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3228 total products found.
Picture for Digital Twin as a Tool for Extending In-Line Inspection Intervals
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Digital Twin as a Tool for Extending In-Line Inspection Intervals

Product Number: 51324-20824-SG
Author: Keith Parker; Yanping Li; Christophe Baete; Victoria Chum; Trey Johnston
Publication Date: 2024
$40.00

Aging pipeline assets are a concern for many pipeline operators. As pipelines age, external corrosion control becomes more challenging and often results in more aggressive monitoring and maintenance activities such as more frequent in-line inspections (ILI) and direct examinations. A pipeline case study is discussed demonstrating how a digital twin based on mechanistic modeling was utilized as a proof of concept for identifying possible cathodic protection remedial actions to decrease external corrosion growth rates (CGR) with the goal of extending the ILI inspection interval from 3 to 5 years. Various remediations such as adjusting or adding cathodic protection and resolving interference are modeled and compared with the existing corrosion control configuration. An economic analysis is included to determine if theoretical remediations can reduce monitoring and maintenance costs while maintaining asset integrity.
NoP Commerce Standards image
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SSPC-SP 1-2016, Solvent Cleaning

Product Number: SSPC-SP 1-2016
Publication Date: 2016
$109.00
Picture for An Exploratory Investigation of the Cracking Susceptibility of Three Corrosion Resistant Alloys under Thermal Cycles and Conditions Exceeding the Traditional NACE MR0175/ISO 15156 Recommendations
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An Exploratory Investigation of the Cracking Susceptibility of Three Corrosion Resistant Alloys under Thermal Cycles and Conditions Exceeding the Traditional NACE MR0175/ISO 15156 Recommendations

Product Number: 51324-20455-SG
Author: Manuel Marya
Publication Date: 2024
$40.00
The environmentally-assisted cracking (EAC) of three wrought corrosion-resistant alloys (CRAs) with a minimum yield strength of 110ksi (760MPa) was investigated between 70°F (21°C) and 450°F (232°C) through weekly thermal cycles totalizing 42 days. The thermal cycling was introduced to approximate service equipment conditions and gain additional confidence on the EAC-free limits of all three CRAs. Alloys 17-4PH, K-500, and 925 were selected and exposed to a 180,000-ppm NaCl brine (pH=2.75) in equilibrium with 1000 psi (68.95 bar) H2S, 1000 psi (68.95 bar) CO2, and 2500 psi (172.37 bar) CH4. All three CRAs were (a) acquired as per the NACE MR0175/ISO 1516 requirements (1), (b) tested as per NACE TM0177 Method C at 30-to-90% of the CRA minimum specified minimum yield strength (SMYS), and (c) also compared for their weight-loss corrosion and localized corrosion. The results show: (a) Alloy 17-4PH remains resistant to EAC below 45% of its SMYS, (b) Alloy K-500 resists cracking at an estimated 80% of its SMYS, but uniformly corrodes by sulfide conversion under film at a rate of 64 mpy (1.63 mm/yr.), and (c) Alloy 925 continues to be immune to EAC at 90% of its SMYS. Alloy 17-4PH also corroded at a rate of 22.8 mpy (0.58 mm/yr.) in comparison to only 0.6 mpy (15.2 mm/yr.) for Alloy 925, with no CRA showing experiencing crevice corrosion.
Picture for Redefining Corrosion Resistance Requirements for Austenitic Stainless Steels used in Drilling Applications – Part 2: CrNi-Stainless Steels
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Redefining Corrosion Resistance Requirements for Austenitic Stainless Steels used in Drilling Applications – Part 2: CrNi-Stainless Steels

Product Number: 51323-19277-SG
Author: Julia Ditmann, Helmuth Sarmiento Klapper, Thomas Williams, Bernd Holper, Krutibas Panda, Reece Goldsberry, Wendy Martin, Daryl McIntyre, Clara Herrera, Merlin Seifert
Publication Date: 2023
$20.00

Pitting and environmentally assisted cracking (EAC) are a major concern when austenitic CrMn-stainless steels, which are commonly used for non-magnetic drill collars (NMCD), are exposed to high halide-containing drilling fluids. Even though the fast propagation of environmentally assisted cracks can partially be controlled by the introduction of compressive residual stresses, surface treatments are not intended to address localized corrosion resistance. In fact, it has been demonstrated that CrMn-stainless steels become prone to pitting corrosion when exposed to high Cl- streams at elevated temperature, which ultimately can also lead to stress corrosion cracking (SCC) when sufficient stresses are present.
Picture for Effect of Curing Time on the Performance of Novolac Internal Tank Coatings - a Realistic Assessment Using Laboratory Testing
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Effect of Curing Time on the Performance of Novolac Internal Tank Coatings - a Realistic Assessment Using Laboratory Testing

Product Number: 51324-20588-SG
Author: Amal Al-Borno; Moavin Islam; A. Al Hashem; Hasan Sabri
Publication Date: 2024
$40.00
Novolac coating systems are widely used for internal applications in tanks and pressure vessels due to their excellent corrosion resistance under aggressive conditions, their availability, and ease of application. Typically, these coatings require a curing time before putting the coating into service is typically around 7-8 days at (at 20-25o C). During the vessel shutdown, the production schedule sometimes demands compromising the curing process of the lining. This puts a time constraint on the end-user in terms of coating project duration. In response to this challenge, a major oil producing company was interested in finding out if shorter curing times would be suitable to reduce the downtime. The main objective of this study was to conduct a detailed laboratory investigation on the effect of different curing times on the coating performance of four Novolac systems selected from three different manufacturers. The assessment of coating curing involved a series of tests, including Differential Scanning Calorimetry (DSC) and Attenuated Total Reflectance Fourier Transform Infrared Spectroscopy (ATR-FTIR) analyses, shore-D Hardness, X-cut adhesion, and pull-off adhesion tests. Additionally, standard laboratory coating performance tests were carried out, consisting of water immersion, cathodic disbondment, autoclave in multi-phase environments at elevated pressure and temperature, as well as atlas cell (cold-wall effect) tests. The investigation results demonstrated that even though the coatings were not fully cured, all four coating systems showed acceptable laboratory performance, after just 1 day of curing. This implies that these coatings may be put into service much earlier than the specified curing period of manufacturer which would significantly reduce the project downtime during maintenance. Subsequent field test results (not reported here) confirmed the laboratory findings.
Picture for A New Biocide Enhancer for a Better Pipeline Treatment
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A New Biocide Enhancer for a Better Pipeline Treatment

Product Number: 51324-20576-SG
Author: Nik Nor Azrizam Nik Norizam; Hasrizal A Rahman; Azmi Mohammed Nor
Publication Date: 2024
$40.00
Biocide Enhancer (BioMETT) is a PETRONAS in-house chemical technology developed by PETRONAS Research Sdn Bhd (PRSB). BioMETT development took place back in 2015 where PRSB started to develop a biocide enhancer formulation that could enhance and boost up further the efficacy of current Tetrakis(hydroxymethyl)phosphonium Sulfate (THPS) biocide used by operation in mitigating corrosion problem inside crude oil pipelines due to Microbial Induced Corrosion (MIC). PRSB continued to test out the formulation in the actual offshore field environment where the BioMETT technology was piloted in two separate fields namely field A and B. The purpose of the pilot is to evaluate further the effectiveness of BioMETT formulation (a mixture of THPS and enhancer) in reducing the current biocide dosage injection between 30% to 40% at both pipelines while still showing the same efficacy as that of existing dosage in maintaining the acceptable low Sulfate Reducing Bacteria (SRB) count reading of <10 cfu/ml. Feasibility study was conducted to ensure the enhancer do not cause any corrosively effect to the pipeline on its own or when mixing with THPS. Furthermore, the mixture was also compatible with other oilfield chemicals and did not cause physical problems such as foaming and emulsion. Upon completion of the pilot, the results obtained showed a successful reduction of 30% in the biocide dosage, translated into 30% reduction in the biocide injection cost per every operational pigging (OP).
Picture for Impact of Different Carbon Sources on dsrAB Gene, a Major Concern for Oil and Gas Industries
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Impact of Different Carbon Sources on dsrAB Gene, a Major Concern for Oil and Gas Industries

Product Number: 51324-20602-SG
Author: Luiz André Lucas Teixeira Pinto; Vinícius Ribeiro Flores; Diogo Azevedo Coutinho; Walter Barreiro Cravo Junior
Publication Date: 2024
$40.00
Corrosion induced by microorganisms is an already known fact that affects, among other heavy industries, the oil and gas sector. Its understanding and deep knowledge can avoid material and physical damage to those involved in the related processes. Molecular tools may help to mitigate these possible damages; however, studies are needed to understand molecular mechanisms involving microbial activity, especially the transcription of important enzymes such as sulfite reductase (dsrAB) which may be involved inthe corrosive process. mRNA extraction and cDNA synthesis were performed to quantify gene expression. Also, the enzyme production quantification by molecular techniques and H2S analysis were conducted to check dissolved gas concentration through potentiometric titration. It was possible to infer that availability of carbon sources and its complexity may increase bacterial metabolic activity, especially in the presence of lactate that, in this study, showed an increase in gene expression and H2S production compared to a variety of carbon sources and a control sample.
Picture for Effect of CO in Stress Corrosion Cracking of Carbon Steel Pipelines in CCS Environments
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Effect of CO in Stress Corrosion Cracking of Carbon Steel Pipelines in CCS Environments

Product Number: 51324-20647-SG
Author: Gaoxiang (Garret) Wu; Jose Rafael Vera; Ken Evans; Chong Li; William Kovacs
Publication Date: 2024
$40.00
Carbon monoxide (CO) is one of various possible impurities in carbon capture and storage (CCS) streams. As a by-product of the methane reforming process to produce blue hydrogen, CO is combusted and converted to carbon dioxide (CO2) and transported in pipelines. However, a trace amount of CO in the presence of oxygen (O2) and water can cause stress corrosion cracking (SCC) in carbon steel pipelines. This paper assesses the SCC risk of carbon steels induced by CO at different concentrations with or without O2 in lab simulated dense phase CO2 environments. Electrochemical measurements were also conducted to reveal the pseudo-passive behavior of carbon steels in different CO/O2/CO2 systems, and to help understand the resultant SCC behaviors.
Picture for Predicting Corrosion of Successive Feeds in Distilling Units - An Experimental Approach
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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.
Picture for Investigating Fatigue Crack Growth Rate of Ferritic Steels in High Pressure Hydrogen Gas
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Investigating Fatigue Crack Growth Rate of Ferritic Steels in High Pressure Hydrogen Gas

Product Number: 51324-20692-SG
Author: P. Bortot; M. Ortolani; M. Bellingardi; C. San Marchi; J. Ronevich
Publication Date: 2024
$40.00
Fatigue crack growth rate (FGCR) is essential knowledge for the design of high-pressure hydrogen storage vessels, which are subject to repeated pressurization and depressurization cycles. High strength, low alloy steels are widely used for this application. However, these materials are known to be sensitive to hydrogen assisted cracking, meaning their crack growth rate under repeated cycles of pressurization and depressurization is significantly enhanced due to the interaction of hydrogen gas with the metal, compared to an inert environment. This work reviews existing literature on commonly used low alloy, quenched and tempered (Q&T) steels. Additionally, recently generated data on very high strength low alloy grades, as well as low carbon, low alloy, weldable steels are presented in comparison. These results illustrate common trends and similarities for FCGR in hydrogen gas and discuss differences in alloy design and manufacturing process parameters affecting materials performance in the target environment.
Picture for Development of High Strength Material with 140KSI SMYS for Sour Service
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Development of High Strength Material with 140KSI SMYS for Sour Service

Product Number: 51324-20720-SG
Author: Hiroki Kamitani; Keiichi Kondo; Yuji Arai; Hisashi Amaya
Publication Date: 2024
$40.00
Development of oil and gas wells becomes more challenging due to high pressure, high temperature HPHT and sour service environment. At the current status, industries have commercialized sour service materials with up to 125ksi SMYS for mildly sour service. To realize 140ksi SMYS materials with SSC resistance at ambient temperatures, it should be needed to balance mechanical properties and corrosion resistance. In order to achieve 140ksi SMYS strength and corrosion resistance in a mildly sour environment (0.01bar H2S, pH=3.5), authors modify and adjust the amount of elements improving SSC resistance, such as chromium and molybdenum. SSC tests per NACE TM0177 Method A proved superior corrosion resistance under 90% actual YS. Furthermore, limitation in partial pressure of H2S and pH was also examined and this material is acceptable for the part of SSC region 2 in accordance with NACE MR0175/ISO 15156-2 at ambient temperatures.
Picture for Qualification Methods of Seamless Tubes for H2 Gas Applications
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Qualification Methods of Seamless Tubes for H2 Gas Applications

Product Number: 51324-20737-SG
Author: Florian Thebault; Vincent Designolle
Publication Date: 2024
$40.00
Sour service is frequently perceived as an appropriate material selection by default for high pressure hydrogen service. So a documented review of sour versus hydrogen gas charging is given, in terms of their respective hydrogen fugacities, hydrogen sources, surface states and crack tip blunting. This global view is susceptible to affect the selection of the test methodology for material qualification. Constant displacement and step loading fracture mechanics tests were performed on an OCTG K55 at room temperature and 100 bar of H2 gas. Results differ with the test method, which was found to be linked to the steepness of the crack growth resistance curve.

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