AMPP Store - Online Conference Paper

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Investigating the Application of the Effective Area Approach to Estimating Fatigue Life

Product Number: 51324-21053-SG

Author: Zach Booth; Ben Hanna; Steven J Polasik

Publication Date: 2024

$40.00

Fitness-for-service assessments of corrosion flaws in line pipe often use an Effective Area Method approach (e.g., RSTRENG) to estimate criticality. This method evaluates all contiguous combinations of flaw dimensions that can be defined via a detailed profile. The lowest burst pressure of those combinations is considered the estimated burst pressure of the flaw. This paper investigates the use of an effective area approach to estimate the remaining fatigue life of crack-like flaws described by a detailed profile. Using flaws reported from in-line inspection, the burst pressure and fatigue life of all combinations of flaw dimensions were estimated using the CorLAS™ fracture mechanics model. For some profiles, the effective area corresponding to the lowest burst pressure is not the same as the effective area corresponding to the lowest fatigue life. Therefore, additional analyses of flaws with detailed profiles may be warranted when developing remediation plans considering both fatigue life and burst pressure.

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Investigating The Effect Of H2S And Corrosion Inhibitor On The Corrosion Of Mild Steel Under High Pressure CO2 Conditions

Product Number: 51322-17943-SG

Author: Yoon-Seok Choi, Fernando Farelas, Luciano Paolinelli, Ahmad Zaki B Abas, Azmi Mohammed Nor, Muhammad Firdaus Suhor

Publication Date: 2022

$20.00

Over the past decade, there has been increasing interest in the corrosion behavior of carbon steels in supercritical CO₂ conditions. Unlike the case of carbon capture and storage (CCS) where small amounts of water are present, the exploitation of fields with high pressures of CO₂ needs to consider the presence of formation water, which presents strong corrosivity. It has been reported that the aqueous corrosion rate of carbon steel at high CO₂ pressures (liquid and supercritical CO₂) without protective FeCO₃ corrosion product layers is very high (>20 mm/y) due to the high concentrations of corrosive species such as H⁺ and H₂CO_³.^1-5 Steels with low Cr contents (i.e., 1% Cr and 3% Cr) have shown no beneficial effect in terms of reducing the corrosion rate to admissible values.6 Therefore, controlling corrosion in these cases usually involves the use of corrosion resistant alloys (CRAs) or corrosion inhibitors (CI). Adequate protection of carbon steel was achieved by applying CI in high pressure CO₂ environments.⁶

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Investigating the Effect of Trace O2 Concentrations on CO2 Corrosion Mechanisms

Product Number: 51324-20996-SG

Author: Shrirang Deshmukh; Bruce Brown; David Young

Publication Date: 2024

$40.00

CO2 co-produced in brine with crude oil is the governing corrodent in upstream oil and gas systems. A potential additional corrosive species that can be introduced through ingress is O2. Consequently, strict guidelines exist within the oil and gas industry to limit O2 levels in production environments, emphasizing the significance of understanding any associated corrosion risks. These guidelines require O2 concentrations to be as low as 20 ppb, however, there is little to no experimental evidence to support this limit. The aim of the research described herein was to advance the understanding of how trace O2 concentrations can influence CO2 corrosion mechanisms of bare steel at the acidic pH of 4. Elucidating these underlying mechanisms would enable more effective corrosion prediction, thereby enabling development of effective mitigation strategies, as well as establishing validity of the aforementioned “20 ppb” guideline related to O2 ingress. To accomplish these goals, controlled experiments were performed to test aqueous O2 concentrations up to 100 ppb on pipeline steel in a CO2 saturated 1 wt% NaCl brine at 1 bar total pressure. Various electrochemical analytical techniques, including LPR, EIS, and potentiodynamic polarization measurements were employed. The research reported herein is foundational for characterizing the impact of oxygen in CO2 corrosion environments, an ongoing research activity. This will contribute to the development of more reliable and sustainable corrosion control practices for industries experiencing CO2 corrosion which can be extendable to carbon capture and transmission systems.

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Investigating the Interaction of Brine Solutions and Diluted Inhibited HCl Acid on Coiled Tubing Steel Corrosion

Product Number: 51320-14596-SG

Author: N. Chkolny, J. Burns, D. Maley, C. Wiggins

Publication Date: 2020

$20.00

Coiled tubing is defined as a continuous tubular product that is used for oil and gas well interventions. Its popularity continues to grow due to its versatility and speed of operation. Though superior grades of metal alloys exist in terms of corrosion resistance, coiled tubing operations primarily employ high-strength low-alloy steels because of their availability, lower cost and weldability. The low-alloy steel can also be thermo-mechanically controlled to elicit specific material properties, such as yield strength and ductility. These coiled tubing steels are often introduced into potentially corrosive downhole conditions, therefore proper testing must be completed to ensure adequate corrosion protection prior to job execution. Downhole corrosive conditions often encountered include; oxygen saturated fluids, elevated temperatures, exposure to oxidizing agents, hydrochloric acid and highly concentrated brines. Often these fluids will be recirculated in a closed loop system, consistently re-exposing equipment to potentially damaging conditions. Frequently, these challenging conditions faced are tested individually with pressurized mass loss coupon testing at bottom hole conditions. However, due to a recent coiled tubing incident in which the coiled tubing pipe had completely parted downhole, the post-job incident investigation involving SEM and metallographic analysis revealed pitting corrosion throughout the tubing, despite the pre-job testing performed indicating adequate acid corrosion protection for the entirety of the job. A literature review indicated very little research was available involving the possible interaction of brine solutions and diluted acid on coiled tubing carbon steels. This paper aims to investigate the possible corrosive interactions between salt brines and inhibited acid blends at elevated temperatures on high grade coiled tubing coupon samples through metallographic examinations and mass loss tests in pressurized heated cells. Coiled tubing coupons will be exposed to a variety of acid blends diluted with a 10% brine (8% wt NaCl and 2% wt CaCl2) or fresh water to investigate the possibility of corrosion enhancement between saline fluids in a diluted acid system.

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Investigating the thermal stability and corrosivity of biocrude oil at FCC feeding temperatures for co-processing applications

Product Number: 51323-18895-SG

Author: Henry Pedraza, Yimin Zeng, Haoxiang Wang, Jing Liu, Xue Han

Publication Date: 2023

$20.00

Biomass, as a renewable energy source, can be converted into bio-oil (BO) via thermochemical conversion pathways. Among them, fast pyrolysis is the most common and the only industrially applied approach to convert dry biomass into BO. There are many advantages of using BO to replace traditional fossil fuels. For example, the amount of CO2 generated from biofuel combustion is close to that absorbed in raw biomass growth, leading to a net-zero carbon emission from energy production. BO combustion generates lower emissions of SOx and NOx compared to conventional fossil fuels.

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Investigating the Trends in Coating Degradation During Long Term Accelerated Testing

Product Number: 51324-21021-SG

Author: Anand H.S. Iyer; Andreas Løken; Anders W.B. Skilbred

Publication Date: 2024

$40.00

Accelerated corrosion testing has been an integral part of estimating the durability of protective coatings on metal substrates. Test methods such as salt spray and artificial ageing has been used extensively according to the requirements put forward by the ISO 12944 standards. The testing time depends on the corrosivity of the environment as well as the durability expected from the coatings. For the highest corrosion class, this can range up to 4200 hours (approx. 6 months). With the ongoing demand for coatings with higher durability (> 25 years), the testing time will be further increased. This in turn results in prolonged periods of testing requiring a huge number of resources. We therefore conducted a study to determine the presence of any trends in the corrosion creep observed in salt spray testing as well as artificial ageing. An epoxy with a polyurethane topcoat was chosen as the paint system, and salt spray tests according to ISO 9227 and artificial ageing according to ISO 12944-6 and 9 were conducted for various durations. Following the end of testing, the evaluation of degradation was performed using corrosion creep as a parameter. Visual examination was performed to observe any visible degradation. The barrier properties of the coating system were evaluated using Electrochemical Impedance Spectroscopy (EIS) according to ISO 16773-2. Supplementary data obtained from water condensation tests and adhesion pull-off tests shall as be presented as well. The identification of trends in such corrosion tests opens the possibilities of estimation of corrosion behaviour of paint systems based on a finite set of data.

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Investigation & Mitigation Of Corroding Unbonded Post-Tension Tendons

Product Number: 51322-17781-SG

Author: Lenard Mancs, David Whitmore

Publication Date: 2022

$20.00

Unbonded post-tensioned reinforcement in concrete structures has been used for many years in elevated slabs (parking garages and residential or commercial buildings), residential foundations, walls, and columns and more recently in bridge structures. The use of unbonded post-tensioned reinforcing allows for unique and cost-effective design and construction that include: thinner concrete sections, longer spans between supports, stiffer walls to resist lateral loads, and stiffer foundations to resist the effects of shrinking and swelling soils.

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Investigation of Acid Corrosion Inhibition Using N,N′-(1,4-phenylenebis(methyl))bis(N,N-dimethylalkan-1-aminium) Chloride Corrosion Inhibitors

Product Number: 51320-14723-SG

Author: Norah Aljeaban, Nurudeen A. Odewunmi, Bader Alharbi, Mohammad A. Jafar Mazumde, Salem Balharth, Shaikh A. Ali

Publication Date: 2020

$20.00

The application of corrosion inhibitors (CI) to producing oil and gas field systems is one of the most common practices of corrosion control. Acid stimulation fluids such as hydrochloric acid (HCl) and organic acids has high calcite and dolomite dissolving power; however, pumping HCl downhole during acid stimulation process particularly at elevated temperatures can cause severe corrosion. Therefore, the addition of corrosion inhibitors is indispensable to protect the metal from corrosion. More inhibitors that are efficacious are still needed to provide better protection against the corrosion.
Two new bisquaternary ammonium salts; 1,4-Benzenedimethanaminium, N,N'-didodecyl-N,N,N',N'-tetramethyl-, dichloride (CI-1) and 1,4-Benzenedimethanaminium, N,N'-dihexadecyl-N,N,N',N'-tetramethyl-, dichloride (CI-2) as corrosion inhibitors were successfully synthesized, characterized and electrochemically evaluated for their corrosion inhibition efficiency in 1 M hydrochloric acid (HCl) solution on API 5L X60 low carbon steel. Potentiodynamic polarization measurement revealed mixed type inhibition mechanisms of the synthesized inhibitors. Inhibition efficiency of CI-1 increase with increase in concentration 2.0 to 20.0 ppm while CI-2 efficiency does not go beyond 2 ppm. Adsorption isotherm of CI-1 was found to deviate from Langmuir isotherm due to its interaction on low carbon steel and the interaction was approximated by Temkin isotherm. Analysis of the adsorption of CI-1 on API 5L X60 involve both physisorption and chemisorption.

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Investigation of CO2 Corrosion Inhibitor Adsorption and Desorption Behavior Using Langmuir Isotherm Model and Effects of Iron Carbide on CI Persistency

Product Number: 51323-19451-SG

Author: Kasra Shayar Bahadori, Bruce Brown, Marc Singer

Publication Date: 2023

$20.00

CO2 corrosion of the internal walls of mild steel pipelines has always been a significant problem in the oil and gas industries. Different methods have been implemented to mitigate internal pipeline corrosion. The use of corrosion inhibitors provides advantages compared to other mitigation techniques as inhibitor treatment costs are seen to be lower and can be easily adjusted over time.

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Investigation Of Corrosion In WAAM Manufactured Materials

Product Number: 51322-18133-SG

Author: Aishwarya, Benoit Verquin, Quentin Petavy, Robert Shandro, Liam Kok Chye

Publication Date: 2022

$20.00

Among the many additive manufacturing processes, Wire Arc Additive Manufacturing (WAAM) has recently been drawing interest due to its great and attractive prospect for fabrication of large parts, the possibility to process a vast range of materials in form of welding wires, and the addition of further details to semi-finished components [1]. However, most of the research have currently focused on optimization of the WAAM process parameters and analysis of the resulting thermal and residual stresses [2]. Unlike conventional manufacturing processes, WAAM process and post-processing treatments result in unique microstructures and material surfaces that alter the corrosion performance of the materials but are not fully studied or understood yet.

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Investigation Of Hydrogen Embrittlement Of A Low Alloy Disc Spring Material Exposed To Several Hydraulic Fluids Using Electrochemical Methods

Product Number: 51321-16853-SG

Author: Jie He; Peter F. Ellis II

Publication Date: 2021

$20.00

$Picture for Investigation of MEG-Water Co-Condensation by In-Situ Refractometry$

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Investigation of MEG-Water Co-Condensation by In-Situ Refractometry

Product Number: 51323-19285-SG

Author: Sondre Borg Gjertsen, Attila Palencsár, Tor Hemmingsen

Publication Date: 2023

$20.00

Top-of-Line Corrosion (TLC) is a practical but costly problem for unprocessed natural gas transport. Utilizing multiphase pipelines instead of processing the well-fluids offshore has required massive modeling development to control hydrate formation and corrosion. At the inlet of the pipelines, the gas, and other well fluids have much higher temperatures than the pipelines' outside environment, e.g., cold ocean water or river water.

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Association for Materials Protection and Performance