Remote Monitoring of Pitting Corrosion Using a Next Generation Electric Field Mapping (EFM) System

2008 ◽  
Author(s):  
Eric Kubian ◽  
Andrew Vorozcovs ◽  
Sam Cauchi
Keyword(s):  
Electric Field ◽  
Monitoring System ◽  
Wall Thickness ◽  
Pitting Corrosion ◽  
Corrosion Monitoring ◽  
Worst Case ◽  
Internal Corrosion ◽  
Field Mapping ◽  
Corrosion Rates ◽  
Area Of Interest

Pitting corrosion is one of the most serious problems in sour gas / oil pipelines and in crude oil refineries. Unlike generalized wall loss, pitting corrosion can grow at non-uniform rates and can rapidly proceed to full depth penetration. Such a loss of integrity can lead to leaks that cause production shutdowns, environmental damage, or in the worst case, loss of life. In practice, pitting corrosion is generally detected during pipeline inline inspection or during routine ultrasound scans undertaken as part of a maintenance program. Locations identified to exhibit pitting corrosion are then often risk ranked, and then either repaired or monitored depending on a variety of factors. Unfortunately, the sites where this type of corrosion frequently occurs are often inaccessible for frequent follow-up wall thickness inspections due to geographical remoteness or the need to the use of scaffolding to reach the site. This difficulty creates a need for an advanced internal corrosion monitoring system capable of remotely monitoring the progression of pitting corrosion. This paper describes a new pitting corrosion monitoring system based on the principal of Electric Field Mapping (EFM) and proceeds to describe recent results from an operational field installation of this technology. Using this technique, remaining wall thickness is carefully mapped out within a pre-defined area of interest. The system indicates the presence of any generalized corrosion in addition to the location, width, and depth of individual pitting corrosion defects. Innovations of this new EFM system include the use of a robust pre-fabricated fiberglass shell that significantly reduces the installation time compared to earlier technologies; non-welded contacts that have minimal metallurgical impact; permanent, self-powered on-site data acquisition system equipped with cellular or satellite data communication. Design principles of this technique are discussed, and installation procedures are outlined. Results are presented from a field site where pitting corrosion is being monitored on an ongoing basis. Background information on the installation, in addition to project goals and observations are reported. Daily wall thickness data obtained remotely from the site is used to report individual corrosion rates for pitting defects within the pipeline. These corrosion rates are then plotted over time and correlated to events such as process upsets, chemical inhibitor application, cleaning pig runs, and other actions intended to mitigate for internal corrosion. This correlation provides data which is then subsequently used to improve the corrosion mitigation program in place, and better schedule maintenance activities.

Remote Monitoring Digitizes Asset-Integrity Management

2021 ◽  
Vol 73 (01) ◽  
pp. 65-66
Author(s):  
Chris Carpenter
Keyword(s):  
Real Time ◽  
Monitoring System ◽  
Wall Thickness ◽  
Remote Monitoring ◽  
Ultrasonic Transducer ◽  
Abu Dhabi ◽  
Corrosion Monitoring ◽  
Electric Pulses ◽  
Ultrasonic Sound ◽  
Integrity Management

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 197168, “Digitalize Asset-Integrity Management by Remote Monitoring,” by Mohamed Sahid, ADNOC, prepared for the 2019 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 11-14 November. The paper has not been peer reviewed. Monitoring of corrosion in process pipelines has always been of paramount importance in ensuring plant-asset integrity. Similarly, steam traps play an important role in ensuring steam quality and, thus, the integrity of critical assets in the plant. The complete paper discusses these two aspects of monitoring asset integrity - real-time corrosion monitoring and real-time steam-trap monitoring - as implemented by the operator. The authors highlight the importance of digitization by means of implementing wireless technology and making data available in remote work stations in real time. Real-Time Corrosion-Monitoring System Corrosion coupons and electrical resistance probes are among the most-tried and -tested methods to monitor corrosion, but the authors detail shortcomings of these systems, focusing their efforts on the option of using nonintrusive ultrasonic sensors for corrosion monitoring. Fixed ultrasonic thickness (UT) monitoring systems measure a localized thickness of vessel wall or pipe through the use of sound waves. They are the fastest method to measure wall thickness and wall loss reliably. The wall thickness is calculated from the reflection of the ultrasonic signal at both external and internal surfaces. UT systems normally include a transducer and a pulser/receiver. The type of transducer used for this application is the ultrasonic transducer, which can be either piezoelectric or variable-capacitive. The pulser generates short electric pulses of energy at a constant rate, which are converted by the transducer into short, high-frequency ultrasonic sound pulses. These pulses are then directed into the material. Any discontinuation or impurity in the path of the ultrasonic sound wave will be reflected and received by the transducer, transformed into an electric signal, and amplified by the receiver to be projected onto the display (in the case of portable UT instruments). Depending on the intensity shown on the display, information about the impurity or discontinuity, such as size, orientation, and location, can be derived accurately. The shortcomings of using portable UT sensors have been overcome by the introduction of permanent UT sensors, which provide wall-thickness measurement continuously at one location in real time. Because these sensors remain fixed at one location for years, it is possible to analyze corrosion at a single point over time, thus detecting early corrosion onset. Real-Time UT Gauging. The operator installed the real-time corrosion-monitoring system in its offshore associated gas (OAG) unit. A UK-based vendor provided UT sensors along with data-management and -viewing software to support data interpretation. Twenty locations were identified in various plants of the OAG unit on the basis of criticality and previously recorded corrosion levels.

Internal Corrosion Monitoring System Selection for Cross Country Natural Gas Pipeline: A Case Study of SHPPL

2015 ◽  
Author(s):  
Sandeep Vyas
Keyword(s):  
Natural Gas ◽  
Monitoring System ◽  
Gas Pipeline ◽  
Operating Conditions ◽  
Corrosion Monitoring ◽  
Compressor Station ◽  
Internal Corrosion ◽  
Monitoring Techniques ◽  
Natural Gas Pipeline ◽  
Pipeline Project

Reliance Gas Pipelines Limited (RGPL) is currently implementing a gas pipeline project from Shahdol, Madhya Pradesh to Phulpur, Uttar Pradesh for evacuation of gas produced from Coal Bed Methane (CBM) blocks owned by Reliance Industries Ltd. This pipeline will be hooked up with GAIL’s HVJ Pipeline at Phulpur. Over all Pipeline system includes 312 km (approx.) long trunk line, and associated facilities such as Compressor Station at Shahdol, Intermediate Pigging facilities, Metering & Regulating facilities at Phulpur and 12 No. Mainline valve stations. Gas produced from CBM blocks will be dehydrated within Gas Gathering Station facilities of CBM Project located upstream of pipeline Compressor station at Shahdol. Gas received at pipeline battery limit is dry and non-corrosive gas in nature, Internal corrosion is not expected in normal course of operation, however internal corrosion of the natural gas pipeline can occur when the pipe wall is exposed to moisture and other contaminants either under process upset conditions or under particular operating conditions. Even though internal corrosion is not expected during normal course of operations, to take care of any eventuality, it is proposed to implement Internal Corrosion Monitoring (ICMS) system in this project. ICMS will provide an efficient and reliable means of continuous monitoring internal corrosion. Internal Corrosion Monitoring (ICMS) system is used as a part of overall integrity management framework; to achieve two objectives viz., verify the corrosive behaviour of gas and to verify the efficacy of applied preventive actions. Philosophy involved in evaluating a suitable CM technique would include : • Applicable corrosion damage mechanisms, anticipated corrosion rates and probable locations. • Suitable CM technique and location based on process condition, system corrosivity, water content, pigging facilities, available corrosion allowance, design life, maintenance etc., • Measurement frequency. Some of the Corrosion Monitoring techniques used for pipeline and of relevance are: • Weight-loss Corrosion Coupons (CC), • Electrical Resistance probes (ER), • Linear Polarization Resistance Probe (LPR) • Ultrasonic Thickness Measurement (UT) • Sampling Points (SP) This paper discusses the merits / demerits of these corrosion monitoring techniques, considerations for selecting a specific technique for the Shahdol – Phulpur Gas Pipeline Project and highlights the implementation of the internal corrosion monitoring system.

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 ◽  
Author(s):  
Patrick J. Teevens ◽  
Zhenjin Zhu ◽  
Ashish Khera ◽  
Abdul Wahab Al-Mithin ◽  
Shabbir Safri
Keyword(s):  
Crude Oil ◽  
Pitting Corrosion ◽  
Metal Loss ◽  
Uniform Corrosion ◽  
Local Pressure ◽  
Worst Case ◽  
Internal Corrosion ◽  
Oil Pipeline ◽  
Direct Assessment ◽  
First Case

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.

Water treatment to reduce internal corrosion in the drinking water distribution system in Oslo

2001 ◽  
Vol 1 (3) ◽  
pp. 91-96 ◽  
Author(s):  
L.J. Hem ◽  
E.A. Vik ◽  
A. Bjørnson-Langen
Keyword(s):  
Water Treatment ◽  
Corrosion Rate ◽  
Distribution System ◽  
Water Distribution ◽  
Treatment Plant ◽  
Water Treatment Plant ◽  
Corrosion Monitoring ◽  
Copper Corrosion ◽  
Iron Corrosion ◽  
Internal Corrosion

In 1995 the new Skullerud water treatment plant was put into operation. The new water treatment includes colour removal and corrosion control with an increase of pH, alkalinity and calcium concentration in addition to the old treatment, which included straining and chlorination only. Comparative measurements of internal corrosion were conducted before and after the installation of the new treatment plant. The effect of the new water treatment on the internal corrosion was approximately a 20% reduction in iron corrosion and a 70% reduction in copper corrosion. The heavy metals content in standing water was reduced by approximately 90%. A separate internal corrosion monitoring programme was conducted, studying the effects of other water qualities on the internal corrosion rate. Corrosion coupons were exposed to the different water qualities for nine months. The results showed that the best protection of iron was achieved with water supersaturated with calcium carbonate. Neither a high content of free carbon dioxide or the use of the corrosion inhibitor sodium silicate significantly reduced the iron corrosion rate compared to the present treated water quality. The copper corrosion rate was mainly related to the pH in the water.

Measuring Rates and Impact of Corrosion on DOD Equipment

2008 ◽  
Vol 38 ◽  
pp. 163-181 ◽  
Author(s):  
Sean Morefield ◽  
Susan Drozdz ◽  
Vincent F. Hock ◽  
William Abbott
Keyword(s):  
Air Force ◽  
Atmospheric Corrosion ◽  
Large Scale ◽  
Coast Guard ◽  
Weather Data ◽  
Corrosion Monitoring ◽  
Open Structure ◽  
Corrosion Rates ◽  
Monitoring Test ◽  
Environmental Severity

A large scale atmospheric corrosion monitoring test was undertaken for the purpose of characterizing environmental severity. This work was conducted at ground based Army, Navy, Coast Guard, and Air Force sites. At present over 73 sites are in operation. This work adds to the existing worldwide databases to include new military and/or related sites not previously monitored. In addition and to the extent that such data are available, relevant weather data was collected from public or military sources in order to test existing corrosion algorithms for each site. Many of the 1 year exposures have been successfully completed. However, all of the exposures currently in progress will not be completed until early 2008. Sample analyses are in progress. New data have been obtained to show the important effects of sheltering on reducing corrosion rates. Data from Daytona Beach and Tyndall AFB show that even a relatively simple open structure/sunshade can reduce corrosion rates by factors of 2 or 3. New data are being reported on corrosion vs. distance from ocean. Data were also collected for the comparison of corrosion severity among commonly used test sites and within selected sites (multiple locations within a base.)

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