AMPP Store - Products tagged with 'sulfur'

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07565 Effect of Mercaptans and Other Organic Sulfur Species on High Temperature Corrosion in Crude and Condensate Distillation Units

Product Number: 51300-07565-SG

ISBN: 07565 2007 CP

Author: J. D. Jong, A. Saunders-Tack, M. Sargent, A. M. Etheridge, W. C. Fort, and N. Dowling

Publication Date: 2007

$20.00

The corrosivity of four mercaptans and selected crude oil fractions were measured in lab tests. Conclusion: Mercaptan corrosion can contribute significantly to the total sulfur related corrosion in the temperature range 235–300°C, which agrees with observations of elevated temperature corrosion in refinery distillation equipment.

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11120 Sulfur Corrosion Due To Oxygen Ingress

Product Number: 51300-11120-SG

ISBN: 2011 11120 CP

Author: Joseph Boivin and Scott Oliphant

Publication Date: 2011

$20.00

Case histories are presented where Oxygen ingress has led to Sulfur corrosion failures in pipelines and downhole equipment.

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51318-11320-Study of Repetitive Failure of a Gas/Gas Heat Exchanger

Product Number: 51318-11320-SG

Author: Saleh Al-Sulaiman / Sundip Kuthe / Sharad Londhe / Abdul Razzaq Al-Shamari

Publication Date: 2018

$20.00

A case history of repeated failure of a gas/gas shell and tube heat exchanger in a gas dehydration unit in a gathering center. The investigation showed that corrosion products had resulted in the blockage.

Assessing Environmentally Assisted Cracking Of Structural Alloys In Molten Salts

Product Number: ED22-17120-SG

Author: George Young, Jake Quincey, Andrew Brittan, Pit Shulze, Stella Tsotsos, Lars Parrington, Josef Parrington, Anne Demma, Micah Hackett, Samuel Briggs and Julie D. Tucker

Publication Date: 2022

$20.00

The potential for structural alloys to undergo environmentally assisted cracking in molten salts is relatively unexplored due to their limited industrial application. However, fluoride salts are of prime interest to many advanced reactors including the Kairos Power FHR reactors. Table I summarizes literature studies of EAC in molten fluoride salts. For the ten studies shown, seven are for Ni-Mo-Cr family of alloys (INOR-8 / Hastelloy N or variants) that were used in the Molten Salt Reactor Experiment (MSRE), two studies investigate austenitic stainless steels, and there is one report of EAC in oxygen free high conductivity (OFHC) copper.

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Evaluation of Alloy 825 Performance in a Critical Sour Environment with Elemental Sulphur Deposition

Product Number: 51324-20853-SG

Author: Ruqaia Al Rusheidi; Mohamed Ossama; Arwa Al Wahaibi; Talal Al Nabhani; Zaher Al Hajri

Publication Date: 2024

$40.00

The deposition of elemental sulfur is a major concern in the gas and oil industries. The effect of sulfur deposition on nickel-based alloy 825 under severe conditions is not well understood. This work investigates the impact of elemental sulfur deposition on Alloy 825 under two conditions using four-point bend test in accordance with NACE TM0316.The results show that alloy 825 samples were not affected by way of SSC, SCC, pitting or other corrosion damage mechanisms in temperature of 90° C, pressure of 75 bar, Chloride level of 1000 ppm, a partial pressure of H2S of 12 bara, and a partial pressure of CO2 of 55 bara with present of elemental sulfur. A further autoclave exposure test was performed in which alloy 825 samples were exposed in 20 bara H2S partial pressure and 57 bara CO2 partial pressure in 21,853 ppm chloride and =150gL-1 elemental sulfur at 190°C for 720 hours. Under this condition, alloy 825 shows environmentally assisted corrosion as well as SCC on all samples. As a conclusion, alloy 825 is not a robust material against elemental sulfur related degradation at high temperature and pressure with high H2S and CO2 environment. Hence, safety risk from elemental sulfur deposition at high temperature should be carefully considered and evaluated when using alloy 825. The limit tested in this paper could provide a reference for selecting alloy 825 in presence of sulfur.

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Evaluation Of Dead Leg Piping with Internal Corrosion at A Salt Dome Natural Gas Storage Facility

Product Number: 51323-19041-SG

Author: Leslie A. Ward, Len J. Krissa, Garry Matocha, Thomas Pickthall

Publication Date: 2023

$20.00

The essence of this paper is to talk about internal corrosion found in deadleg piping at the Enbridge Gas Transmission, & Midstream (GTM) Egan Hub Partners Storage Facility and especially how the corrosion was evaluated after the deadlegs were removed. The salt dome cavern storage facility is in south central Louisiana. The internal corrosion was found in the piping that comes from the storage caverns and goes through pressure reduction stations and then through dehydrations systems.

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Failure Analysis Of A Vacuum Pump Component In A Geothermal Power Plant

Product Number: 51323-19044-SG

Author: Charles Thomas, Liam Rowlands, Keith Lichti, Nathan Gibson

Publication Date: 2023

$20.00

This case study highlights the challenges facing designers of equipment required to operate in geothermal environments. It describes the failure of a non-condensable gas extraction pump at the Nga Awa Purua Power Station (NAP) which has a capacity of 140 MW. The station is located near Taupo in the North Island of New Zealand (Figure 1) and was commissioned in 2010.

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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.

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Introducing An Innovative Simultaneous Naphthenic Acid, Sulfidation And Mass Transport Corrosion Model

Product Number: 51321-16755-SG

Author: Abbey Wing; Winston Robbins, PhD; Gerrit Buchheim, P.E.; Frank Sapienza

Publication Date: 2021

$20.00

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Mechanistic Insights into Refinery Sulfidation Corrosion

Product Number: 51323-19107-SG

Author: Ishan Patel, Gheorghe Bota, David Young

Publication Date: 2023

$20.00

High temperature sulfidation (or sulfidic) corrosion of steel by sulfur species in crude oil has long been known to damage refinery equipment. Corrosion engineers have been using prediction curves derived from field corrosion data to estimate rates of sulfidation corrosion. However, a significant inaccuracy is often encountered in these estimations because of the extensive diversity in molecular structures of sulfur compounds in crude oils.

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Predicting Corrosion of Successive Feeds in Distilling Units - An Experimental Approach

Product Number: 51324-20668-SG

Author: Gheorghe Bota; Ishan Patel; Peng Jin; David Young

Publication Date: 2024

$40.00

Cheap heavy crudes become attractive for oil refineries to increase their benefit margins but the corrosivity of heavy crudes compels the refinery engineers to blend them with the more expensive light sweet crudes. Crude oil blends with complex composition including organo-sulfur compounds, fatty acids, nitrogen and chlorine compounds become corrosive when processed at high temperatures due to these reactive species. Therefore, maintaining corrosion control is a constant effort in oil refineries, and it involves the use of dedicated corrosion models combined with specific experimental lab procedures and methods. This work is presenting the practical application of a lab testing procedure used for predicting the high temperature corrosivity of different crude fractions that were run successively for different time periods in a specific “flow-through” apparatus. The testing procedure consists of two distinct phases performed in the same apparatus, at the same temperature, and for different time durations. During the first phase of the test, scales are formed using a distilling fraction on metal samples and further, in the second test phase, these preformed scales on samples are exposed without interruption to a different distilling fraction. Thus, the two successive test phases, each using a different distilling fraction, are associated with the “changing feeds” in the distilling tower. Corrosive effects are evaluated by sample weight loss measured in successive fraction tests and in separate tests performed with each of the selected fractions. Experimental results are compared to predictions of a corrosion model for sulfidation and naphthenic acid corrosion.

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Predicting Hot Oil Corrosion: A Framework for Quantifying Reactive Organic Sulfur Compounds in Crude Unit Process Streams

Product Number: 51323-19105-SG

Author: Winston Robbins, Sridhar Srinivasan, Gerrit Buchheim

Publication Date: 2023

$20.00

In Corrosion/2021, the authors introduced a molecular mechanistic model that quantifies and predicts SNAPS corrosion rates. During Corrosion/2022, we presented the mechanistic corrosion prediction framework describing the molecular basis of the model’s reactions, kinetics, and mass transport of ROSC to vessel walls. In this molecular model, sulfidation corrosion is calculated for direct heterolytic reaction of ROSC with solid surfaces.

Products tagged with 'sulfur'

Association for Materials Protection and Performance