The Experts below are selected from a list of 318 Experts worldwide ranked by ideXlab platform
Shabbir Safri - One of the best experts on this subject based on the ideXlab platform.
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Internal Corrosion Management of Crude Pipelines
Volume 2: Pipeline Integrity Management, 2014Co-Authors: Surya Prakash, Shabbir Safri, Abdul Razzaq Al-shamari, Amer JaraghAbstract:Kuwait currently produces about 3 million barrels of crude oil per day and has a large pipeline network system for handling its oil and associated products (condensate, low pressure and high pressure gas, as well as produced and effluent waters). The total length of the pipeline network is about 4790 Km consisting of API 5L Grade-B carbon steel ranging in diameter from 100 mm to 1830 mm. The Kuwait Oil Company (KOC) is responsible for the Corrosion and integrity management of the pipeline network system which involves: Internal Corrosion Monitoring to assess the Internal Corrosion status of the pipelines including the occurrence of microbial influenced Corrosion; external Corrosion protection with the help of coatings and cathodic protection, and periodic intelligent and cleaning pigging operations for Internal Corrosion assessment and cleaning.The present paper focuses on the Internal Corrosion management of the export crude segment of the pipeline network system which is very important for a healthy economy. The Internal Corrosion monitoring protocol includes, online Corrosion monitoring, cleaning pigging and intelligent pigging. Bacteria counts’ trending is also included as part of protocol. Some anomalies between the results obtained from Corrosion trends, cleaning pigging results and intelligent pigging are highlighted and a sound engineering explanation is attempted to explain these apparent anomalies.Copyright © 2014 by ASME
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Two Contrasting Internal Corrosion Scenarios Assessed by Liquid Petroleum–Internal Corrosion Direct Assessment (LP-ICDA) for the Innovative Development of a Dynamic Pitting Factor
Volume 2: Pipeline Integrity Management, 2012Co-Authors: Patrick J. Teevens, Zhenjin Zhu, Ashish Khera, Abdul Wahab Al-mithin, Shabbir SafriAbstract:This paper details the complete four-step Liquid Petroleum - Internal Corrosion Direct Assessment (LP-ICDA) for two operationally different liquid petroleum pipeline systems owned by Kuwait Oil Company. The Internal Corrosion pipeline wall metal losses were originally predicted using a uniform pitting factor and subsequently upgraded by a dynamic pitting factor. The first case evaluated three, 1959 vintage, non-piggable 40″/38″ telescopic export crude oil pipelines (CR102, CR103 and CR104) with individual corresponding parallel run lengths of 7.7km. All three pipelines run parallel to each other in a common corridor. They are gravity-fed from a storage tank farm resulting in a moderate fluid transit operating velocity. The second assessment was performed on a 6.5 year-old, piggable 36″ crude oil production pipeline (CR088) with an overall distance of 25 kilometers. During the Pre-assessment step, pipeline historical and operational data were collected. Limited historical data was available for the 3 non-piggable pipelines compared to the newer 36″ pipeline which was ultrasonically (UT) inspected via in-line inspection (ILI). In the Indirect Inspection step, the proprietary Internal Corrosion predictive model (ICPM), enpICDATM, was applied with a uniform pitting factor to predict the amount of degradation at those locations where liquid hold-up, solids accumulation, and in-turn the Internal metal losses would be most pronounced. During the Detailed Examination step, “in-the-ditch” UT was utilized to measure and confirm the remaining wall thicknesses of the three gravity pipelines whereas a comparison of the ICPM to the ILI was executed for the newer 36″ × 25km pipeline. In the Post-Assessment step, a comparison between the predicted metal losses and the UT-ILI measured data were carried out. As a result of a gap analysis, dynamic pitting factors were proposed and developed to enhance and update the proprietary model for predicting the metal losses point-by-point within each subregion over the entire pipeline in terms of local pressure, temperature, water accumulation, and solids deposition. Validation of the in-house prediction was performed using the field measurements for gravity pipelines and ILI data for CR088, demonstrating that metal losses predicted by the proprietary model and measured through field tests and ILI data agree reasonably well for both extreme scenarios. Results showed that three gravity pipelines have minimal Internal Corrosion under a high flow velocity despite having a 51-year operating history whereas severe Internal Corrosion was identified after a 6.5-year operation for the CR088 pipeline. Hence, selection of a proper operating velocity is crucial for crude oil pipeline operations. Under a low speed condition, localized pitting Corrosion dominates whereas uniform Corrosion is predominant under a higher flow or “sweep” velocity. Since the pipeline operators were more interested in the worst-case scenarios, i.e. metal loss due to localized pitting Corrosion, development of dynamic pitting factors was undoubtedly an innovative improvement of the overall Liquid Petroleum - Internal Corrosion Direct Assessment through capturing the fluctuation of metal losses along the entire pipeline, which can enhance the ICDA methodology toward a higher level of precision and accuracy.Copyright © 2012 by ASME
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two contrasting Internal Corrosion scenarios assessed by liquid petroleum Internal Corrosion direct assessment lp icda for the innovative development of a dynamic pitting factor
2012 9th International Pipeline Conference, 2012Co-Authors: Patrick J. Teevens, Zhenjin Zhu, Ashish Khera, Abdul Wahab Almithin, Shabbir SafriAbstract:This paper details the complete four-step Liquid Petroleum - Internal Corrosion Direct Assessment (LP-ICDA) for two operationally different liquid petroleum pipeline systems owned by Kuwait Oil Company. The Internal Corrosion pipeline wall metal losses were originally predicted using a uniform pitting factor and subsequently upgraded by a dynamic pitting factor. The first case evaluated three, 1959 vintage, non-piggable 40″/38″ telescopic export crude oil pipelines (CR102, CR103 and CR104) with individual corresponding parallel run lengths of 7.7km. All three pipelines run parallel to each other in a common corridor. They are gravity-fed from a storage tank farm resulting in a moderate fluid transit operating velocity. The second assessment was performed on a 6.5 year-old, piggable 36″ crude oil production pipeline (CR088) with an overall distance of 25 kilometers. During the Pre-assessment step, pipeline historical and operational data were collected. Limited historical data was available for the 3 non-piggable pipelines compared to the newer 36″ pipeline which was ultrasonically (UT) inspected via in-line inspection (ILI). In the Indirect Inspection step, the proprietary Internal Corrosion predictive model (ICPM), enpICDATM, was applied with a uniform pitting factor to predict the amount of degradation at those locations where liquid hold-up, solids accumulation, and in-turn the Internal metal losses would be most pronounced. During the Detailed Examination step, “in-the-ditch” UT was utilized to measure and confirm the remaining wall thicknesses of the three gravity pipelines whereas a comparison of the ICPM to the ILI was executed for the newer 36″ × 25km pipeline. In the Post-Assessment step, a comparison between the predicted metal losses and the UT-ILI measured data were carried out. As a result of a gap analysis, dynamic pitting factors were proposed and developed to enhance and update the proprietary model for predicting the metal losses point-by-point within each subregion over the entire pipeline in terms of local pressure, temperature, water accumulation, and solids deposition. Validation of the in-house prediction was performed using the field measurements for gravity pipelines and ILI data for CR088, demonstrating that metal losses predicted by the proprietary model and measured through field tests and ILI data agree reasonably well for both extreme scenarios. Results showed that three gravity pipelines have minimal Internal Corrosion under a high flow velocity despite having a 51-year operating history whereas severe Internal Corrosion was identified after a 6.5-year operation for the CR088 pipeline. Hence, selection of a proper operating velocity is crucial for crude oil pipeline operations. Under a low speed condition, localized pitting Corrosion dominates whereas uniform Corrosion is predominant under a higher flow or “sweep” velocity. Since the pipeline operators were more interested in the worst-case scenarios, i.e. metal loss due to localized pitting Corrosion, development of dynamic pitting factors was undoubtedly an innovative improvement of the overall Liquid Petroleum - Internal Corrosion Direct Assessment through capturing the fluctuation of metal losses along the entire pipeline, which can enhance the ICDA methodology toward a higher level of precision and accuracy.Copyright © 2012 by ASME
Ashish Khera - One of the best experts on this subject based on the ideXlab platform.
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Internal Corrosion Predicted and Found in Refined Piggable Product Pipeline Through ICDA
ASME 2017 India Oil and Gas Pipeline Conference, 2017Co-Authors: Ashish Khera, Bidyut B. BaniahAbstract:Contaminants such as CO2, H2S and O2 in liquid and gas pipelines in the presence of water create an aggressive environment conducive to Internal Corrosion. During pipeline operations, solids deposition, water accumulation, bacterial activities and improper chemical inhibition aggravate the Internal Corrosion attack. For assessing the threat of Internal Corrosion the industry has only three integrity validation tools at its disposal. These are Pressure Testing, In Line Inspection (ILI) and Internal Corrosion Direct Assessment (ICDA). To enhance pipeline integrity for piggable and non-piggable pipelines, NACE International published a variety of Standard Practices for the ICDA protocols for predicting time-dependent Internal Corrosion threats for various products in both offshore and onshore in sweet or sour service. All ICDA protocols are a structured, iterative integrity assessment process, consisting of the following four steps: Pre-assessment, Indirect Inspection, Detailed Examination and Post-assessment. Most importantly, unlike ILI and pressure testing, all ICDA standards require a mandatory root cause analysis and a go forward mitigation plan to arrest the Corrosion processes being encountered. This paper reviews one case study; LP-ICDA for three (3) “piggable” refined product pipelines from the Jetty to the onshore marketing terminal. This paper will be useful for the pipeline operators to provide guidance on not only identifying the locations at which Internal Corrosion activity has occurred but also look into how the operators used the ICDA program to better manage their asset.
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Internal Corrosion Direct Assessment for Hydrocarbon Service Petroleum Pipelines
ASME 2013 India Oil and Gas Pipeline Conference, 2013Co-Authors: Patrick J. Teevens, Ashish Khera, Zhenjin ZhuAbstract:Contaminants such as CO2, H2S and O2 in water-wet liquid and gas pipelines create an aggressive environment conducive to facilitating Internal Corrosion. During pipeline operations, solids deposition, water accumulation, bacterial activities and improper chemical inhibition aggravate the Internal Corrosion attack. For assessing the threat of Internal Corrosion, the petroleum industry currently has only three integrity validation tools at its disposal. These are Pressure Testing, In-line Inspection (ILI) and Internal Corrosion Direct Assessment (ICDA). To enhance pipeline integrity for piggable and non-piggable pipelines, NACE International has developed and published a variety of industry consensus Standard Practices for the ICDA protocols to predict time-dependent Internal Corrosion threats for various petroleum products in both offshore and onshore under sweet or sour environments. These NACE International ICDA Standards include:• SP0206-2006 “ICDA Methodology for Pipelines Carrying Normally Dry Natural Gas (DG-ICDA)”[1]• SP0208-2008 “ICDA Methodology for Liquid Petroleum Pipelines (LP-ICDA)”[2]• SP0110-2010 “Wet Gas ICDA Methodology for Pipelines (WG-ICDA)”[3]• Multiphase flow (MP-ICDA) is under development with TG-426 and will be released in 2013.• Process Piping (PP-ECDA, Above Ground) is in its early stages of development with the release not likely before 2015.• Process Piping (PP-ECDA, Buried) is in its early stages of development with the release not likely before 2015.• Process Piping (PP-ICDA) for various service environments is in its early stages of development with the release not likely before 2015.All ICDA protocols are a structured, iterative integrity assessment process, consisting of the following four steps: Preassessment, Indirect Inspection, Detailed Examination and Postassessment. Most importantly, unlike ILI and pressure testing, all the ICDA standards require a mandatory root cause analysis and a go forward mitigation plan to arrest the Corrosion processes being encountered. This paper reviews the following case studies: LP-ICDA for a crude oil pipeline and WG-ICDA for a high pressure gas pipeline with free water and condensate. ICDA is applicable for dry gas systems too but due to limiting length of this paper, the dry gas case study is not detailed. This paper will be useful for the pipeline operators to provide guidance in identifying locations at which Corrosion activity has occurred, is occurring, or may likely occur in the future under a series of pre-defined operating conditions.Copyright © 2013 by ASME
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Two Contrasting Internal Corrosion Scenarios Assessed by Liquid Petroleum–Internal Corrosion Direct Assessment (LP-ICDA) for the Innovative Development of a Dynamic Pitting Factor
Volume 2: Pipeline Integrity Management, 2012Co-Authors: Patrick J. Teevens, Zhenjin Zhu, Ashish Khera, Abdul Wahab Al-mithin, Shabbir SafriAbstract:This paper details the complete four-step Liquid Petroleum - Internal Corrosion Direct Assessment (LP-ICDA) for two operationally different liquid petroleum pipeline systems owned by Kuwait Oil Company. The Internal Corrosion pipeline wall metal losses were originally predicted using a uniform pitting factor and subsequently upgraded by a dynamic pitting factor. The first case evaluated three, 1959 vintage, non-piggable 40″/38″ telescopic export crude oil pipelines (CR102, CR103 and CR104) with individual corresponding parallel run lengths of 7.7km. All three pipelines run parallel to each other in a common corridor. They are gravity-fed from a storage tank farm resulting in a moderate fluid transit operating velocity. The second assessment was performed on a 6.5 year-old, piggable 36″ crude oil production pipeline (CR088) with an overall distance of 25 kilometers. During the Pre-assessment step, pipeline historical and operational data were collected. Limited historical data was available for the 3 non-piggable pipelines compared to the newer 36″ pipeline which was ultrasonically (UT) inspected via in-line inspection (ILI). In the Indirect Inspection step, the proprietary Internal Corrosion predictive model (ICPM), enpICDATM, was applied with a uniform pitting factor to predict the amount of degradation at those locations where liquid hold-up, solids accumulation, and in-turn the Internal metal losses would be most pronounced. During the Detailed Examination step, “in-the-ditch” UT was utilized to measure and confirm the remaining wall thicknesses of the three gravity pipelines whereas a comparison of the ICPM to the ILI was executed for the newer 36″ × 25km pipeline. In the Post-Assessment step, a comparison between the predicted metal losses and the UT-ILI measured data were carried out. As a result of a gap analysis, dynamic pitting factors were proposed and developed to enhance and update the proprietary model for predicting the metal losses point-by-point within each subregion over the entire pipeline in terms of local pressure, temperature, water accumulation, and solids deposition. Validation of the in-house prediction was performed using the field measurements for gravity pipelines and ILI data for CR088, demonstrating that metal losses predicted by the proprietary model and measured through field tests and ILI data agree reasonably well for both extreme scenarios. Results showed that three gravity pipelines have minimal Internal Corrosion under a high flow velocity despite having a 51-year operating history whereas severe Internal Corrosion was identified after a 6.5-year operation for the CR088 pipeline. Hence, selection of a proper operating velocity is crucial for crude oil pipeline operations. Under a low speed condition, localized pitting Corrosion dominates whereas uniform Corrosion is predominant under a higher flow or “sweep” velocity. Since the pipeline operators were more interested in the worst-case scenarios, i.e. metal loss due to localized pitting Corrosion, development of dynamic pitting factors was undoubtedly an innovative improvement of the overall Liquid Petroleum - Internal Corrosion Direct Assessment through capturing the fluctuation of metal losses along the entire pipeline, which can enhance the ICDA methodology toward a higher level of precision and accuracy.Copyright © 2012 by ASME
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two contrasting Internal Corrosion scenarios assessed by liquid petroleum Internal Corrosion direct assessment lp icda for the innovative development of a dynamic pitting factor
2012 9th International Pipeline Conference, 2012Co-Authors: Patrick J. Teevens, Zhenjin Zhu, Ashish Khera, Abdul Wahab Almithin, Shabbir SafriAbstract:This paper details the complete four-step Liquid Petroleum - Internal Corrosion Direct Assessment (LP-ICDA) for two operationally different liquid petroleum pipeline systems owned by Kuwait Oil Company. The Internal Corrosion pipeline wall metal losses were originally predicted using a uniform pitting factor and subsequently upgraded by a dynamic pitting factor. The first case evaluated three, 1959 vintage, non-piggable 40″/38″ telescopic export crude oil pipelines (CR102, CR103 and CR104) with individual corresponding parallel run lengths of 7.7km. All three pipelines run parallel to each other in a common corridor. They are gravity-fed from a storage tank farm resulting in a moderate fluid transit operating velocity. The second assessment was performed on a 6.5 year-old, piggable 36″ crude oil production pipeline (CR088) with an overall distance of 25 kilometers. During the Pre-assessment step, pipeline historical and operational data were collected. Limited historical data was available for the 3 non-piggable pipelines compared to the newer 36″ pipeline which was ultrasonically (UT) inspected via in-line inspection (ILI). In the Indirect Inspection step, the proprietary Internal Corrosion predictive model (ICPM), enpICDATM, was applied with a uniform pitting factor to predict the amount of degradation at those locations where liquid hold-up, solids accumulation, and in-turn the Internal metal losses would be most pronounced. During the Detailed Examination step, “in-the-ditch” UT was utilized to measure and confirm the remaining wall thicknesses of the three gravity pipelines whereas a comparison of the ICPM to the ILI was executed for the newer 36″ × 25km pipeline. In the Post-Assessment step, a comparison between the predicted metal losses and the UT-ILI measured data were carried out. As a result of a gap analysis, dynamic pitting factors were proposed and developed to enhance and update the proprietary model for predicting the metal losses point-by-point within each subregion over the entire pipeline in terms of local pressure, temperature, water accumulation, and solids deposition. Validation of the in-house prediction was performed using the field measurements for gravity pipelines and ILI data for CR088, demonstrating that metal losses predicted by the proprietary model and measured through field tests and ILI data agree reasonably well for both extreme scenarios. Results showed that three gravity pipelines have minimal Internal Corrosion under a high flow velocity despite having a 51-year operating history whereas severe Internal Corrosion was identified after a 6.5-year operation for the CR088 pipeline. Hence, selection of a proper operating velocity is crucial for crude oil pipeline operations. Under a low speed condition, localized pitting Corrosion dominates whereas uniform Corrosion is predominant under a higher flow or “sweep” velocity. Since the pipeline operators were more interested in the worst-case scenarios, i.e. metal loss due to localized pitting Corrosion, development of dynamic pitting factors was undoubtedly an innovative improvement of the overall Liquid Petroleum - Internal Corrosion Direct Assessment through capturing the fluctuation of metal losses along the entire pipeline, which can enhance the ICDA methodology toward a higher level of precision and accuracy.Copyright © 2012 by ASME
Alfredo Viloria - One of the best experts on this subject based on the ideXlab platform.
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Internal Corrosion studies in hydrocarbons production pipelines located at Venezuelan Northeastern
Chemical Engineering Research and Design, 2012Co-Authors: José Biomorgi, Samuel Hernández, Jairo Marín, Erik Rodríguez, Milton Lara, Alfredo ViloriaAbstract:Abstract The demand of fossil energy has boosted the construction of new oil facilities and the preservation of the physical and mechanical integrity of the already existing infrastructure. Corrosion is the main causes of failures in the hydrocarbons industry and half of them are produced by acid gases (CO2 and H2S) ( Kermany and Harrop, 1996 ). Within this framework, a monitoring device was developed by PDVSA-Intevep, in order to study the Internal Corrosion mechanism in a real hydrocarbons production system. The results show the advantages offered by this tool, which allowed studying thoroughly the Internal Corrosion mechanism present in the system and their immediate causes. In this case, the main Corrosion mechanism present is under deposit Corrosion, which causes pitting damage at different positions along the pipeline. According to microscopic analyses, the pitting are related to the presence of sand and solids (iron carbonates and sulphides); and the location of the damage depends basically on the Internal diameter of pipelines (the hydrodynamics of the system).
Kevin C. Garrity - One of the best experts on this subject based on the ideXlab platform.
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External Corrosion and Internal Corrosion Direct Assessment Validation Project
2004 International Pipeline Conference Volumes 1 2 and 3, 2004Co-Authors: Carl A. Mikkola, Christina L. Case, Kevin C. GarrityAbstract:In January, 2003, Enbridge Midcoast Energy, L.P., a subsidiary of Enbridge Energy Partners, L.P., implemented a comprehensive direct assessment development and validation project for its Natural Gas Business segment; a project intended to demonstrate the validity of External Corrosion and Internal Corrosion Direct Assessment (ECDA and ICDA). The work began in January 2003 and was concluded in June 2003. The primary goal of the project was to demonstrate that External Corrosion Direct Assessment and Internal Corrosion Direct Assessment as performed in compliance with the NACE and INGAA methodologies could be used to effectively verify and manage the integrity of non-piggable and non-interruptible natural gas pipeline segments. The programs were validated by in-line inspection (ILI) using high-resolution magnetic flux leakage tools and field verification digs. The objective of the project was to receive approval from the Texas Railroad Commission to use direct assessment (“DA”), where demonstrated to be appropriate, for integrity verification and management of pipeline systems that are not verifiable through other approved means. The Enbridge DA Validation Project was successfully completed and is considered to be one of the leading DA validation projects undertaken to date in the U.S. A total of 12,000 manhours and over $1MM was expended in performing the pre-assessment to identify a candidate pipeline, develop detailed procedures for DA execution and implementation, perform indirect surveys, modify pipe and complete cleaning pig runs, gauge pig runs, dummy pig runs, intelligent pig runs, perform detailed direct examinations and perform detailed analysis of the results including the preparation of the final report. This paper is intended to describe the steps that Enbridge took in validating DA.
Patrick J. Teevens - One of the best experts on this subject based on the ideXlab platform.
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Internal Corrosion Direct Assessment for Hydrocarbon Service Petroleum Pipelines
ASME 2013 India Oil and Gas Pipeline Conference, 2013Co-Authors: Patrick J. Teevens, Ashish Khera, Zhenjin ZhuAbstract:Contaminants such as CO2, H2S and O2 in water-wet liquid and gas pipelines create an aggressive environment conducive to facilitating Internal Corrosion. During pipeline operations, solids deposition, water accumulation, bacterial activities and improper chemical inhibition aggravate the Internal Corrosion attack. For assessing the threat of Internal Corrosion, the petroleum industry currently has only three integrity validation tools at its disposal. These are Pressure Testing, In-line Inspection (ILI) and Internal Corrosion Direct Assessment (ICDA). To enhance pipeline integrity for piggable and non-piggable pipelines, NACE International has developed and published a variety of industry consensus Standard Practices for the ICDA protocols to predict time-dependent Internal Corrosion threats for various petroleum products in both offshore and onshore under sweet or sour environments. These NACE International ICDA Standards include:• SP0206-2006 “ICDA Methodology for Pipelines Carrying Normally Dry Natural Gas (DG-ICDA)”[1]• SP0208-2008 “ICDA Methodology for Liquid Petroleum Pipelines (LP-ICDA)”[2]• SP0110-2010 “Wet Gas ICDA Methodology for Pipelines (WG-ICDA)”[3]• Multiphase flow (MP-ICDA) is under development with TG-426 and will be released in 2013.• Process Piping (PP-ECDA, Above Ground) is in its early stages of development with the release not likely before 2015.• Process Piping (PP-ECDA, Buried) is in its early stages of development with the release not likely before 2015.• Process Piping (PP-ICDA) for various service environments is in its early stages of development with the release not likely before 2015.All ICDA protocols are a structured, iterative integrity assessment process, consisting of the following four steps: Preassessment, Indirect Inspection, Detailed Examination and Postassessment. Most importantly, unlike ILI and pressure testing, all the ICDA standards require a mandatory root cause analysis and a go forward mitigation plan to arrest the Corrosion processes being encountered. This paper reviews the following case studies: LP-ICDA for a crude oil pipeline and WG-ICDA for a high pressure gas pipeline with free water and condensate. ICDA is applicable for dry gas systems too but due to limiting length of this paper, the dry gas case study is not detailed. This paper will be useful for the pipeline operators to provide guidance in identifying locations at which Corrosion activity has occurred, is occurring, or may likely occur in the future under a series of pre-defined operating conditions.Copyright © 2013 by ASME
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Two Contrasting Internal Corrosion Scenarios Assessed by Liquid Petroleum–Internal Corrosion Direct Assessment (LP-ICDA) for the Innovative Development of a Dynamic Pitting Factor
Volume 2: Pipeline Integrity Management, 2012Co-Authors: Patrick J. Teevens, Zhenjin Zhu, Ashish Khera, Abdul Wahab Al-mithin, Shabbir SafriAbstract:This paper details the complete four-step Liquid Petroleum - Internal Corrosion Direct Assessment (LP-ICDA) for two operationally different liquid petroleum pipeline systems owned by Kuwait Oil Company. The Internal Corrosion pipeline wall metal losses were originally predicted using a uniform pitting factor and subsequently upgraded by a dynamic pitting factor. The first case evaluated three, 1959 vintage, non-piggable 40″/38″ telescopic export crude oil pipelines (CR102, CR103 and CR104) with individual corresponding parallel run lengths of 7.7km. All three pipelines run parallel to each other in a common corridor. They are gravity-fed from a storage tank farm resulting in a moderate fluid transit operating velocity. The second assessment was performed on a 6.5 year-old, piggable 36″ crude oil production pipeline (CR088) with an overall distance of 25 kilometers. During the Pre-assessment step, pipeline historical and operational data were collected. Limited historical data was available for the 3 non-piggable pipelines compared to the newer 36″ pipeline which was ultrasonically (UT) inspected via in-line inspection (ILI). In the Indirect Inspection step, the proprietary Internal Corrosion predictive model (ICPM), enpICDATM, was applied with a uniform pitting factor to predict the amount of degradation at those locations where liquid hold-up, solids accumulation, and in-turn the Internal metal losses would be most pronounced. During the Detailed Examination step, “in-the-ditch” UT was utilized to measure and confirm the remaining wall thicknesses of the three gravity pipelines whereas a comparison of the ICPM to the ILI was executed for the newer 36″ × 25km pipeline. In the Post-Assessment step, a comparison between the predicted metal losses and the UT-ILI measured data were carried out. As a result of a gap analysis, dynamic pitting factors were proposed and developed to enhance and update the proprietary model for predicting the metal losses point-by-point within each subregion over the entire pipeline in terms of local pressure, temperature, water accumulation, and solids deposition. Validation of the in-house prediction was performed using the field measurements for gravity pipelines and ILI data for CR088, demonstrating that metal losses predicted by the proprietary model and measured through field tests and ILI data agree reasonably well for both extreme scenarios. Results showed that three gravity pipelines have minimal Internal Corrosion under a high flow velocity despite having a 51-year operating history whereas severe Internal Corrosion was identified after a 6.5-year operation for the CR088 pipeline. Hence, selection of a proper operating velocity is crucial for crude oil pipeline operations. Under a low speed condition, localized pitting Corrosion dominates whereas uniform Corrosion is predominant under a higher flow or “sweep” velocity. Since the pipeline operators were more interested in the worst-case scenarios, i.e. metal loss due to localized pitting Corrosion, development of dynamic pitting factors was undoubtedly an innovative improvement of the overall Liquid Petroleum - Internal Corrosion Direct Assessment through capturing the fluctuation of metal losses along the entire pipeline, which can enhance the ICDA methodology toward a higher level of precision and accuracy.Copyright © 2012 by ASME
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two contrasting Internal Corrosion scenarios assessed by liquid petroleum Internal Corrosion direct assessment lp icda for the innovative development of a dynamic pitting factor
2012 9th International Pipeline Conference, 2012Co-Authors: Patrick J. Teevens, Zhenjin Zhu, Ashish Khera, Abdul Wahab Almithin, Shabbir SafriAbstract:This paper details the complete four-step Liquid Petroleum - Internal Corrosion Direct Assessment (LP-ICDA) for two operationally different liquid petroleum pipeline systems owned by Kuwait Oil Company. The Internal Corrosion pipeline wall metal losses were originally predicted using a uniform pitting factor and subsequently upgraded by a dynamic pitting factor. The first case evaluated three, 1959 vintage, non-piggable 40″/38″ telescopic export crude oil pipelines (CR102, CR103 and CR104) with individual corresponding parallel run lengths of 7.7km. All three pipelines run parallel to each other in a common corridor. They are gravity-fed from a storage tank farm resulting in a moderate fluid transit operating velocity. The second assessment was performed on a 6.5 year-old, piggable 36″ crude oil production pipeline (CR088) with an overall distance of 25 kilometers. During the Pre-assessment step, pipeline historical and operational data were collected. Limited historical data was available for the 3 non-piggable pipelines compared to the newer 36″ pipeline which was ultrasonically (UT) inspected via in-line inspection (ILI). In the Indirect Inspection step, the proprietary Internal Corrosion predictive model (ICPM), enpICDATM, was applied with a uniform pitting factor to predict the amount of degradation at those locations where liquid hold-up, solids accumulation, and in-turn the Internal metal losses would be most pronounced. During the Detailed Examination step, “in-the-ditch” UT was utilized to measure and confirm the remaining wall thicknesses of the three gravity pipelines whereas a comparison of the ICPM to the ILI was executed for the newer 36″ × 25km pipeline. In the Post-Assessment step, a comparison between the predicted metal losses and the UT-ILI measured data were carried out. As a result of a gap analysis, dynamic pitting factors were proposed and developed to enhance and update the proprietary model for predicting the metal losses point-by-point within each subregion over the entire pipeline in terms of local pressure, temperature, water accumulation, and solids deposition. Validation of the in-house prediction was performed using the field measurements for gravity pipelines and ILI data for CR088, demonstrating that metal losses predicted by the proprietary model and measured through field tests and ILI data agree reasonably well for both extreme scenarios. Results showed that three gravity pipelines have minimal Internal Corrosion under a high flow velocity despite having a 51-year operating history whereas severe Internal Corrosion was identified after a 6.5-year operation for the CR088 pipeline. Hence, selection of a proper operating velocity is crucial for crude oil pipeline operations. Under a low speed condition, localized pitting Corrosion dominates whereas uniform Corrosion is predominant under a higher flow or “sweep” velocity. Since the pipeline operators were more interested in the worst-case scenarios, i.e. metal loss due to localized pitting Corrosion, development of dynamic pitting factors was undoubtedly an innovative improvement of the overall Liquid Petroleum - Internal Corrosion Direct Assessment through capturing the fluctuation of metal losses along the entire pipeline, which can enhance the ICDA methodology toward a higher level of precision and accuracy.Copyright © 2012 by ASME
