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Picture for Carbonation-Induced Corrosion Assessment for Reinforced Concrete Structures
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Carbonation-Induced Corrosion Assessment for Reinforced Concrete Structures

Product Number: 51324-21169-SG
Author: Kingsley Lau; Samanbar Permeh; Sepehr Faridmarandi; Mansoureh Ghahfarokhi; Atorod Azizinamini
Publication Date: 2024
$40.00
Rebar corrosion induced by carbonation of concrete can occur in structures in both wet and dry exposures. This corrosion can become increasingly relevant in buildings as housing structures age and concrete carbonation occurs. The corrosion risk can vary depending on inter-related factors that include design, materials, and environmental exposure. The risk of corrosion furthermore can be assessed by the corrosion initiation and propagation phases. In this work two sets of testing were performed, including large scale concrete column testing to assess the corrosion behavior of steel subjected to loading and small-scale concrete testing to identify the effect of material and moisture condition environments on carbonation penetration. Concrete was cast with different water-to-cement ratio, limestone aggregate size, and conditioned in various moisture environments. The concrete specimens conditioned in wet conditions maintained in extended accelerated carbonation conditioning for up to 1 month of continuous carbonation of near 100% CO2 at 20 psi did not yield any significant carbonation penetration due to the slow rate of CO2 penetration. Concrete carbonation for the concrete specimens maintained in the dry condition fully carbonated within 67 hours and significant carbonation occurred for the concrete specimens maintained at 75%RH. In the carbonated concrete, the corrosion rate ranged from 0.2-0.8 µA/cm2. In presence of an external compressive force, the corrosion rates were similar; however, the time to corrosion initiation was delayed in time by a factor of 1.6-2. It is evident that both corrosion initiation and propagation should be considered when establishing recommendations for structural health monitoring and inspection.
Picture for Hydrogen Stress Cracking Resistance of Precipitation Hardenable Nickel Alloys and Optimization
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Hydrogen Stress Cracking Resistance of Precipitation Hardenable Nickel Alloys and Optimization

Product Number: 51324-20719-SG
Author: Stephen McCoy; Brian A. Baker; William MacDonald
Publication Date: 2024
$40.00
The material trend in the Oil & Gas sector is for high strength materials with high levels of corrosion resistance to resist increasingly harsh sour downhole environments. Compared to sweet wells the presence of hydrogen sulphide, elemental sulphur and hydrogen generally requires material selection of tubular and bar products in high performance stainless steels and nickel base alloys to withstand the pressures and temperatures. The materials of choice must be corrosion resistant, cost effective, reliable and have the strength required for the well design conditions. The material selection for downhole and well head equipment such as hangers, sub-surface safety valves, pumps and packers require age-hardenable materials to obtain the strength in heavier cross sections which cannot be strengthened by cold work. The commonly used nickel alloys for the sour service applications are alloy UNS N09925 (925), alloy UNS N07718 (718) and alloy UNS N07725 (725) with the more recently developed alloy UNS N09945 (945) and alloy UNS N09946 (945X) designed for HP/HT and sour wells. The metallurgical stability and freedom from detrimental phases of these materials being increasingly important to optimise the mechanical and corrosion resistant properties, particularly as larger section thicknesses of higher strength materials. The effect of the microstructure of these materials is shown to have a significant effect on the resistance to hydrogen attack and corrosion in sour environments. Optimising the compositional control, thermomechanical processing and microstructure is shown to give significant improvements in resistance to sour corrosion and hydrogen stress cracking resistance of materials used for critical downhole components. Over recent years there has been increasing industry demand to improve quality control and categorise the various PH Nickel alloy grades resistance to Hydrogen Stress Cracking (HSC) for critical High Pressure-High Temperature environments. HSC is a complex corrosion mechanism with many factors including composition, strength, microstructure, and grain boundary cleanliness influencing susceptibility. Evaluation efforts have used multiple techniques to measure the effects of HSC resistance, with this paper focusing on the Slow Strain Rate Test (SSRT) method according to TM0198 Method C(1) and using the quality control standard API*6ACRA(2). The purpose of the paper is to present results using the TM0198:C slow strain rate test method in a hydrogen charging environment and show the HSC resistance of the grades 925, 718, 945, 945X, and 725. This paper shows how the composition can be controlled within the defined limits of the alloy grade to optimise the HSC resistance by reducing precipitation of deleterious phases and reduce mill heat batch variation. The SSRT results are compared with mechanical properties determined according to API6ACRA(2) and detailed microstructural analysis.
Picture for Compatibility Study of HDPE Internal Lining in Carbon Steels for Polymer Injection and Mixing Applications
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Compatibility Study of HDPE Internal Lining in Carbon Steels for Polymer Injection and Mixing Applications

Product Number: 51324-20607-SG
Author: Ahmed Al Yahyaai; Amjad Al Kharusi; Bushra Al Hudar; Hilal Al Shuhumi; Mohammed Al Maqbali
Publication Date: 2024
$40.00
Oil and gas production consider the nature of the reservoir and the complexity of the forming layers as a governing factor. One of the major challenges that are faced in the oil and gas upstream industry is the complexity of the reservoir in which the production requires enhanced recovery process. Polymer injection is one of the methods that is used widely to enhance the production and increase it accordingly. However, after the polymer preparation and mixing process, a system of flowlines and pipelines is utilized to carry over the final polymer product to the injection wells. This requires a comprehensive study of the material selection options for the pipelines and flowlines that are considered based on their performance, low maintenance requirement, and cost effectiveness. This paper focuses on the testing and qualification of high-density polyethylene (HDPE) internal lined carbon steel that is considered as one of the material selection options for polymer transfer. Further, material selection options are discussed along with the testing and qualification requirements. Compatibility of the high concentrated polymer liquid with HDPE material was tested to design HDPE liner inside CS pipes to transport and inject the polymer into the wells.
Picture for Synthesis of Aminopropyl-modified Silica with Hydrophilic Branches Inhibitor for Corrosion Inhibition
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Synthesis of Aminopropyl-modified Silica with Hydrophilic Branches Inhibitor for Corrosion Inhibition

Product Number: 51324-20630-SG
Author: Norah Aljeaban; Ahmed Busaleh; Bader Alharbi; Tawfik A. Saleh
Publication Date: 2024
$40.00
In some oil and gas production processes, steel with carbon steel is the most often used type in construction of some lines due to its durability, reasonable cost, and readily available. However, carbon steel is prone to corrosion. Corrosion cannot be completely stopped since it tends to turn metal into minerals or oxides, returning it to its original mixed state. Silica-based nanoparticles are commonly used and easily created with good physical-chemical characteristics. They can be altered to have a range of characteristics, including hydrophilicity and hydrophobicity. Nanosilica-based materials are promising as inhibitors because they have improved qualities to meet the demand for efficient materials. Their surface area can also be easily altered with various functionalities, creating a strong affinity for the metal surface. As an illustration, silanization, which creates the (Si-O-Si) connection, results in a material with strong thermal stability that is an appropriate option for inhibitors. In this work, we synthesized a modified silica-based inhibitor using a thermal treatment procedure. The inhibitor consists of silica nanoparticles grafted with hydrophobic branches and amines; using triethoxysilane (TS), tetraethoxy orthosilicate (TEOS), and 3-(aminopropyl)trimethoxysilane (APTMS). As the weight loss measurements indicated, the synthesized material showed good corrosion inhibition performance.
Picture for Using Machine Learning to Assess Internal Corrosion Constituent Thresholds
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Using Machine Learning to Assess Internal Corrosion Constituent Thresholds

Product Number: 51324-20677-SG
Author: Nicole Moore; Christopher Taylor; Christopher Kagarise; John Cotti
Publication Date: 2024
$40.00
Natural gas pipeline operators often rely on gas and liquid sample analysis as well as bacteria serial dilution to determine if corrosive conditions exist within the pipeline. When corrosive conditions are suspected, additional monitoring methods such as corrosion coupons or probes are employed. One of the challenges faced by operators is determining what constitutes “corrosive conditions” because existing regulations do not define gas or liquid compositions that are corrosive. In this study, over a decade’s worth of sampling and corrosion monitoring data collected by a natural gas pipeline operator are assessed using machine learning in order to determine the parameters with the greatest influence on corrosion rate. This work combines over 2,300 gas tests, liquid samples, solid samples, and bacteria tests in an attempt to determine if the thresholds the company is using are reflective of where corrosion is actually occurring based on over 1,700 coupon analysis results within an operator’s unique system. The results from this study can be used to guide future sampling practices so that effort is spent collecting the most meaningful data and improving the ability to identify corrosive conditions.
Picture for Real-Time Measurement of Aerospace Organic Coating Condition and Performance in Atmospheric Corrosion Conditions
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Real-Time Measurement of Aerospace Organic Coating Condition and Performance in Atmospheric Corrosion Conditions

Product Number: 51324-20742-SG
Author: Victoria Avance; Rebecca Marshall; Fritz Friedersdorf; Matthew Repasky; Henry Yuchi
Publication Date: 2024
$40.00
The purpose of this work is to develop a predictive coating condition model that processes continuous coating condition measurements to characterize changes in coating protection in atmospheric laboratory and outdoor environments. Zero resistance ammeter measurements across an interdigitated electrode composed of two different aerospace materials were used to monitor the inhibitive ability of a scribed coating and detect loss of inhibitor protection. Results will be presented that demonstrate the ability of a stochastic model to detect loss of inhibitor protection and predict coating failure in comparison to observational results. A description of the samples, electrochemical measurements, and test environments will be reported along with the approach used to extract parameters to model and predict coating performance.
Picture for Synergistic Effect of Magnetite-Enriched Rust Layer and Sulfate Reducing Bacteria on Pipeline Steel Corrosion in Oilfield Produced Water
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Synergistic Effect of Magnetite-Enriched Rust Layer and Sulfate Reducing Bacteria on Pipeline Steel Corrosion in Oilfield Produced Water

Product Number: 51324-20769-SG
Author: Victor Malachy Udowo; Fuchun Liu; Maocheng Yan; Peter C. Okafor
Publication Date: 2024
$40.00
Research shows that microorganisms play a significant role in corrosion of buried steel pipes. Partially hydrolyzed polyacrylamide (HPAM), a polymer commonly used to enhance oil recovery (EOR) from reservoirs, has been found to benefit microorganisms as a nutrient source, resulting in severe microbial corrosion of steel in the vicinity. Herein, microbial corrosion behavior of carbon steel was examined under active Fe oxide and inert sand deposits in oilfield water containing HPAM and sulfate-reducing bacteria (SRB). The electrochemical results show that corrosion rate of the steel under the Fe oxide deposit was generally higher than that under the sand deposit. The steel under the Fe oxide deposit suffered severe pitting assault with wider and deeper pits of about 32.65 µm. In comparison, corrosion severity decreased in the sand-deposited sample (having a maximum pit depth of 11.22 µm). The results demonstrate a synergistic effect between SRB activities and Fe oxide deposits to exacerbate steel corrosion in the oilfield water containing HPAM gel.
Picture for Effect of Drying on Corrosion Mitigation of Hanford Transfer Lines
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Effect of Drying on Corrosion Mitigation of Hanford Transfer Lines

Product Number: 51324-20794-SG
Author: Pavan K. Shukla; Joshua Boerstler; Roderick E. Fuentes; Bruce J. Wiersma; Crystal Girardot
Publication Date: 2024
$40.00
Radioactive waste is stored in underground, carbon-steel double-shell tanks at the Department of Energy Hanford site. The waste is transferred between the tanks and other assets using the transfer lines spanning throughout the various tank farms at Hanford. The transfer lines consist of a pipe-in-pipe design, small diameter pipes, and are not piggable. Recent inspection data of the transfer lines have shown areas with corrosion on both interior of the encasements and exterior of the primary pipes, with nearly 50 percent wall loss on the primary pipes and nearly 25% wall loss on the encasement pipes due to pitting corrosion. The visual inspections of the transfer lines have shown presence of corrosion products near the pipeline risers and beyond. It has been hypothesized that the corrosion is predominantly due to the high humidity conditions and in some cases is driven by the presence of residual hydrotest water in the encasement and the associated contact with the safety significant primary pipe. Therefore, drying of the transfer lines could lead to corrosion mitigation. Experimental studies are being conducted to understand the effect of environmental conditions, especially, relative humidity and temperature, on transfer line grade carbon steel corrosion and on mitigating corrosion. The experimental conditions are selected based on the seasonal temperature changes, and relative humidity conditions ranging from 30 to 100 percent. The experimental data will be used as guidance for maintaining a dry environment that will help mitigate the transfer-line corrosion caused by the high humidity conditions.
Picture for Pitting Corrosion Detection by Ultrasound Monitoring
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Pitting Corrosion Detection by Ultrasound Monitoring

Product Number: 51324-20810-SG
Author: Magnus Wangensteen; Ali Fatemi; Tonni Franke Johansen; Erlend Magnus Viggen
Publication Date: 2024
$40.00
Early diagnosis is essential for successful mitigation of pitting corrosion, a localized form of corrosion that causes cavities and structural failure in metallic materials. Although ultrasonic inspection techniques are effective in detecting uniform wall thinning, they have challenges in accurately identifying pitting corrosion. The present work proposes a technique for early-stage pitting detection utilizing time-lapse pulse-echo signals. The generation of two-dimensional time-lapse images of ultrasonic reflectivity may be achieved by capturing several ultrasonic traces over a period of time. These images can then serve as input for a neural network trained specifically for the purpose of pitting diagnostics. To obtain a substantial training dataset required for training the machine learning model, a drilling experiment was conducted, and random time-ordered combinations of the pulse-echo measurements produced the time-lapse images. A classification neural network was trained to detect the presence of pits, while a separate regression network was trained to estimate the pit depth. Test data from a previously unseen transducer indicates that the pit depth estimations exhibit a mean absolute error of less than 0.2 mm. All pits are reliably identified when they exceed the defined pitting threshold of 0.5 mm by a depth of 0.1 mm.
Picture for Corrosion Deposits Data Base - X-Ray Diffraction Analysis of Deposits from Oil and Gas Upstream Well/Production Systems
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Corrosion Deposits Data Base - X-Ray Diffraction Analysis of Deposits from Oil and Gas Upstream Well/Production Systems

Product Number: 51324-20831-SG
Author: Anil Kumar Chikkam; Mehrooz Zamanzadeh; Sunil Kumar Pulagam; Ganesh P; Perry Mortel
Publication Date: 2024
$40.00
This paper presents the analysis results of a wide range of corrosion deposits, scale deposits, and sludge collected from various components within the oil and gas upstream well/production systems. The accumulation of corrosion deposits within equipment can lead to catastrophic failures and unplanned shutdowns of well/production operations. Therefore, understanding the nature of these deposits and identifying their composition is crucial. This study aims to identify the phases and compounds present in corrosion deposits and determine their source. Furthermore, the identification and characterization of these deposits assist clients in determining the underlying causes of corrosion, enabling the development of effective corrosion mitigation strategies. The X-ray Powder Diffraction (XRD) data presented in this paper serves as a valuable resource for clients during major problems and shutdowns, as no comprehensive database of this nature currently exists. The paper also outlines the sample preparation and analysis procedures employed to examine these corrosion deposits thoroughly.
Picture for Critical Review of International Standards on Soluble Salts Measurement Methods
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Critical Review of International Standards on Soluble Salts Measurement Methods

Product Number: 51324-20851-SG
Author: Sophia Xiaoxia Zhu; Benjamin T. A. Chang
Publication Date: 2024
$40.00
It is well known that the residual salts on steel substrates have detrimental effects on the coating performance. There are several international standards on the measurement of residual salts. The most widely recognized ones are ISO 8502-6 and 8502-9. ISO 8502-6 specifies the soluble salts extraction procedures and ISO 8502-9 specifies the calculation of the soluble NaCl salt. The standards use 3 ml deionized (DI) water in 10 minutes dwell time to extract the soluble salts to measure with a potable conductivity meter. The measured conductivity reading in µS/cm is multiplied by 1.2 to convert into total (NaCl) salts in mg/m2. The ISO standards assume the extracted salt solution containing only Na+ and Cl- ions and use a simple analytical calculation to convert the conductivity to the total NaCl salt concentration on the contaminated steel surface. In fact, in addition to Na+ and Cl- ions, Fe+2, OH- ions are also in the extracted salt solution contributing to the conductivity reading, but not considered in the total salt calculation. The ISO standards on the total (NaCl) salt measurement are oversimplified that leads to inaccurate estimation of the residual salts. The chloride ions in aqueous condition can cause micro-pits on the carbon steel surface. The pit density and depth are related to the salt levels and corrosion reaction time. During the salt measurement, the DI water can not readily migrate to the micro-pits to extract salts, and the salt extraction efficiency depends on the corrosion severity. In this work we have investigated the salt extraction on doped salted steel panels with five known amounts of NaCl salt. We also used a chloride electrode to measure the chloride ion concentration. The test results showed that the salt extraction efficiency depends on the severity of the pitting corrosion. Based on the chloride level, the extraction efficiency is 90% at low salt content and 50-66% at higher salt content on the grit blasted panels using Bresle patch method. It is recommended to use the residual chloride concentration in the coating specifications as the acceptance criterion, not the total NaCl salt level. More research is to be done to investigate the residual chloride measurements to give the international coating community a more reliable test method in the field.
Picture for Case Histories of Permian Area Scale Treatment Challenges and Chemical Program Optimization Strategies
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Case Histories of Permian Area Scale Treatment Challenges and Chemical Program Optimization Strategies

Product Number: 51324-20857-SG
Author: Haiping Lu; Wei Wei; Chao Yan; Roy Young; David Nix
Publication Date: 2024
$40.00
During production in the Permian Area, one of the most impactful operational issues is scale formation and deposition, which can be related to CaCO3, CaSO4, BaSO4, FeS, etc. Scale can occur anywhere from downhole reservoirs and wellbores to topside facilities. Based on different scale formation species, operation conditions, and system requirements, scale treatment strategies will vary and can include the following aspects: • For downhole conditions, either continuous injection or squeeze application can be applied. Squeeze treatments can effectively prevent carbonate and sulfate scales for typically at least 6 to 12 months and help to reduce the amount of solid deposition downhole and in surface facilities. • For surface facilities, continuous injection is usually applied. Scale inhibitors should be compatible with high TDS & high calcium waters to avoid pseudo scale formation, causing increased usage of inhibitors and even blockage of the system. • Iron sulfide (FeS) scale can be controlled by chelators, i.e., Tetrakis(hydroxymethyl)phosphonium sulfate (THPS), though typically should be combined with corrosion control and even H2S scavenging treatment to reduce FeS solid deposition. This paper presents case histories from the Permian Area, including general scale issues, FeS deposition cases, and guidance for selecting suitable treatment programs to provide insights on future scale treatments in similar operations.

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