Internal Corrosion Monitoring Experience in a Multi-Product Pipeline of Oil India Limited - A Case Study

2014 ◽  
Author(s):  
Subodh Purohit ◽  
Pulak Sarma ◽  
Mool Chand Nihalani
Keyword(s):  
Corrosion Monitoring ◽  
Internal Corrosion ◽  
Product Pipeline

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.

ANALYSIS OF THE USE OF ULTRASONIC TESTING METHODS IN THE FRAMEWORK OF CORROSION MONITORING OF INTERNAL CORROSION AT GAS PRODUCTION FACILITIES IN THE PRESENCE OF CARBON DIOXIDE

2020 ◽  
pp. 30-35
Author(s):  
D. N. Zapevalov ◽  
R. K. Vagapov
Keyword(s):  
Carbon Dioxide ◽  
Oil And Gas ◽  
Thickness Measurement ◽  
Gas Production ◽  
Corrosion Monitoring ◽  
Internal Corrosion ◽  
Ultrasonic Methods ◽  
Ultrasonic Thickness Measurement ◽  
Gas Fields ◽  
Production Facilities

The use of various intrusive and non-intrusive methods of corrosion monitoring makes it possible to assess the corrosion situation and the effectiveness of the applied corrosion protection agents in conditions of internal corrosion at gas production facilities due to the presence of aggressive gases. The analysis of the application of ultrasonic testing methods as part of corrosion monitoring of internal corrosion at gas production facilities in the presence of corrosive components is carried out. Ultrasonic thickness measurement is widely used as a non-intrusive method for monitoring internal corrosion and detecting corrosion defects in promising gas fields. Many gas fields (Bovanenkovskoye oil and gas condensate field, Urengoy oil and gas field and others) revealed corrosion defects due to cases of internal corrosion due to the presence of increased amounts of carbon dioxide in the produced hydrocarbons. Under conditions of corrosion in the presence of carbon dioxide, ultrasonic methods for measuring the thickness of a metal have certain limitations associated with the unpredictable local nature of carbon dioxide corrosion, which should be considered when used in gas facilities. The main method for measuring thickness under operational conditions is ultrasonic thickness measurement, which is used in conjunction with radiographic monitoring. Using these two main non-intrusive methods, corrosion monitoring monitors the thinning of the metal, the size and depth of local defects and the dynamics of their change over time. Based on the results of measuring the residual wall thickness of the pipe and equipment, the possibility of their further work is determined, and recommendations are made on extending the safe life of gas facilities. The authors analyzed the literature data on new options and technical solutions for the use of ultrasonic methods in the measurement of the thickness of a metal surface.

Internal Corrosion Monitoring of Subsea Production Flowlines - Probe Design, Testing, and Operational Results

1999 ◽  
Author(s):  
M.W. Joosten ◽  
J. Kolts ◽  
P.G. Humble ◽  
D.M. Keilty ◽  
T.J. Blakset ◽  
...  
Keyword(s):  
Probe Design ◽  
Corrosion Monitoring ◽  
Internal Corrosion

scholarly journals Fire-Side Corrosion: A Case Study of Failed Tubes of a Fossil Fuel Boiler

2017 ◽  
Vol 2017 ◽  
pp. 1-8
Author(s):  
Majid Asnavandi ◽  
Mohaddeseh Kahram ◽  
Milad Rezaei ◽  
Davar Rezakhani
Keyword(s):  
Power Plant ◽  
Critical Points ◽  
Fossil Fuel ◽  
Corrosion Behaviour ◽  
Combustion Products ◽  
Metal Loss ◽  
Corrosion Monitoring ◽  
Boiler Tubes ◽  
Conventional Models

The failures of superheater and reheater boiler tubes operating in a power plant utilizing natural gas or mazut as a fuel have been analysed and the fire-side corrosion has been suggested as the main reason for the failure in boiler tubes. The tubes have been provided by a fossil fuel power plant in Iran and optical and electron microscopy investigations have been performed on the tubes as well as the corrosion products on their surfaces. The results showed that the thickness of the failed tubes is not uniform which suggests that fire-side corrosion has happened on the tubes. Fire-side corrosion is caused by the reaction of combustion products with oxide layers on the tube surface resulting in metal loss and consequently tubes fracture. However, the tubes corrosion behaviour did not follow the conventional models of the fire-side corrosion. Given that, using the corrosion monitoring techniques for these boiler tubes seems essential. As a result, the thickness of the boiler tubes in different parts of the boiler has been recorded and critical points are selected accordingly. Such critical points are selected for installation of corrosion monitoring probes.

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.

Chemical injection policy for internal corrosion prevention of South Pars sea-pipeline: A case study

2014 ◽  
Vol 21 ◽  
pp. 592-599 ◽  
Author(s):  
Mehdi Davoudi ◽  
Yashar Heidari ◽  
Alireza Safadoost ◽  
Saeed Samieirad
Keyword(s):  
Corrosion Prevention ◽  
Internal Corrosion

Corrosion Detection in Pipes by Piezoelectric Sensors Using Artificial Neural Network

2011 ◽  
Vol 403-408 ◽  
pp. 748-752
Author(s):  
Hamed Rafezi ◽  
Behnood Rahmani
Keyword(s):  
Neural Network ◽  
Artificial Neural Network ◽  
Vinylidene Fluoride ◽  
Detection System ◽  
Oil And Gas Industry ◽  
Corrosion Monitoring ◽  
Corrosion Condition ◽  
Internal Corrosion ◽  
Corrosion Detection ◽  
Artificial Neural

Defect detection in pipes is an essential task specially for sensitive applications such as oil and gas industry where special cares are required. Corrosion is a common defect in pipes which has attracted attention of researchers. In present work a non-destructive methodology for pipe corrosion monitoring is introduced. Polymer of Vinylidene Fluoride (PVDF) Piezoelectric is used as the sensor to measure strain variations affected by internal corrosion. High sensitivity and low cost of piezoelectric materials made them a good candidate for precise industrial applications. Different corrosion conditions (i.e. corrosion location along pipe and corrosion depth) are modeled and sensors voltages in different corrosion conditions are simulated. Finally in order to develop an effective corrosion detection system, an Artificial Neural Network (ANN) is designed to recognize position and amount of corrosion according to sensors voltages. The ANN performed corrosion condition recognition with 91 % of accuracy. This method provides the capability of online implementation for continuous maintenance of pipelines.

Internal Corrosion Predicted and Found in Refined Piggable Product Pipeline Through ICDA

2017 ◽  
Author(s):  
Ashish Khera ◽  
Bidyut B. Baniah
Keyword(s):  
Detailed Examination ◽  
Assessment Process ◽  
Internal Corrosion ◽  
Integrity Assessment ◽  
Pressure Testing ◽  
Root Cause ◽  
Water Accumulation ◽  
Standard Practices ◽  
Sour Service

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.

scholarly journals Evaluation of non-intrusive systems for internal corrosion monitoring

2017 ◽  
Vol 1 (6) ◽  
Author(s):  
Victor G. Silva ◽  
Gustavo L. Vaz ◽  
Pedro A. Ferreira ◽  
Anna Ramus Moreira ◽  
Neusvaldo L. de Almeida
Keyword(s):  
Corrosion Monitoring ◽  
Internal Corrosion

scholarly journals Life Prediction of Crude Oil Pipeline to Mitigate Leakages: A Case Study of an NPDC Major Pipeline in OML30, Nigeria

2021 ◽  
Author(s):  
Henry Freedom Ifowodo ◽  
Chinedum Ogonna Mgbemena ◽  
Christopher Okechukwu Izelu
Keyword(s):  
Crude Oil ◽  
Oil And Gas ◽  
Gas Field ◽  
Internal Corrosion ◽  
Oil Pipeline ◽  
Oil And Gas Field ◽  
Pipeline Failure ◽  
Pipeline Failures ◽  
Major Pipeline

Abstract Pipeline leak or failure is a dreaded event in the oil and gas industries. Top events such as catastrophes and multiple fatalities have occurred in the past due to pipeline leak or failure especially when loss of contents was met with fire incidents. It is therefore imperative that the causes of pipeline failure are tackled to prevent or mitigate leak incidents. This is expedient to curb the menace that goes with leak incidents, such as destruction of the environment and ecosystem; loss of assets, finance, lives and property; dangers to workers and personnel, production downtime, litigation and dent to company’s reputation. This work focuses on the investigation of the actual cause of sudden pipeline failures and frequent pipeline leaks that often result to sectional pipeline replacement before the expiration of their anticipated life cycle in OML30 oil and gas field. The pipeline material selected, the standard of the minimum wall thickness of the material, the corrosive nature of the pipeline content and the observed internal corrosion rate were probed. An analysis of the rate of thinning and diminution of the internal wall of the pipeline by monitoring the interior rate of corrosion was used to forecast the remaining life of a crude oil pipeline and predict the life expectancy of a newly replaced or installed pipeline or installed pipeline.

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