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3228 total products found.

Corrosion, perforated polymer lined pipelines, CO2, H2S, computational modelling, electrochemistry.

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Corrosion Prediction in Perforated Polymer Lined Pipelines (PLP) Used for Oil & Gas Transportation

Product Number: 51324-20954-SG

Author: Gaurav R. Joshi; Remy Mingant; Jean Kittel; Jitender Rai; Carol Taravel-Condat

Publication Date: 2024

$40.00

The perforated polymer-lined pipeline (PLP) is a rigid carbon steel pipeline with internal polymer liner for internal corrosion prevention. The liner is perforated to prevent liner collapse during depressurization. Although the perforations expose the carbon steel to the corrosion fluids within the bore of the pipeline, extensive small-scale and full-scale tests have demonstrated that corrosion at the bottom of each perforation is much less than the corrosion in an un-lined carbon steel pipeline. Based on experience gained on the evaluation and modelling of corrosion in the highly confined environments of flexible pipelines, we have developed a corrosion model to simulate carbon steel corrosion rates corresponding to the perforated PLP system geometry. Predictions from this model could help evaluate corrosion risks at and within perforated liner / steel interfaces. This paper presents an overview of the model and compares its predictions against a variety of experimental data that reproduce the conditions, the geometry, or both, found at the bottom of a PLP perforation. This 1D model considers diffusion and chemical reactions inside an inert hole and incorporates non-ideal thermodynamics (i.e., gas fugacity effects) to describe the aqueous solution chemistry. Electrochemical corrosion equations are compared with experimental data to support validation. This model could serve as a useful tool that complements qualification testing and help validate the PLP technology for a variety of field applications.

Picture for Nanolaminar Nickel-Cobalt Coatings: a Revolution in Wear and Corrosion Resistance

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Nanolaminar Nickel-Cobalt Coatings: a Revolution in Wear and Corrosion Resistance

Product Number: 51324-20660-SG

Author: Marie Li; Herman E Amaya; Steve Brunst

Publication Date: 2024

$40.00

In the demanding environments of the oil and gas industry, the need for superior protective coatings is paramount. This paper explores electrodeposited nanolaminar Nickel-Cobalt (Ni-Co) coatings as a robust solution. Distinguished from traditional offerings, these coatings provide enhanced hardness, wear resistance, and corrosion protection. These qualities make Ni-Co coatings ideal for rigorous applications, including downhole tools, deep-sea equipment, and chemical processing apparatus. Our investigation underlines the crucial role of the unique nanostructure, obtained via specialized electrodeposition techniques, in augmenting the coating properties. The paper also establishes a comparison between Ni-Co coatings and Zinc-Nickel coatings, drawing attention to their distinctive use cases in the industry. While Zinc-Nickel coatings excel in atmospheric or offshore corrosion protection, Ni-Co coatings outperform in more demanding environments requiring stronger mechanical properties and specific corrosive resistance. Characterizing data supporting the exceptional performance of Ni-Co coatings will be presented. By delineating these advancements, the paper underscores the potential of nanostructured Ni-Co coatings to transform equipment protection strategies in the oil and gas sector.

Picture for Can Electrochemical Charging Replace Hydrogen Gas Charging During Hydrogen Embrittlement Testing?

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Can Electrochemical Charging Replace Hydrogen Gas Charging During Hydrogen Embrittlement Testing?

Product Number: 51324-20712-SG

Author: Erik Koren; Roy Johnsen; Dong Wang; Cataslina H.M. Hagen; Anette B. Hagen; Bård Nyhus; Antonio Alvaro; Hisao Matsunaga

Publication Date: 2024

$40.00

This paper presents the output from a study with the aim to correlate hydrogen gas charging and electrochemical charging for a X65 pipeline steel. The hydrogen uptake and diffusivity were evaluated via the permeation technique by employing both hydrogen gas charging and electrochemical charging. The effective diffusion coefficient, Deff, was determined by partial transients. The sub-surface hydrogen concentration, C0R, was then employed to determine the equivalent hydrogen pressure, pH2eq, of electrochemical charging conditions. In parallel, a permeation cell consisting of two membranes with thickness 6 mm welded together with a narrow gap in between was built. This unit was exposed to equal cathodic polarization conditions as the electrochemical permeation cell. The equilibrium pressure in the gap was measured and compared to the calculated hydrogen pressure from the gas permeation test with good correlation. Finally, an initial evaluation through toughness tests with the same X65 material executed in i) hydrogen gas and ii) electrolytic charging at equivalent hydrogen concentrations, gave promising results concerning the correctness of the correlation between the two hydrogen sources.

Picture for Development of a Master Curve to Characterize the Susceptibility of Fastener Materials to Hydrogen Embrittlement

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Development of a Master Curve to Characterize the Susceptibility of Fastener Materials to Hydrogen Embrittlement

Product Number: 51324-20813-SG

Author: Ted L Anderson; Behrang Fahmi; Herman E. Amaya

Publication Date: 2024

$40.00

This paper introduces an innovative approach for mitigating hydrogen embrittlement in materials used in underwater environments, a critical challenge in marine engineering. Our study focuses on developing a comprehensive 'master curve' that encapsulates the complex interplay among key factors: hydrogen concentration, applied potential, and material strength. This curve serves as a predictive tool for evaluating the susceptibility of materials to hydrogen embrittlement, a phenomenon that lacks a one-size-fits-all solution. Through fracture mechanics testing of carbon steel alloys and rigorous analysis, quantitative relationships between these factors are established. This research not only aids in optimizing material selection and designing effective cathodic protection systems but also ensures enhanced safety and integrity in operational contexts. The master curve, rooted in both empirical data and theoretical insights, offers a strategic framework for engineers and industry professionals, guiding decisions that enhance the durability and reliability of subsea equipment.

Picture for Methodologies to Evaluate Corrosion of Carbon and Stainless Steels in Artificial Geothermal Solutions

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Methodologies to Evaluate Corrosion of Carbon and Stainless Steels in Artificial Geothermal Solutions

Product Number: 51324-20716-SG

Author: Gabriela Aristia; Sabrina Marcelin; Nicolas Mary; Gaurav R. Joshi; Francois Grosjean

Publication Date: 2024

$40.00

Corrosion and scaling are some of the most common challenges in geothermal applications due to the complex brine chemistry combined with the high temperatures and pressures, and the gaseous components. To study mineral scaling at metallic surfaces, appropriate corrosion tests representing the real geothermal reservoir and operating conditions must be selected. This paper focus on the reconstruction of thermal gradients between geothermal fluids and the steel walls of wells and heat exchanger tubes, in laboratory and autoclave flow loop tests (up to 200°C and 300 bar), to simulate scaling and corrosion conditions. The implementation of an electrochemical measurement device makes it possible to monitor changes to the electrochemical behaviour of steel subjected to thermal gradients in these environments and so the corrosion response and in situ evolution of scales. Results from carbon steels (N80 and P110) and stainless steel (13Cr) in artificial geothermal brines representative of Dogger and Soultz geothermal wells in France are presented.

Picture for Investigation of the Hydrogen Embrittlement of API 5L Natural Gas Pipeline Steels

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Investigation of the Hydrogen Embrittlement of API 5L Natural Gas Pipeline Steels

Product Number: 51324-20922-SG

Author: Lucas Teeter; Kyle Rozman; Zineb Belarbi; Ömer Doğan

Publication Date: 2024

$40.00

Hydrogen produced during corrosion or through hydrogen blending into natural gas pipelines can lead to the degradation of ductility of metals used in these transmission pipelines. The effect of hydrogen on the mechanical properties of pipeline steels was studied for three grades of API 5L steels: X56, X65, and X100. These steels are either commonly used in or developed for use in natural gas transmission pipelines which are being considered for use in hydrogen blending. These steels were subjected to constant strain rate tensile testing after charging with electrochemically generated hydrogen. This paper reports on work to extend the life of the natural gas pipeline network via understanding the effect of hydrogen embrittlement induced by corrosion processes.

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.