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Picture for Effect Of Dissolved Oxygen On Carbon Steel Corrosion And Particulate Formation In Water Injection Systems. Part 2: Rotating Cage Experiments
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Effect Of Dissolved Oxygen On Carbon Steel Corrosion And Particulate Formation In Water Injection Systems. Part 2: Rotating Cage Experiments

Product Number: 51324-20817-SG
Author: Jose Vera; Ken Evans; Conchita Mendez
Publication Date: 2024
$40.00
Seawater treatment for secondary recovery injection typically includes controlling the dissolved oxygen concentration (DOC) below 20 ppb using a combination of mechanical deaeration and oxygen scavenger injection. However, upsets can occur during operation, which may temporarily increase DOC above the specified values. These DOC excursions may not only significantly increase corrosion rates but also produce corrosion product particles in suspension. The potential influence of suspended particles produced by corrosion in water injection systems’ performance during water injection operations is not well understood. An electrochemically modified rotating cage autoclave (RCA) setup was used in conjunction with a particle analyzer instrument to correlate dissolved oxygen concentration (DOC), corrosion rates and particulate formation in real-time. Dissolved oxygen and pH were also continuously monitored throughout the tests. All testing was performed in a seawater simulant brine at 32°C. The effect of consecutive DOC excursions from 20 ppb to either 100 ppb or 1000 ppb were evaluated at two different flow velocities. The key findings from the testing can be summarized as follows: (1) there is a clear and significant interaction between flow velocity and the corrosion rates caused by the DOC excursions, which is not considered in the available predictive models; (2) localized corrosion was observed mainly on tests with 1000 ppb excursions; (3) The suspended particle concentration starts to increase after the total accumulated iron produced by corrosion reaches a minimum value, usually shortly after the first DOC excursion, and the mean particle size increases, reaching a maximum between 20 and 50 µm.
Picture for Expected Service Life and Cost Considerations for Maintenance and New Construction Protective Coating Work
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Expected Service Life and Cost Considerations for Maintenance and New Construction Protective Coating Work

Product Number: 51324-20960-SG
Author: Jayson L. Helsel; Robert Lanterman
Publication Date: 2024
$40.00
This paper is an update to “Expected Service Life and Cost Considerations for Maintenance and New Construction Protective Coating Work” by the authors in 2022.1 The paper is designed to assist the coatings engineer or specifier in identifying candidate protective coating systems for typical service environments and provides: 1) commonly used generic coating systems; 2) practical maintenance time for each system and service environment; 3) current material costs; 4) current field and shop painting costs; and 5) guidelines for calculating approximate installed costs of the systems. Guidelines for developing long-term life-cycle costs and number of paintings for the expected life of the structure are also included. The basic elements of economic analysis and justification are addressed together with guidance on the preparation of a Present Value Analysis. Examples are provided to aid the reader in the proper use of the information. Updates to the paper include coating system revisions for atmospheric exposure, new discussion related to maintenance painting strategies and new cost information. Key words: protective coatings, life-cycle costs, coating selection, coating system life, containment costs, industrial maintenance, maintenance painting costs, industrial environments, corrosive, solvent-free, metalizing, galvanizing, Present Value Analysis, installed coating costs.
Picture for Corrosion Inhibitor Qualification for Umbilical and Subsea Applications
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Corrosion Inhibitor Qualification for Umbilical and Subsea Applications

Product Number: 51324-20724-SG
Author: Larry Chen; Thenuka Ariyaratna; Nihal Obeyesekere; Tharindu Jayaneththi
Publication Date: 2024
$40.00
Umbilical functionality is critical to the proper operation of subsea production systems to eliminate risks and downtime. The importance of preventing subsea operational issues has led to more stringent chemical quality requirements as the applications have gone deeper in depth, further from shores, and more demanding as far as Health, Safety & Environment are concerned.(1) Production chemicals such as corrosion inhibitors to provide protections for subsea systems from flow assurance to integrity management have become more demanding concerning product performance, stability, deliverability, and compatibility with the materials of construction. The present work describes various laboratory testing techniques used for certificating corrosion inhibitors designed for subsea applications via umbilical and deepwater applications.
Picture for Corrosion of Candidate BoP Alloys for the Hydrogen Side in Alkaline Water Electrolysis
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Corrosion of Candidate BoP Alloys for the Hydrogen Side in Alkaline Water Electrolysis

Product Number: 51324-21036-SG
Author: Morten Tjelta; Jon Kvarekvål
Publication Date: 2024
$40.00
This paper presents corrosion test results of candidate alloys for balance-of-plant (BoP) at the hydrogen side in alkaline water electrolyzers. Experiments were carried out at industrially relevant conditions, i.e. 60-80 °C in 25 wt% KOH solutions at H2 pressures ranging from 1 bar (cf. atmospheric units) to 15 bar (cf. pressurized units). Materials tested were nickel base alloy UNS N06625, austenitic stainless steel UNS S31603, super duplex UNS S327X0 and carbon steel UNS K03014. Mass loss corrosion and localized corrosion based on surface profilometry were used to evaluate materials performance. Corrosion scales were characterized using XRD.
Picture for Sulfide Stress Cracking Resistance of Quenched and Tempered 41XX Low Alloy Steels with 26 HRC Max Hardness
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Sulfide Stress Cracking Resistance of Quenched and Tempered 41XX Low Alloy Steels with 26 HRC Max Hardness

Product Number: 51324-20958-SG
Author: Karthik Krishnan; Cheng Chau Lum
Publication Date: 2024
$40.00
Section A.2.2.3.3 and Table A.3 of current NACE MR0175/ISO 15156-2 version (2021/2020)1 allows for use of 41XX type low alloy steels quenched and tempered in the tubular form if the hardness does not exceed 26 HRC for all temperature, all region sour service similar to the sour service guidelines of API 5CT2/ISO 119603 L80 Type 1 and T95 Type 1 grades. While the clause recommends qualification for use in sour service it does not mandate the same. In this work different 41XX grades heat treated in tubular form to 26 HRC max hardness with varying quench and temper treatments were tested for Sulfide Stress Cracking (SSC) resistance to verify the clause. It is shown that only specific 41XX grades with certain quench and temper heat treatments could pass SSC testing prescribed for all region, all temperature sour service in NACE MR0175/ISO 15156. Hence qualification for use of this Section A.2.2.3.3 should not be optional but required else could lead to use in conditions where the material can have inadequate cracking resistance. This work could help NACE MR0175/ISO 15156 modify this clause to provide better guidelines for use of 41XX low alloy steels with 26 HRC max hardness in sour service. Keywords: Sulfide Stress Cracking (SSC), 41XX low alloy steel, quenched and tempered, sour service, NACE MR0175/ISO 15156
Picture for Synergistic Effect of Chloride, Sulfide and Thiosulfate on the SCC Behavior of Carbon Steel Welds Exposed to Concrete Pore Water under Anoxic Conditions
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Synergistic Effect of Chloride, Sulfide and Thiosulfate on the SCC Behavior of Carbon Steel Welds Exposed to Concrete Pore Water under Anoxic Conditions

Product Number: 51324-20786-SG
Author: B. Kursten; S. Caes; V. De Souza; R. Gaggiano
Publication Date: 2024
$40.00
The supercontainer (SC) is the current reference concept for the geological disposal of vitrified high-level nuclear waste and spent fuel in Belgium. It comprises a prefabricated concrete buffer that completely surrounds a carbon steel overpack. Welding is being considered as the final closure technique of the carbon steel overpack in order to ensure its water tightness. Welding is known to induce residual stresses in the weld zone and its vicinity, which may lead to an increased susceptibility to stress corrosion cracking (SCC). In this study, slow strain rate tests were conducted to study the SCC behavior of plain and welded UNS K02700 grade carbon steel exposed to an artificial concrete pore water solution that is representative for the SC concrete buffer environment. The tests were performed at 140 °C, at a constant strain rate of 5·10-7 s-1 and at open circuit potential under anoxic conditions. The synergistic effect of chloride, sulfide and thiosulfate on the SCC behavior of carbon steel was investigated up to levels of 35,000 mg?L-1 Cl-, 500 mg?L-1 S2- and 600 mg?L-1 S2O32-. In all the tested electrolyte solutions, none of the studied steel configurations, including welded and heat-affected zone materials, were found to be susceptible to SCC.
Picture for Stress Corrosion Cracking of Carbon Steel in CO2 Liquefaction Plant
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Stress Corrosion Cracking of Carbon Steel in CO2 Liquefaction Plant

Product Number: 51324-20393-SG
Author: Qiang Liu, Lawrence Lau, Shoba Kanda, Luigi Esposito
Publication Date: 2024
$40.00
Carbon dioxide is produced during ethanol fermentation. In order to prevent CO2 emission, gas CO2 is compressed, dried, liquefied, and injected into the reservoir for enhanced oil recovery. Under the operating condition of 2200 kPag and -20°C, the entrained ethanol is dropped out of liquefied CO2. The separated ethanol phase at local site resulted in trans-granular stress corrosion cracking of carbon steel piping and heat exchangers. The investigation involves CO2/ethanol phase behavior study, sourcing contaminants, and failure analysis. It is concluded that 1) ethanol stress corrosion cracking (SCC) is the root cause of the failure in presence of water, chloride and oxygen at pH of 3.0. 2) hydrogen stress cracking is the secondary damage mechanism. Trace of H2S originated from sulfate reducing bacteria (SRB) in ethanol plant and was carried over to the liquefied CO2. Its concentration was increased in the ethanol phase. Mitigation of SCC is approached by reducing ethanol carry-over, minimizing O2 ingress, and lowering the level of other contaminants.
Picture for Advancement of a Comprehensive Mechanistic CO2 Corrosion Model to Incorporate Simulated Hydrodynamics via a Turbulent Flow Model
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Advancement of a Comprehensive Mechanistic CO2 Corrosion Model to Incorporate Simulated Hydrodynamics via a Turbulent Flow Model

Product Number: 51324-20657-SG
Author: Michael Jones; Gregory de Boer; Richard Woollam; Joshua Owen; Richard Barker
Publication Date: 2024
$40.00
In this work, two comprehensive mechanistic models of aqueous carbon dioxide (CO2) corrosion produced by Nordsveen et al.1 and Kahyarian et al.2 17 years apart are recreated and compared to highlight the evolution in understanding. The differences between the models include the role of carbonic acid at the surface, whether it is directly reduced or acts as a buffering agent, as well as different mechanisms for the anodic response, and varying temperature responses of multiple input variables. Through recreation and validation of these models using the same software, key comparisons are made to understand the effect of these changes on predicted corrosion rate, surface pH, and speciation through the boundary layers. These values are plotted across a range of input parameters to investigate how the change in scientific understanding influences predictive response of corrosion models.
Picture for Corrosion Testing of Carbon Steel and 13Cr Casing Materials in Simulated Superhot Deep Geothermal Well Environment
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Corrosion Testing of Carbon Steel and 13Cr Casing Materials in Simulated Superhot Deep Geothermal Well Environment

Product Number: 51324-20903-SG
Author: Sigrun Nanna Karlsdottir; Gifty Oppong Boakye; María Ýr Þráinsdóttir; Erlend Straume; Andri Ísak Þórhallsson
Publication Date: 2024
$40.00
Major challenges are encountered in the design and construction of deep superhot (>300°C) geothermal wells due to higher temperatures and pressure, and increased corrosiveness of the geothermal fluid. The corrosiveness of the geothermal fluid is due to the chemical composition which includes corrosive gases such as HCl, H2S and CO2. In this study L80-type 1 carbon steel and L80-13Cr stainless steel API casing materials were tested in a simulated superhot geothermal well environment at 350°C in water with Cl, H2S and CO2 for 168 hrs. in both vapor and liquid phases in high temperature and high pressure (HTHP) autoclave to investigate their corrosion behavior. The results showed that both API casing materials, L80-type 1 and L80-13Cr, were prone to corrosion attack in the simulated superhot deep geothermal well environment. The L80 grade Type 1 carbon steel tested in the liquid phase exhibited the highest corrosion rate and demonstrated vulnerability to localized corrosion or cracking in both liquid and vapor phases. Similarly, the L80 grade 13Cr stainless steel is not considered a suitable choice for harsh environments rich in H2S, CO2, and Cl at superheated temperatures. While it was prone to localized corrosion, it exhibited a low uniform corrosion rate (<0.1 mm/year).
Picture for How Informative is Your Annual CP Survey Potential Data? - A Statistical Analysis
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How Informative is Your Annual CP Survey Potential Data? - A Statistical Analysis

Product Number: 51324-21219-SG
Author: Thomas Hayden; Len Krissa; Keith Parker; Cedar Osmond
Publication Date: 2024
$40.00
In the United States, gas and hazardous liquid pipelines are regulated by Section 49 of the Code of Federal Regulations, Parts 192 and 195 respectively. It is in these regulations where guidance for the location and frequency is required to “have sufficient test stations or other contact points for electrical measurement to determine the adequacy of cathodic protection.” Historically, many operators in the United States have placed test stations at typically a 1-to-3-mile interval to demonstrate compliance with the associated regulations. A statistical analysis was performed on the annual test station data on multiple pipelines to show how meaningful this data is towards understanding the overall cathodic protection effectiveness. The priority of CP application needs to be from a corrosion prevention perspective rather than one driven strictly by regulatory compliance.
Picture for External Chloride Stress Corrosion Cracking (Cl-SCC) of Valve Bonnet 304 Austenitic Stainless Steel Stud Bolts
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External Chloride Stress Corrosion Cracking (Cl-SCC) of Valve Bonnet 304 Austenitic Stainless Steel Stud Bolts

Product Number: 51324-21176-SG
Author: Iyad Al-Buraiki; Mohammed Abu Alsaud; Yousif AlRabie
Publication Date: 2024
$40.00
Chloride stress corrosion cracking (Cl-SCC) is known to occur in austenitic stainless steels operating at temperatures above 60 °C (150 °F). This paper, however, will discuss external Cl-SCC failures that occurred at ambient conditions. These failures occurred in stainless steel grade 304 bolts used as valve bonnet stud bolts. The failure caused total disengagement of the valve bonnet. These valves were located approximately 1 km from the seashore. In addition, the valves were located underneath a seawater deluge system used for fire protection which was periodically tested resulting in the valves being wetted by seawater. This paper provides details related to the materials, environmental conditions and mechanical properties of these bolts and provides recommendations to avoid such failures in the future.
Picture for Premature Corrosion Attack of Stainless Steel Pipes and Welds
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Premature Corrosion Attack of Stainless Steel Pipes and Welds

Product Number: 51324-20325-SG
Author: Hussain H. AlMahamedh; Ali H. AlShawaf
Publication Date: 2024
$40.00
Newly constructed Stainless Steel Pipes experienced multiple leaks during commissioning. The different sizes pipe were constructed of 316L and 304L stainless steel at one of the Saudi Basic Industries Corporation (SABIC) affiliates. A failure investigation was performed to identify the root cause of the leaks. Samples were cut out of the pipes for analytical study. Scanning Electron Microscopy (SEM) coupled with Energy Dispersive Spectroscopy (EDS) was used to study the corrosion damage morphology and the chemical compositions of the corrosion products. Cross sectional samples, out of the pipes, were prepared for Metallographic examinations. XRF (X-Ray Fluorescence Spectrometry) and carbon/sulfur analyzer was used to identify the chemical composition of the pipes material. The failure investigation suggests that, improper welding, mothballing and lay-up of the piping network after hydrotesting promoted Microbiologically Influenced Corrosion (MIC).

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