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Picture for Performance of Thermally Sprayed Aluminium in 10MPa Supercritical CO2
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Performance of Thermally Sprayed Aluminium in 10MPa Supercritical CO2

Product Number: 51324-21069-SG
Author: Shiladitya Paul; Catherine Leahy
Publication Date: 2024
$40.00
This paper reports the performance of thermally sprayed aluminium (TSA) in an aqueous solution pressurized with 10MPa supercritical CO2 at 40°C. Carbon steel specimen (BS EN 10025 S355) was coated with TSA and exposed to 3.5 wt.% NaCl solution pressurised with 10MPa CO2. The specimen was taken out after the 168h test and post-test examination was carried out. Post-test visual examination indicate no significant signs of damage which was confirmed by microstructural characterization. The SEM micrographs indicated promising behaviour of TSA with no corrosion was seen at the TSA-steel interface. However, one must note that the test was carried out for 168h and such short term test seldom give long-term corrosion performance. Nonetheless, the initial results looks interesting and provides some indication of TSA’s promise for protection of steel against CO2 corrosion.
Picture for Research Progress of Fouling Scale Control Technology in Low Permeability Oilfields
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Research Progress of Fouling Scale Control Technology in Low Permeability Oilfields

Product Number: 51324-21027-SG
Author: Chenglong Li; Qiongwei Li; Ning Liu; Min Yang; Peng Xu
Publication Date: 2024
$40.00
In recent years, Changqing Oilfield has continuously enlarged the scale of exploration and development, and its oil and gas equivalent output has exceeded 6,500 × 104t/a. However, the oilfield has been developed by multiple reservoir system stacking, and it has gradually entered the stage of medium-high water cut, and scaling has become more and more prominent impact of production system. In accordance with compose the prevention and control strategy, chemical and physical scaling technology research and on-site tests have been combined to extend the scaling cycle and slow down the scaling rate, and achieve good results.
Picture for Insulation Driven Intergranular Stress Corrosion Cracking of Carbon Steel
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Insulation Driven Intergranular Stress Corrosion Cracking of Carbon Steel

Product Number: 51324-20914-SG
Author: Matt Krantz; Yuan Li
Publication Date: 2024
$40.00
Over the past decade, an increasing number of intergranular stress corrosion cracking (IGSCC) incidents have been observed on carbon steel assets operating in Alberta, Canada. At the time of publication, over 128 distinct cracks have been identified on 26 assets spanning at least 5 operators. All incidents have occurred on uncoated carbon steel operating between 70 °C and 190 °C and exposed to wet mineral wool insulation. Both piping and pressure vessels have been affected. Cracking has been isolated to assets with mineral wool insulation produced after 2003; however, a specific change to mineral wool composition in this timeframe has not been identified. The purpose of this paper is to provide a summary of incidents and investigations that have been reported to date and to update the environmental conditions (window of susceptibility) where insulation driven intergranular stress corrosion cracking has been observed. By drawing attention to this issue, it is the authors’ objective to increase awareness and determine if similar cracking incidents are occurring in other geographical regions.
Picture for Independent Research on the Effectiveness of Polyethylene Encasement as a Corrosion Control Coating for Ductile Iron Water and Wastewater Piping
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Independent Research on the Effectiveness of Polyethylene Encasement as a Corrosion Control Coating for Ductile Iron Water and Wastewater Piping

Product Number: 51324-20943-SG
Author: Michael J. Szeliga
Publication Date: 2024
$40.00
Polyethylene encasement (PE) is a coating method that consists of a loose wrap of thin plastic around ductile iron piping (DIP), that is typically held in place with PVC tape. It has become the primary means of corrosion control on DIP water and wastewater piping even though no large scale independent studies have been performed to document how often the thin plastic is damaged. Damage to the PE exposes the DIP to direct soil contact and corrosion can occur. The frequency of these exposed anodic (corroding) areas on polyethylene encased DIP has also never been compared to the frequency of anodic areas on uncoated DIP. Uncoated DIP is DIP that that has the 2 to 3 mils thick factory applied black asphaltic paint applied to it. The asphaltic paint is water permeable and provides no significant reduction in corrosion activity on DIP. This research project evaluated cell-to-cell potential data on 89,275 feet of uncoated DIP and 51,609 feet of polyethylene encased DIP. Cell-to-cell potential measurements are the only way to accurately detect areas of corrosion on unbonded DIP.
Picture for Evaluation of a Hydrophobic Coating Material for Downhole Application, Lab vs. Field Evaluation
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Evaluation of a Hydrophobic Coating Material for Downhole Application, Lab vs. Field Evaluation

Product Number: 51324-20756-SG
Author: Tao Chen; Feng Liang; Frank Chang; Qiwei Wang
Publication Date: 2024
$40.00
A hydrophobic electroless nickel-phosphorus (ENP) coating material has been developed to reduce corrosion-induced iron sulfide scale deposition. The ENP coating has several key advantages to provide corrosion resistance for sour oil and gas applications, including a level of phosphorus imparting superior corrosion resistance in a sour gas environment, a tailored phosphorus level providing a range of super hydrophobic microstructures, and a second material introduced and embedded in the ENP coating during the coating process to impart desired properties such as wear and erosion resistance. The coating material has been qualified through a series of evaluation tests carried out in the lab, including iron sulfide scale formation under HTHP, coating adhesion tests, explosive decomposition, formation of heazlewoodite (Ni3S2), etc. The coating material was installed in downhole completion tubing through a downhole corrosion and scale monitoring (DCSM) tool to monitor coating stability, corrosion, and scaling under real downhole flow conditions in a sour gas well over 3 months. Overall, the field testing has demonstrated that this newly developed coating material can effectively protect the metal coupon against corrosion and iron sulfide deposition. However, the abrasion of the formed surface layer of Ni3S2 and blistering might be a concern for a long-term field application. This paper will comprehensively compare the coating performance evaluated in the lab and field conditions. Long-term evaluation under real field conditions is highly recommended to qualify the coating material for large-scale application in the downhole.
Picture for Corrosion of Stainless Steel Alloys in Fresh Water Simulating Condensed Water in Contact with Supercritical CO2- An Electrochemical Study
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Corrosion of Stainless Steel Alloys in Fresh Water Simulating Condensed Water in Contact with Supercritical CO2- An Electrochemical Study

Product Number: 51324-20621-SG
Author: Suresh Divi; Bruce Craig; Adam Rowe
Publication Date: 2024
$40.00
There has been a recent and significant surge in projects for injection of supercritical CO2 (SC-CO2) into saline reservoirs due to enhanced financial incentives. This has created a rush to permit projects without the necessary data to make informed decisions regarding the corrosion resistance of materials for well completions. Of urgent need is a better understanding of the corrosion performance of alloys for injection tubing and well equipment exposed to the injectate above the saline aquifer contact zone. An electrochemical study was performed to simulate contact of SC-CO2 containing some impurities with fresh water consistent with water condensing from the CO2 phase. The simulated condition represents a pH of 3 typical of water in contact with CO2 at greater than 73.8 bar and 31oC. A range of alloys were tested, including 13Cr, 17Cr, 22Cr, and others. Weight loss corrosion and pitting attacks were measured. The results of this study can be used for life prediction only in the cases where there is no localized corrosion to support material selection decisions for well equipment based on upsets and well shut-in during the life of SC-CO2 injection.
Picture for Impurity Reactions in Gaseous and Liquid CO2 Streams
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Impurity Reactions in Gaseous and Liquid CO2 Streams

Product Number: 51324-20788-SG
Author: Bjørn Helge Morland; Gaute Svenningsen; Johannes Sonke
Publication Date: 2024
$40.00
Safe transportation of CO2 for carbon capture and storage requires strict control of contaminants in the captured CO2, so that corrosion and particulate matter problems are avoided. The present work tested two almost similar CO2 specifications for chemical reactions and liquid or solid drop-out. The tests were carried out with CO2 in liquid and gaseous state, at field-relevant pressure and temperatures. It was shown that the NO2 content had a strong effect on chemical reactions and tendency to drop-out, but the threshold was different depending on the physical state of the CO2. Presence of NO2 resulted in chemical reactions. Drop-outs were observed for 3 ppm-mol NO2 in the liquid state (+4°C, 100 bar) and for 8 ppm-mol in the gaseous state ( -3°C, 25 bar).
Picture for Investigating the Application of the Effective Area Approach to Estimating Fatigue Life
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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.
Picture for Destructive Examination Protocol for 3013-Container-Package Storing Plutonium-Bearing Materials
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Destructive Examination Protocol for 3013-Container-Package Storing Plutonium-Bearing Materials

Product Number: 51324-20811-SG
Author: Roderick E. Fuentes; Michael J. Martínez-Rodríguez; Elizabeth J. Kelly
Publication Date: 2024
$40.00
The 3013-container-package consists of a convenience, inner and outer container and is used for long-term storage of plutonium-bearing materials. A destructive examination (DE) protocol has been developed to examine the container package visually and with microscopic aid to find any corrosion conditions that could result in the loss of the integrity of the container package over its lifetime. The DE protocol contains three main steps: initial container examination, helium (He) leak testing, and detailed imaging and analysis of the inner container closure weld region (ICCWR). The ICCWR has been determined to be bounding, defined as exhibiting worst case conditions for stress corrosion cracking (SCC) of the inner container. To assess SCC in the ICCWR, the inner container lid is cut into quarters and the weld and He-leak testing gasket are removed. Then a citric acid wash is performed to remove adherent chlorides from the ICCWR. The wash is then sent for analysis to determine the concentration of chlorides in the ICCWR. While the analysis for chloride concentration is being performed, the quarter sections are further sectioned into 1/8th subsections by cutting each section in half. These subsections are washed using nitric acid to remove corrosion products. Then each subsection is imaged using a Wide Angle 3-D Measurement System (WAMS). After analysis of microscope images for potential SCC, additional imaging can be performed, including subsurface imaging. After review, a determination is made of whether the container integrity may potentially affect the safe storage of the material.
Picture for Evaluation of Alloy 825 Performance in a Critical Sour Environment with Elemental Sulphur Deposition
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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.
Picture for Effect of H2S Fugacity on Hydrogen Uptake in Carbon Steels for Upstream Applications
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Effect of H2S Fugacity on Hydrogen Uptake in Carbon Steels for Upstream Applications

Product Number: 51324-20951-SG
Author: Gaurav R. Joshi; Christophe Mendibide; Jean Kittel
Publication Date: 2024
$40.00
The presence of dissolved hydrogen sulfide in upstream or refining fluids is known to encourage hydrogen-induced mechanical failures of carbon or low alloy steel. Historically, the solution pH and the gaseous partial pressure of H2S (PH2S, bar) are used to evaluate an aqueous environment’s severity during materials corrosion cracking qualification. However, in recent years, it is suggested that the H2S fugacity (fH2S, an effective H2S partial pressure in bar) and actual dissolved H2S concentration ([H2S]aq) be used, rather than the PH2S, to better account for the effect of total pressure on steel corrosion cracking performance. In this paper, results obtained in a Joint Industry Programme (JIP) focused on evaluating the effect of fH2S on the hydrogen permeation across upstream steels using hydrogen pressure probe sensors and electrochemical Devanathan-Stachurski permeation tests are presented. A positive correlation between H-permeation rate at steady-state and environment fH2S or [H2Saq] is measured for numerous carbon steel grades in acetate-buffered 5% NaCl solution at pH ~ 4 and PH2S (~1bar), tested at total pressure between 1 – 300 bar. Furthermore, hydrogen induced cracking of a susceptible carbon steel grade increases when evaluated as a function of increasing fH2S for the same PH2S/pH combination.
Picture for Effects of Silicon Carbide in Corrosion of A36 Gas Shielded Flux Core Welding
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Effects of Silicon Carbide in Corrosion of A36 Gas Shielded Flux Core Welding

Product Number: 51324-21163-SG
Author: Moe A. Rabea; Herbert Wang
Publication Date: 2024
$40.00
Using Gas Shielded Flux Core welding, a butt joint can be analyzed for surface corrosion. The material used with both of these welding processes in this experiment is 1/4-inch A36 Hot Rolled Flat Bar, cut from a single piece, variations of the stock material are minimized. The material is chosen as it is one of the most prevalent material used in many industries that incorporate heavy steel usage. The flat bar measures 3-inch in width, 1/4-inch in thickness, and are cut into 2-inch test pieces. Two pieces form a single test subject, which are welded together. One set of the test pieces are applied with SiC (Silicon Carbide) before the welding process. Both sets are then welded with Gas Shielded Flux Core welding. The final dimension of the test piece is 1/4-inch x 4-inch x 3-inch. The welded pieces are then subjected to corrosion testing in a salt spray chamber and results are observed. The salt spray chamber is controlled at 1 bar pressure with 180L brine reservoir at 5% NaCl concentration. The temperature is held constant at 45 °C with a humidity of 50%. The test pieces will be subjected to this condition for 96 hours. A parallel corrosion test conducted using 1% HCl solution at ambient temperature, 35 °C, 45°C, and 55°C. The samples are initially weighed and placed in the HCl solution for 24 hours. Weight loss from thermal shock from quenching is also conducted. Subjects are heated to a temperature of 250, 300, 350, 400, 450, 500, 550°C and quenched for 15 minutes. The final weight is then taken. Microhardness testing is conducted on the weldments. The conclusion of the test reveals that with the incorporation of SiC powder into the welding process, it resulted in less corrosion (weight loss), less weight loss from thermal shock, and increased microhardness.

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