drilling stainless steels developed crevices within one to five weeks, and, (3) neither 718, 25Cr, nor newer directional drilling alloys with both high nickel and high PRENmod showed any sign of crevices upon being tested up to 60 days. Through a variety of comparisons, this investigation also reveals useful technical directions for the development of new, economical, and fit-for-service Oil & Gas alloys for both production and drilling.

Online Conference Paper

Association for Materials Protection and Performance