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Picture for Predicting Corrosion Severity of Pipeline Steels in Supercritical CO2 Environments Using Supervised Machine Learning
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Predicting Corrosion Severity of Pipeline Steels in Supercritical CO2 Environments Using Supervised Machine Learning

Product Number: 51324-20803-SG
Author: Emily Seto; Meifeng Li; Jing Liu
Publication Date: 2024
$40.00
The importance of effective corrosion management in carbon capture, utilization, and storage (CCUS) networks has significantly increased. Captured CO2 is often transported in the supercritical state (s-CO2) and can contain impurities like H2O, O2, SOx, or NOx. While repurposing existing oil and gas pipelines for s-CO2 transport has been suggested, further testing and risk assessment is required to validate this strategy and its associated risks. Given the substantial amount of corrosion data available from recent corrosion studies, machine learning (ML) has emerged as a promising tool for corrosion prediction and management. This study aims to utilize supervised ML techniques to predict the corrosion severity of pipeline steels operating in s-CO2 systems. The selected algorithms, random forest (RF), K-nearest neighbor (KNN), and support vector machine (SVM) were trained on a comprehensive data set of X-series pipeline steels which includes corrosion rates, impurity levels, temperatures, pressures, and exposure times. Additional testing data set and error and accuracy scores were used to determine the most accurate algorithm. An additional experimental testing was performed to verify the predictions of the model. It was found that the RF model had the best accuracy of 65.3% out of the three tested models and KNN had the worst accuracy of 59.2%. In multiple impurity environments the RF model was able to accurately predict corrosion severity but overestimated corrosion severity in environments with short exposure times.
Picture for Condition Assessment of 66 kV Underground Transmission Lines in Concrete Vaults
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Condition Assessment of 66 kV Underground Transmission Lines in Concrete Vaults

Product Number: 51324-20826-SG
Author: Anil Kumar Chikkam; Aaron Ulmer; Nathan Pace; Mehrooz Zamanzadeh
Publication Date: 2024
$40.00
This paper focuses on assessing the condition of steel pipe cable sections within concrete vaults, serving as protective covers for conductors transmitting up to 66,000 volts. To prevent internal corrosion and short circuits, these cables are filled with pressurized oil. However, water accumulation during storms frequently submerges the cables in water in the concrete vaults, presenting significant challenges for external corrosion protection. Through condition assessment, it was determined that the coating on the 6-5/8" (16.8 cm) diameter steel carrier pipe remained in satisfactory condition. However, the coating on the 14" (35.56 cm) diameter steel casing exhibited poor condition and no longer provided adequate corrosion protection. This paper investigates the underlying causes of premature coating failure and proposes a recommended coating system considering the elevated temperatures experienced by the pipe cables. The findings contribute to enhancing the durability and effectiveness of coatings for submerged steel pipe cables, addressing the challenges posed by water submersion and ensuring long-term corrosion protection. Also, we discuss the temperature and corrosion monitoring by wireless Sensor.
Picture for Effects of Corrosion and Wildfires on Galvanized Steel Towers: A Case Study with Wildfire and Corrosion Sensors
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Effects of Corrosion and Wildfires on Galvanized Steel Towers: A Case Study with Wildfire and Corrosion Sensors

Product Number: 51324-20844-SG
Author: Mehrooz Zamanzadeh; Anil Kumar Chikkam; George T. Bayer; Clinton Char; Carolyn Tome
Publication Date: 2024
$40.00
With the rising prevalence of climate change, utilities are facing increased risk and consequences from accelerated corrosion and wildfires, particularly in the state of California and British Columbia. These fires have the potential to compromise the integrity of galvanized steel lattice towers, widely used in high voltage transmission lines. Considering this, it is crucial for utilities to assess the potential risks and deploy corrosion control and postfire inspection strategies. This paper investigates the effects of corrosion and wildfires on these structures and presents a case study involving real-time monitoring sensors for early risk identification and evaluation. This paper aims to shed light on the challenges posed by wildfires and corrosion to utility structures and provides actionable insights for future preparedness. With escalating concerns about climate change, utilities must adapt their strategies for a more resilient future.
Picture for Evaluation of Susceptibility of 316L to Stress Corrosion Cracking in Aqueous Ammonium Chloride Environments with Low Dissolved Oxygen
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Evaluation of Susceptibility of 316L to Stress Corrosion Cracking in Aqueous Ammonium Chloride Environments with Low Dissolved Oxygen

Product Number: 51324-20875-SG
Author: Jonas Sa; Alexander Saul; Monir Aljaradli; Dana Abdeen; Nicholas Laycock
Publication Date: 2024
$40.00
Corrosion of stainless steel in applied industrial environments continues to be an area of concern for various refining operators. It is well accepted that a certain concentration of dissolved oxygen is required for chloride stress corrosion cracking (SCC). However, there are some environments where it is suspected that chloride SCC can occur even in the absence of dissolved oxygen. The susceptibility to SCC of 316L stainless steel has been studied in the pursuit of extending operating boundaries at higher temperatures under low dissolved oxygen concentrations. Slow strain rate tensile (SSRT) tests have been carried out for various temperatures and ammonium chloride concentrations under low dissolved oxygen conditions. The susceptibility to SCC was assessed in terms of the relative reduction in area (RRA). Detailed fractography and cross section inspections were used to identify the damage mechanisms. The implications of this behavior and its influence on improving material selection have been discussed.
Picture for On Defending against Calcium Carbonate and Asphaltene Deposits Using Dual-Action Diamond-Like Carbon and Polymer-Like Coatings
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On Defending against Calcium Carbonate and Asphaltene Deposits Using Dual-Action Diamond-Like Carbon and Polymer-Like Coatings

Product Number: 51324-20896-SG
Author: Alireza Zolfaghari; Manuel Marya; Virendra Singh
Publication Date: 2024
$40.00
In searching for dual-action coatings, capable of combatting the deposition of calcium carbonate scale as well as asphaltene, three diamond-like carbon (DLC) coatings, a polymer-like carbon (PLC) coating, and an engineering PPS-PTFE polymer coating were concurrently investigated for their resistance against these chemical deposits. Attempts were made to correlate surface properties, namely water contact angle and friction coefficient, with series of laboratory-made deposits generated over 72-hrs at 31 MPa and 75C by stirred and partially soluble liquids. Among all tested surfaces, deposits were successfully and repeatedly produced, and analyzed for their mass and their average adhesion (pull-off) strength. Several coatings, particularly the PLC coating, was identified for acting well against both calcium carbonate and asphaltene. A proprietary DLC coating also demonstrated beneficial effects against deposits; its high hardness and low friction coefficient also makes it particularly attractive for equipment with dynamic sealing surfaces. Finally, this short exploratory study did not establish a relationship between any type of deposition, contact angle, or friction coefficient, but proposes alternate explanations.
Picture for Application of the One Hundred Millivolt Cathodic Polarization Criterion by Means of Coupons: A New Point of View
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Application of the One Hundred Millivolt Cathodic Polarization Criterion by Means of Coupons: A New Point of View

Product Number: 51324-20929-SG
Author: Ivano Magnifico; Lorenzo Spisni
Publication Date: 2024
$40.00
This paper presents a comprehensive investigation into the practical application of the One Hundred Millivolt (100 mV) Cathodic Polarization Criterion to assess Cathodic Protection effectiveness by means of coupon on underground pipelines in a Gas Distribution Network. The One Hundred Millivolt Cathodic Polarization Criterion is a widely recognized criterion for assessing the effectiveness of CP systems particularly in those areas where the -850 mV Potential criterion is difficult to respect due to the higher soil resistivity or the network configuration. When using the criterion by evaluating the 100 mV shift by measuring the depolarization after disconnecting the CP current, the instant-off potential to consider as the reference value is often measured too late, thus loosing completely the overvoltage generated by activation polarization that generally disappears in the order of few milliseconds. In this study, a deep investigation on applying the criterion by measuring depolarization on coupons is given, evaluating on real field measurements the effect of the waiting time on taking the reference value from coupon disconnection, as well as the effect of changing in soil resistivity considering different periods of the year.
Picture for Inhibiting Nucleation Corrosion in Liquid Hydrocarbons
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Inhibiting Nucleation Corrosion in Liquid Hydrocarbons

Product Number: 51324-21232-SG
Author: Moshood Adewale; Hitesh Bagaria; Nimeshkumar Patel; Tatiana Barbosa; Osvaldo Antonio Heredia Cancino
Publication Date: 2024
$40.00
Dewpoint corrosion is a well-known phenomenon in flue gas stacks and refinery overheads, where fine water droplets condense from the vapor upon cooling, and the acid gases in the vapors diffuse into water droplets to form a highly corrosive low pH liquid. We have identified a similar mechanism in hydrocarbon liquids, which we call as “nucleation corrosion” (C2023-19463). Liquid hydrocarbons often have dissolved water (DW), which does not promote corrosion even in the presence of corrosive species (e.g., organic acids, H2S). Upon cooling, the DW nucleates as nanometer-sized water droplets and acids present in the liquid partition into the water droplets decreasing pH to cause aggressive nucleation corrosion. In this study the methods to mitigate nucleation corrosion are investigated with an emphasis on studying the impact of different types of chemical inhibitors on this newly discovered mechanism. An interesting example of the impact of the test method on inhibitor selection is shown. Finally, a case study highlighting nucleation corrosion in a refinery distillation overhead reflux line is presented.
Picture for Corrosion Challenges in Processing Crude Oils: Influence of Active Sulfur Species and Corrosion Rates of Various Alloys
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Corrosion Challenges in Processing Crude Oils: Influence of Active Sulfur Species and Corrosion Rates of Various Alloys

Product Number: 51324-21207-SG
Author: Yuhchae Yoon; Hui Li; Russell D. Kane
Publication Date: 2024
$40.00
The depletion of conventional sweet oil resources has led to increased attention towards sour and acidic oil sources, which typically consist of lower-quality, corrosive crude oils with elevated concentrations of naphthenic acids and sulfur compounds. They are often referred to as “opportunity crudes” since they come at a lower price to refiners, but if successfully processed, they can result in a higher margin to the refinery. This paper focuses on an investigation of the impact of active sulfur species present in crude oils during processing. Corrosion rates of several common alloys were evaluated under stirred/pipe flow conditions in autoclaves. The experimental conditions closely simulated relevant refinery environments, encompassing temperatures ranging from 200°C to 370°C. The study assessed the influence of temperature, wall shear stress (WSS), and active sulfur content on corrosion rates. The results were derived from a comprehensive Joint Industry Program (JIP) conducted to quantify the influence of crude oil chemistry on naphthenic acid corrosion, understand the contributions of active sulfur chemistry to protection and FeS scale formation. The program also assessed the ability to resist naphthenic acid corrosion by utilizing beneficial sulfur speciation in the context of operational factors such as temperature and wall shear stress to build a prediction model to characterize the active sulfur level as a function of sulfur compound concentration and temperature, which is further utilized to predict corrosion rates of multiple alloys.
Picture for Preliminary Study to Characterize Concrete Durability by Water Permeation and Electrochemical Impedance Spectroscopy
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Preliminary Study to Characterize Concrete Durability by Water Permeation and Electrochemical Impedance Spectroscopy

Product Number: 51324-21167-SG
Author: Kingsley Lau; Amer Awwad; Samanbar Permeh; Atorod Azizinamini
Publication Date: 2024
$40.00
Sustainability of civil infrastructure construction can in part be attained by better testing to identify important material characteristics that affect durability. The quality of the concrete in reinforced concrete structures is a primary factor that enhances corrosion durability of reinforced concrete structures. The concrete may be assessed for quality control using methods such as bulk ion diffusivity tests, accelerated electrical migration tests, and electrical resistivity. There is interest in non-destructive in-situ testing for assessment of structures in service. In this study, preliminary tests were conducted to characterize the durability of concrete using a water permeation test, acoustic testing, as well as electrochemical impedance spectroscopy. Test results showed that the electrical properties of the hardened concrete can be assessed by electrochemical impedance spectroscopy where a high frequency impedance loop (relating to the bulk material and internal moisture content) can be discerned. The concretes with lower water-to-cement ratio and larger coarse aggregates showed larger resonant frequency values that can be attributed to greater developed stiffness. A water permeation test was also demonstrated to differentiate internal moisture conditions, and its results (described by a decay factor derived from mass and energy balance) was well correlated to its concrete electrical parameters.
Picture for Vintage Pipeline Enhanced Corrosion Management Analysis
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Vintage Pipeline Enhanced Corrosion Management Analysis

Product Number: 51324-21127-SG
Author: Kenton Lawson; Jason Charles Land; Angel R. Kowalski
Publication Date: 2024
$40.00
Vintage pipeline operators face increased regulatory challenges. These aging pipeline systems may have decades of metal loss and coating damage from soil interaction, pressure cycling, thermal stresses, and other physical phenomena that affects the pipeline’s mechanical integrity to make it more susceptible to leaks or ruptures. Aging pipeline systems are candidates for Enhanced Corrosion Management Analysis (ECMA) to effectively mitigate corrosion risks. The ECMA methodology begins with the integration and analysis of available corrosion control monitoring, maintenance, inspection, and assessment data, to identify the need to collect additional data. When all data deemed necessary to conduct ECMA is available, an analysis is conducted to identify the possible causes of corrosion metal loss in the pipeline system, e.g., inadequate cathodic polarization, poor or disbonded coating conditions, electrical shielding, stray current interference, or microbiologically influenced corrosion (MIC). Effective mitigation plans are then developed to address most probable causes of corrosion metal loss and integrated into the corrosion management program. A case study is presented to demonstrate the implementation of ECMA on a vintage pipeline system and the development of a 20-year corrosion mitigation plan to effectively minimize the corrosion risk on the pipeline. The case study also illustrates how engineering economic analysis can be used to guide decision making regarding operational life extension of the asset and how a well-planned corrosion management program can provide cost-effective, safe operation over the lifecycle of the pipeline.
Picture for Casing Corrosion in Geothermal Environments Containing Sulfuric Acid
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Casing Corrosion in Geothermal Environments Containing Sulfuric Acid

Product Number: 51324-20932-SG
Author: Joseph Thevakumar; Joshua Owen; Richard Barker; Evgeny Barmatov
Publication Date: 2024
$40.00
This work focusses on understanding corrosion severity and material performance within model geothermal sulfuric acid (H2SO4)-containing environments. With the use of a tantalum-lined high pressure/high temperature autoclave, the corrosion behavior of N80 carbon steel was compared against duplex stainless steel when exposed to H2SO4 solutions (pH 2-4) at temperatures up to 150°C. Electrochemical linear polarization resistance measurements were implemented to gather real time corrosion kinetic data. Complimentary ex-situ analyses (scanning electron microscopy and white light interferometry) were conducted to understand the corrosion mechanism and quantify localized corrosion rates. A quantitative relationship was identified in terms of pH, temperature and metal corrosion for the selected materials to highlight material capability within such low pH geothermal environments.
Picture for Effect of Elevated Temperatures (30-80°C) on CO2 Corrosion after Intermittent Oil/Water Wetting
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Effect of Elevated Temperatures (30-80°C) on CO2 Corrosion after Intermittent Oil/Water Wetting

Product Number: 51324-20967-SG
Author: Neda Norooziasl; David Young; Bruce Brown; Marc Singer
Publication Date: 2024
$40.00
The main goal of this research is to electrochemically determine the influence of temperature elevation (30 °C - 80 °C) on the wetting state and corrosion behavior of mild steel during intermittent oil/water wetting. The results obtained in separate experiments demonstrated that the corrosion mitigation effect of an oil phase (LVT-200 model oil) containing myristic acid (surface-active compound representing naturally occurring oxygen-containing compounds in crude oils) on CO2 corrosion decreased with temperature after intermittent wetting. The influence of the same temperature range on interfacial properties during intermittent oil/water wetting such as oil/water interfacial tension (IFT) and oil-in-water contact angle were also investigated. For model oil containing myristic acid, the IFT value was unchanged with temperature and could not be correlated to the corrosion rate. In the presence of the oil phase, the surface became more hydrophilic at 55 °C, which diminished the adsorption and persistency of the oil layer and decreased the corrosion mitigation effect. The effect of temperature on IFT and contact angle can depend on the nature of oil and surface-active compound.

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