AMPP Store - NACE Conference Papers

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Iron Carbonate (Feco3) SLIPS (Slippery Liquid Infused Porous Surfaces) For Enhanced Scale Resistance

Product Number: 51321-16645-SG

Author: Alexander Saul; Anne Neville; Salima Baraka-Lokmane; Aurelie Le Beulze; Thiabaut Charpentier; Suparit Tangparitkul; John-Richard Ordonez-Varela

Publication Date: 2021

$20.00

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Iron Source in Sour Gas/Condensate Wells: Reservoir Fluids or Corrosion?

Product Number: 51317--8998-SG

ISBN: 8998 2017 CP

Author: Giulia Verri

Publication Date: 2017

$20.00

In order to implement an effective iron scale mitigation strategy, operators first need to identify the main source of iron in the system. This work describes a method to predict the “maximum dissolved iron” (MDI) concentration in a reservoir/production system.

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Irradiation Accelerated Corrosion of 316L Stainless Steel T91 and Zircaloy-4 in Primary Water

Product Number: 51317--9131-SG

ISBN: 9131 2017 CP

Author: Stephen Raiman

Publication Date: 2017

$20.00

Austenitic and ferritic-martensitic steel were irradiated with protons while exposed to simulated PWR primary water for 4-72 hr in 320°C water with 3 wppm hydrogen while irradiated at surface dose rates from 400-4000 kGy/s (4x10-7 to 7x10-6 dpa/s).

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Is it MIC or Pitting Corrosion? An Insight in a Common Overlapping

Product Number: 51320-14719-SG

Author: Mohammed Al Muaisub

Publication Date: 2020

$20.00

Although Microbiologically Influenced Corrosion (MIC) is a critical damage mechanism that had been researched for decades in different environments, yet diagnosing a specific industrial failure to be attributed to MIC can still be challenging. The challenge of accurately identifying an MIC failure is partially due to the similarity of the failure morphology with other damage mechanisms, e.g., pitting corrosion due to chloride. Furthermore, the variously proposed initiation and propagation mechanisms for different types of bacteria may illustrate to the failure analyst that the MIC mechanisms are not yet well established. The confusion of MIC failure identification could also be aggravated by the fact that the presence of bacteria in a system does not necessarily mean that MIC is the culprit. Therefore, this paper will shed some light on the overlapping areas between MIC and pitting corrosion, especially the morphology of the attack. Moreover, several steps will be highlighted and discussed on how to correctly identify if MIC is the culprit in a specific failure.

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Isocyanate Free Water Repellent Top Coat For Offshore Corrosion Protection

Product Number: 51321-16640-SG

Author: Rifnur Latipov/ David Morton

Publication Date: 2021

$20.00

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Isothermal Oxidation Behavior of Chromia-Forming and Alumina-Forming Nickel-Base Alloys in Dry and H

Product Number: 51319-13520-SG

Author: Nicholas Ury

Publication Date: 2019

$20.00

Nickel-base alloys are used in high temperature environments such as heat exchangers and land-based gas turbines where oxidation becomes a significant issue. To mitigate oxidation these alloys contain chromium and aluminum to form protective oxide layers. In dry air the behavior of chromia- and alumina-forming alloys can be predictable. However several high temperature applications contain a significant amount of water vapor which in turn can lead to enhanced corrosion. The effects of water vapor are not completely understood. Hence a comparative study of the oxidation behavior of two nickel-base alloys – UNS N06230 and UNS N07214 - in dry and wet air was undertaken. UNS N06230 a chromia former and UNS N07214 an alumina former were oxidized at 1000°C in dry and wet (15 volume% H2O) air for times of 1 minute 10 minutes 1 hour 5 hours 10 hours and 100 hours using thermogravimetric analysis. The coupons were characterized using X-ray diffraction and scanning electron microscopy coupled with energy dispersive spectroscopy. UNS N06230 performed better overall in wet air when compared to UNS N07214. Mechanisms for this difference will be discussed.

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Kinetic and Morphological Investigation of Calcium Sulfate Dihydrate (gypsum) Scale Formation on Heat Exchanger Surfaces in the Presence of Inhibitors

Product Number: 51317--9020-SG

ISBN: 9020 2017 CP

Author: Zahid Amjad

Publication Date: 2017

$20.00

Gypsum scale formation takes place directly on the surface of heat exchanger without bulk or spontaneous precipitation in the reaction cell. Polymeric and non-polymeric inhibitors have been examined for their effects on the rate of scale formation.

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Kinetic Approach To Predict Iron Carbonate Precipitation During Acid Stimulation

Product Number: 51321-16769-SG

Author: Peng Lu; Qiwei Wang; Tao Chen

Publication Date: 2021

$20.00

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Kinetic Turbidity Test Method For Scale Inhibitor Evaluation On Multifunctional Scales

Product Number: 51321-16959-SG

Author: Johnathon Brooks; Haiping Lu; Miriam Barber

Publication Date: 2021

$20.00

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Lab Performance Testing on Corrosion Inhibitors Under Supercritical Carbon Dioxide Conditions

Product Number: 51317--9474-SG

ISBN: 9474 2017 CP

Author: Larry Chen

Publication Date: 2017

$20.00

This paper discusses the design philosophy for corrosion inhibitors used for carbon capture, transportation, and storage and the performance testing using rotating cylinder autoclave (RCA) and electrochemical impedance spectroscopy (EIS) methods under CO2 supercritical conditions.

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Lab Research and Filed Experience of HDPE-Lined Tubing used in Nitrogen Injection Well

Product Number: 51319-13346-SG

Author: An Qing Fu

Publication Date: 2019

$20.00

The tubing of nitrogen injection well suffered heavily corrosion due to nitrogen containing 2%~5% oxygen HDPE-lined tubing was employed as one of the cost-effective measures to mitigate tubing corrosion. Two kinds of HDPE liner with white and black colors were selected as candidates for tubing liner used in nitrogen injection well performance of two HDPE liners were characterized under three conditions including as-received (A) after one month immersed in simulated oxygen-containing water under elevated temperature (B) half-year serviced in field downhole environment (C). The values of vicat softening temperature of red and blue HDPE liners are 84.5℃ and 82.6℃ respectively the vicat softening temperature is known as the key parameter for non-metallic material selection.In lab test the elongation after fracture tensile strength micro-morphology of HDPE liners tested in condition B (80℃) is almost identical to condition A; while the elongation is substantially lost in condition B (100℃) the general appearance of two liners is still white and black but several cracks were observed on both HDPE liners by microscope; two liners are full with cracks in condition B (120℃) and the elongation is totally lost the general appearance of two liners is both black due to carbonizing; the two liners are further carbonized in condition B (140℃) only small pieces were founded after test.It is found that the white HDPE liner is better than black liner white HDPE lined tubing was selected for nitrogen injection well seven tubing sections used for nitrogen injection well from bottom to top with temperature varied from 120℃ to 80℃. The liners of bottom three sections with temperature from 110℃ to 120℃ are totally fallen off only tubing body with heavily corrosion and corrosion products were observed. The liners of middle three sections with temperature from 97℃ to 88℃ are cracked which are still adhered to the tubing body the color is black due to carbonizing. The liner of the top one section with temperature of 80 ℃ is still in intact condition the values of vicat softening temperature in condition A condition B (80℃) and condition C (80℃) are 84.5℃ 82.6℃ and 79.8℃ the values of elongation after fracture are 511.25 430.88 and 511.20 the values of tensile strength are 29.82MPa 23.56MPa and 23.42MPa. It is can be seen that the lab simulated test are highly in accordance with the field test results which provided a good guidance for the selection of HDPE liner for nitrogen injection well.

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Laboratory Experimental Methods for Estimating Inhibition Performance of Corrosion Inhibitor for Deepwater Natural Gas Pipeline

Product Number: 51319-13321-SG

Author: Yun Wang

Publication Date: 2019

$20.00

CO2 corrosion has become a problem that can not be ignored for the deepwater natural gas pipeline. At present this is difficult to simulate the low water content and the high gas flow velocity for natural gas field in the deep water by the traditional evaluation method of corrosion inhibitor in the laboratory and the accuracy of experimental results is questionable. In this paper laboratory simulation of actual natural gas field conditions was carried out using traditional rotating cylinder electrodes and self-made wet gas flow loop via considering the wall shear stress and mass transfer function as the hydrodynamic parameters to equivalent actual working conditions and laboratory conditions. The effect of corrosion inhibitor in high gas flow velocity was evaluated by using the weight loss test the Microcor ER probe and the self-made electrochemical probe respectively. By comparing the evaluation results of above methods the advantages and disadvantages of each method are analyzed at same time the most suitable method and process for the evaluation of corrosion inhibitors are screened and formulated in deepwater natural gas pipelines. In addition it provides the theory and data support for the evaluation of the corrosion inhibitor in deepwater natural gas field.

NACE Conference Papers

Association for Materials Protection and Performance