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Picture for Intergranular Oxidation Of Unstressed Alloy 600 SA And Alloy 600TT In PWR Primary Water
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Intergranular Oxidation Of Unstressed Alloy 600 SA And Alloy 600TT In PWR Primary Water

Product Number: ED22-17279-SG
Author: Daniel K. Schreiber, Karen Kruska, Matthew J. Olszta, Peter H. Chou
Publication Date: 2022
$20.00

Alloy 600 (Ni-16Cr-9Fe) is well known to exhibit intergranular corrosion and intergranular stress corrosion cracking (IGSCC) upon exposure to high temperature water environments, including those found in service environments of pressurized water reactors (PWR). While the higher Cr content alloy 690 exhibits superior IGSCC resistance in these environments, alloy 600 is still in use at many light water reactor plants. Part of the difficulty in assessing alloy 600 performance is the significant variability in behavior from heat to heat, both from the standpoint of initial alloy chemistry and the subsequent thermomechanical treatment of the material.
Picture for Intergranular Stress Corrosion Cracking (IGSCC) of Carbon Steel Equipment
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Intergranular Stress Corrosion Cracking (IGSCC) of Carbon Steel Equipment

Product Number: 51323-19173-SG
Author: Duane Serate, Simon Yuen, Yashar Behnamian, Jeffrey Venezuela
Publication Date: 2023
$20.00

At the time of a recent maintenance shutdown, cracking was discovered in the repads and parent material in the vicinity of several nozzles along the bottom of two in-situ production treater vessels. Some of the cracks were reported to be through-wall. The vessels were commissioned in 2009 and had been in service for about 13 years before the cracks manifested as through-wall.
Picture for Internal Corrosion in Natural Gas Pipelines
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Internal Corrosion in Natural Gas Pipelines

Product Number: 51323-19507-SG
Author: Christopher A. Walker
Publication Date: 2023
$20.00

Corrosion is defined as the degradation of a material or its properties due to a reaction with the environment and is one of the most common pipeline integrity threats for operators. External corrosion may be visually inspected during excavation; however, due to accessibility, additional non-destructive examination (NDE) methods must be utilized to identify the presence and severity of internal corrosion.


Understanding the chemistry and electrical properties of how corrosion occurs aids in mitigating the presence of corrosion, specifically internal corrosion.
Picture for Internal Corrosion of Copper-Nickel Alloys Tubes 90/10 and 70/30 in Chlorinated Seawater for Heat Exchangers
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Internal Corrosion of Copper-Nickel Alloys Tubes 90/10 and 70/30 in Chlorinated Seawater for Heat Exchangers

Product Number: 51319-13338-SG
Author: Dominique Thierry
Publication Date: 2019
$20.00
The corrosion resistance of copper-nickel 90/70 and 70/30 tubes for heat exchangers was evaluated in 0.5 ppm-chlorinated seawater under controlled service conditions in bespoke test loop. Copper-Nickel 90/10 tubes were tested with two different geometries: internal smooth surface and internal finned surface (helix geometry). Internal pitting corrosion resistance was evaluated under two controlled heat fluxes from the internal and the external parts of the tubes for 6 months at 65°C(Tskin-out)/50°C(Tskinin)/35°C(Tseawater) and 105°C(Tskin-out)/70°C(Tskin-in)/35°C(Tseawater). For all the tested copper alloys the uniform corrosion was extremely low and negligible. For both heat fluxes CuNi 90/10 was globally more resistant to localized corrosion than CuNi70/30. The most corrosion resistant configuration was the CuNi 90/10 with the finned internal geometry. The best corrosion resistance compared to the smooth geometry might be attributed to different hydrodynamic conditions at the seawater/metal interface.
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Internal Corrosion of Flare Header - A Case Study

Product Number: 51324-21201-SG
Author: Ayman A. Alabdullatif; Lay Seong Teh; Hatam Mehraz; Anaam H. Shaikh Ali
Publication Date: 2024
$40.00
In a major gas-oil separation plant (GOSP) in Saudi Arabia, a major flare header suffered from severe internal corrosion. Upon analyzing the scale and sludge that was found accumulated in the line, a significant proportion of elemental sulfur was identified. This indicated that in addition to hydrogen sulfide and water (which were expected to be present in the line), significant amount of oxygen was also present. An investigation was conducted to identify the source of this oxygen and to eliminate it. Other critical factors that impacted the internal corrosion were also identified. The line was not properly sloped to drain accumulated moisture. Knock-out boot levels were often high and not regularly drained. In addition, purge gas was not operated at rates adequate to sweep any accumulated liquids. All of these factors combined led to an accelerated deterioration of the header.
Picture for Internal Corrosion of L80 Tubing in Permian Basin Oil and Gas Wells-Case Studies (Lab Study)
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Internal Corrosion of L80 Tubing in Permian Basin Oil and Gas Wells-Case Studies (Lab Study)

Product Number: 51323-18892-SG
Author: Suresh Divi, Michael Newman
Publication Date: 2023
$20.00

The Permian Basin is an oil-and-gas-producing area located in West Texas and the adjoining area of southeastern New Mexico. The Permian Basin covers an area approximately 250 miles wide and 300 miles long and is composed of more than 7,000 fields (best represented in Railroad Commission of Texas production figures as districts 7C, 08, and 8A) in West Texas.1 The greater Permian Basin accounts for nearly 40 percent of all oil production in the United States and nearly 15 percent of its natural gas production.
Picture for Internal Corrosion Prevention During Hydrostatic Testing and Wet Layup of Pipelines: Approach and Case Study
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Internal Corrosion Prevention During Hydrostatic Testing and Wet Layup of Pipelines: Approach and Case Study

Product Number: 51324-20594-SG
Author: Susmitha Purnima Kotu; Christopher Kagarise; Richard Bruce Eckert
Publication Date: 2024
$40.00
The introduction of water and the absence of flow during hydrostatic testing or layup of pipelines can lead to internal corrosion, making corrosion control a critical concern. Various corrosion mechanisms may be active, including microbiologically influenced corrosion (MIC), under deposit corrosion (UDC), and oxygen corrosion, depending on the service and operating conditions of the pipeline. Chemical treatment is typically used to control corrosion during hydrotesting or layup, but it must be targeted at the applicable corrosion mechanisms and remain effective over the duration of hydrostatic test or layup period. Additionally, the applied chemical treatment must reach metal surfaces susceptible to corrosion. This paper highlights the approach for selection of appropriate mitigation strategy for internal corrosion prevention as part of hydrostatic testing and wet layup. This paper also presents two case studies that illustrate the processes used to identify likely corrosion mechanisms and perform laboratory studies to examine the effects of various chemical mitigation solutions for hydrostatic testing and wet layup.
Picture of Internal Corrosion Risk Assessment for Crude Pipeline-D - A Case Study
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Internal Corrosion Risk Assessment for Crude Pipeline-D - A Case Study

Product Number: MECC23-19965-SG
Author: Ayman A. Alabdullatif; Rakan A. Al-Shebil; Ahmad S. Al-Otaibi; Faisal M. Al-Abbas; Omar A. Al-Saif
Publication Date: 2023
$20.00

Pipeline-D was built in 1997 and was used to transport crude to Gas-Oil Separation Plant-1 (GOSP-1). The pipeline continued operating until it was subjected to intermittent shutdown in 2009 when GOSP-2 was built. As part of the project, 900 meters were added to connect Pipeline-D to GOSP-2.
Picture for Internal Corrosion Threat Assessment Using Operational Data and Comparison with ILI Results
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Internal Corrosion Threat Assessment Using Operational Data and Comparison with ILI Results

Product Number: 51315-6001-SG
ISBN: 6001 2015 CP
Author: Dharma Abayarathna
Publication Date: 2015
$20.00
Picture for Internal Corrosivity Assessment and Ranking of Crude Pipeline
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Internal Corrosivity Assessment and Ranking of Crude Pipeline

Product Number: 51317--9225-SG
ISBN: 9225 2017 CP
Author: Abdul Razzaq Al-Shamari
Publication Date: 2017
$20.00

This paper will discuss the effectivity of ranking the crude pipelines due to their product corrosivity based on certain parameters such as corrosion coupons, cleaning pig deposit sampling analyses, microbial activity and previous ILI records.
Picture for Internal Deposits: A Potential Threat to Pipeline Integrity
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Internal Deposits: A Potential Threat to Pipeline Integrity

Product Number: 51324-21014-SG
Author: Sri Krishna Chimbli
Publication Date: 2024
$40.00
Recent failure analyses of several modern pipelines in oil service have exhibited pin-hole leaks at the 6 o’clock position. The pits formed on the inside surface from a combination of pitting corrosion and under deposit corrosion. Two case studies involving an 8-inch and a 12-inch OD API 5L Grade X52M pipeline are discussed. The work scope for the pipeline failure analyses included visual examination, metallography, energy dispersive X-Ray spectroscopy (EDS) of corrosion products, X-Ray diffraction (XRD) analysis, Vickers hardness and tensile tests to determine the mechanism that led to the perforation(s). The failure analyses results indicated that the pitting corrosion likely occurred from the presence of free water and salts, while under deposit corrosion occurred from a layer of deposits containing paraffin, sand, salts and iron oxides. Pipelines anticipated to have significant accumulation of internal deposits require frequent internal cleaning via pigging and the subsequent use of corrosion inhibitors to improve pipeline integrity.
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Internal ICCP of Offshore Wind Monopile Foundations

Product Number: 51323-19376-SG
Author: Christophe Baete, Aldrich Tyto
Publication Date: 2023
$20.00

Despite rapid development of electricity generation from wind compared to other renewable power sources in recent years, much greater efforts are still required to achieve the current level of sustained capacity growth to get on track with the Net Zero Emissions (NZE) by 2050 Scenario. One of the main challenges remains around the sustainability and cost reduction efforts for the offshore wind sector, especially related to operation and maintenance (O&M) costs. Monopiles, the most common foundation type in offshore wind farms, just like any other submerged metal structures are susceptible to corrosion, the maintenance of which could be very costly.


Corrosion prevention of the inside of a monopile structure has been challenging until today.
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