Remnant Life Estimation of Pipelines With Internal Corrosion

2008 ◽  
Author(s):  
Tim Illson ◽  
Clive Ward ◽  
Vinod Chauhan ◽  
Michael Gardiner
Keyword(s):  
Corrosion Rate ◽  
Time Frame ◽  
Pipeline System ◽  
Degradation Mechanisms ◽  
Original Design ◽  
Design Data ◽  
Internal Corrosion ◽  
Well Production ◽  
Advantages And Disadvantages ◽  
Corrosion Rates

Situations can arise where the condition of a pipeline system is poorly known. This may be due to a variety of operational or commercial reasons. Failures will eventually occur if time dependent degradation mechanisms are active. While an appropriate response may be to inspect or hydrotest, this is generally not feasible within a short time frame and integrity assessments or replacements must therefore be prioritized. This paper looks at an ageing upstream pipeline system subject to internal corrosion. A case study is presented in which a system approaching its original design life is required to carry fluids from reservoirs now forecast to be productive for another 50 years. Fluids include sweet or sour gas, crude oil and injection water. Design data are available but inspection information is sparse with less than 10% of lines inspected by ILI; coupon data and well production forecasts are available. The challenge was to prioritize line replacements according to the remnant life of each pipeline, based on the limited available data. Current condition was measured for lines where ILI data were available. A corrosion risk assessment was conducted to identify credible degradation mechanisms. The pipelines were then grouped according to the fluids being transported. This enabled an estimate of current condition for all pipelines based upon the limited inspection and coupon data. In order to predict the remnant life it was necessary to estimate the future corrosion rates, again for all lines. A number of approaches could be used for estimating future corrosion rates. These include basing the rates on historical inspection data or using corrosion modeling techniques. The paper describes a hybrid method that synthesises these two approaches to allow a corrosion rate distribution to be postulated for calculating remnant life. In addition, the options for future corrosion rate estimation are described and the advantages and disadvantages of each one discussed.

Monitoring X65 Steel Internal Corrosion in Humidified N2 containing H2S using Membrane-based Electrochemical Sensors

CORROSION ◽  
10.5006/3454 ◽  
2021 ◽  
Author(s):  
Timothy Duffy ◽  
Derek Hall ◽  
Margaret Ziomek-Moroz ◽  
Serguei Lvov
Keyword(s):  
Relative Humidity ◽  
Natural Gas ◽  
Corrosion Rate ◽  
Electrochemical Sensors ◽  
Element Analysis ◽  
Internal Corrosion ◽  
Natural Gas Pipelines ◽  
Corrosion Rates ◽  
Order Of Magnitude ◽  
X65 Steel

We report here on a new membrane-based electrochemical sensor (MBES) that may provide an important utility in monitoring and characterizing internal corrosion of natural gas pipelines. Using this sensor, we have measured the corrosion rate of X65 steel exposed to H2S in humidified environments up to 60 °C. Consistent with our earlier CO2 study, the membrane’s conductivity did not change when exposed to H2S-contaning acidic gas. Introducing H2S consistently increased the measured corrosion rate between testing conditions, though corrosion rates were typically less than 2 μm y-1. At 30 °C, the corrosion rate doubled from 7.3 to 14 nm y-1 below a relative humidity of 30 %, and increased by an order of magnitude (0.19 μm y-1 to 1.9 μm y-1) at 55 % relative humidity, showing that the influence of H2S on corrosion increases dramatically with larger humidity. Trends with relative humidity match industry expectations: corrosion rate is low (<0.25 μm y-1) without the presence of a condensed aqueous phase, but increases as the water content of the system increases. The MBES was therefore able to captures relevant corrosion trends, even while the corrosion rates would not have presented a serious threat to any natural gas pipeline. As such, the MBES can be used to detect the onset of emerging corrosion threats before they occur. Field emission scanning electron microscopy and energy-dispersive X-ray spectroscopy confirmed that H2S reacted with the metal covered by the membrane phase, showing evidence of sulfur-rich sites on the X65 surface. In addition, finite element analysis confirmed that electrochemical measurements and data analysis techniques could be successfully used for this membrane-based sensor, despite its unconventional cell geometry.

Predicting Corrosion Rates for Onshore Oil and Gas Pipelines

2006 ◽  
Author(s):  
J. M. Race ◽  
S. J. Dawson ◽  
L. Stanley ◽  
S. Kariyawasam
Keyword(s):  
Corrosion Rate ◽  
Growth Rates ◽  
Oil And Gas ◽  
Cost Effective ◽  
Management Plan ◽  
Assessment Method ◽  
Internal Corrosion ◽  
Corrosion Rates ◽  
External Corrosion ◽  
Comparison Of The Results

One of the requirements of a comprehensive pipeline Integrity Management Plan (IMP) is the establishment of safe and cost effective re-assessment intervals for the chosen assessment method, either Direct Assessment (DA), In-Line Inspection (ILI) or hydrotesting. For pipelines where the major threat is external or internal corrosion, the determination of an appropriate re-inspection interval requires the estimation of realistic corrosion growth rates. The Office of Pipeline Safety (OPS 2005) estimate that the ability to accurately estimate corrosion rates may save pipeline companies more than $100M/year through reduced maintenance and accident avoidance costs. Unlike internal corrosion, which occurs in a closed system, the rate of the external corrosion reaction is influenced by a number of factors including the water content of the soil, the soluble salts present, the pH of the corrosion environment and the degree of oxygenation. Therefore the prediction of external rates is complex and there is currently no method for estimating corrosion rates using either empirical or mechanistic equations. This paper describes a scoring model that has been developed to estimate external corrosion growth rates for pipelines where rates cannot be estimated using more conventional methods i.e., from repeat in-line inspection data. The model considers the effect of the different variables that contribute to external corrosion and ranks them according to their effect on corrosion growth rate to produce a corrosion rate score. The resulting score is then linked to a corrosion rate database to obtain an estimated corrosion rate. The methodology has been validated by linking the calculated corrosion rate scores to known corrosion rate distributions that have been measured by comparison of the results from multiple in-line inspection runs. The paper goes on to illustrate how the estimated corrosion rates can be used for the establishment of reassessment intervals for DA, ILI and hydrotesting, comparing the benefits of this approach with current industry recommended practice and guidance.

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.

Integrity Assessment of Non-Piggable Pipeline Through Direct Assessment

2013 ◽  
Author(s):  
Jai Prakash Sah ◽  
Mohammad Tanweer Akhter
Keyword(s):  
Hydrostatic Pressure ◽  
Natural Gas ◽  
Stress Corrosion ◽  
Health Assessment ◽  
Assessment Method ◽  
Pipeline System ◽  
Internal Corrosion ◽  
Integrity Assessment ◽  
Direct Assessment ◽  
External Corrosion

Managing the integrity of pipeline system is the primary goal of every pipeline operator. To ensure the integrity of pipeline system, its health assessment is very important and critical for ensuring safety of environment, human resources and its assets. In long term, managing pipeline integrity is an investment to asset protection which ultimately results in cost saving. Typically, the health assessment to managing the integrity of pipeline system is a function of operational experience and corporate philosophy. There is no single approach that can provide the best solution for all pipeline system. Only a comprehensive, systematic and integrated integrity management program provides the means to improve the safety of pipeline systems. Such programme provides the information for an operator to effectively allocate resources for appropriate prevention, detection and mitigation activities that will result in improved safety and a reduction in the number of incidents. Presently GAIL (INDIA) LTD. is operating & maintaining approximately 10,000Kms of natural gas/RLNG/LPG pipeline and HVJ Pipeline is the largest pipeline network of India which transports more than 50% of total gas being consumed in this country. HVJ pipeline system consists of more than 4500 Kms of pipeline having diameter range from 04” to 48”, which consist of piggable as well as non-piggable pipeline. Though, lengthwise non-piggable pipeline is very less but their importance cannot be ignored in to the totality because of their critical nature. Typically, pipeline with small length & connected to dispatch terminal are non-piggable and these pipelines are used to feed the gas to the consumer. Today pipeline industries are having three different types of inspection techniques available for inspection of the pipeline. 1. Inline inspection 2. Hydrostatic pressure testing 3. Direct assessment (DA) Inline inspection is possible only for piggable pipeline i.e. pipeline with facilities of pig launching & receiving and hydrostatic pressure testing is not possible for the pipeline under continuous operation. Thus we are left with direct assessment method to assess health of the non-piggable pipelines. Basically, direct assessment is a structured multi-step evaluation method to examine and identify the potential problem areas relating to internal corrosion, external corrosion, and stress corrosion cracking using ICDA (Internal Corrosion Direct Assessment), ECDA (External Corrosion Direct Assessment) and SCCDA (Stress Corrosion Direct Assessment). All the above DA is four steps iterative method & consist of following steps; a. Pre assessment b. Indirect assessment c. Direct assessment d. Post assessment Considering the importance of non-piggable pipeline, integrity assessment of following non piggable pipeline has done through direct assessment method. 1. 30 inch dia pipeline of length 0.6 km and handling 18.4 MMSCMD of natural gas 2. 18 inch dia pipeline of length 3.65 km and handling 4.0 MMSCMD of natural gas 3. 12 inch dia pipeline of length 2.08 km and handling 3.4 MMSCMD of natural gas In addition to ICDA, ECDA & SCCDA, Long Range Ultrasonic Thickness (LRUT-a guided wave technology) has also been carried out to detect the metal loss at excavated locations observed by ICDA & ECDA. Direct assessment survey for above pipelines has been conducted and based on the survey; high consequence areas have been identified. All the high consequence area has been excavated and inspected. No appreciable corrosion and thickness loss have observed at any area. However, pipeline segments have been identified which are most vulnerable and may have corrosion in future.

Internal Corrosion Direct Assessment for Pipelines Carrying Wet Gas - Methodology

2004 ◽  
Author(s):  
Oliver Moghissi ◽  
Deanna Burwell ◽  
Rick Eckert ◽  
Jose Vera ◽  
Narasi Sridhar ◽  
...  
Keyword(s):  
Corrosion Rate ◽  
Flow Regimes ◽  
Distribution Model ◽  
Liquid Volume ◽  
Internal Corrosion ◽  
Integrity Verification ◽  
Direct Assessment ◽  
Wet Gas ◽  
Pipeline Segment ◽  
Flow Effects

An Internal Corrosion Direct Assessment methodology is proposed for wet gas pipelines (WG-ICDA). Wet gas systems (i.e., those normally containing liquids) include storage and gathering systems with large gas-to-liquid volume ratios. Wet gas systems are not well represented by ICDA for normally dry gas, and existing corrosion models applied to wet gas systems are not sufficiently targeted at integrity verification. The essential focus of WG-ICDA compared to other internal corrosion models is the discrimination of conditions along the length of a pipeline so that possible local integrity threats with respect to internal corrosion are identified and mitigated. The basis of WG-ICDA is to prioritize locations along a pipeline segment by factors of traditional corrosion rate, flow effects, and other influencing factors. Corrosion rate depends on gas quality, liquid chemistry, pressure, and temperature. The corrosion rate can be normalized because WG-ICDA as integrity verification only concerns itself with corrosion distribution (i.e., the location along a pipeline segment where corrosion is more severe than other locations). Flow effects include possible flow regimes and the presence of water from condensation (at locations of heat loss). Expected possible flow regimes are stratified, slugging, and annular. The final term captures other factors influencing corrosion rate distribution. These factors include corrosion inhibition (batch and continuous, solubility and dispersibility in hydrocarbon and aqueous phases), biocide treatments, hydrocarbon condensates (including emulsion characteristics), maintenance pigging, bacteria, solids/scale, and other products. WG-ICDA follows the same four-step process as all other Direct Assessment (DA) methods: 1) Pre-Assessment: Data is collected, a feasibility analysis is performed, and the pipeline segment is divided into regions. 2) Indirect Inspections: Measurements are taken or calculations are performed to prioritize locations along a particular pipeline segment for susceptibility to corrosion. For WG-ICDA, the factors contributing to the distribution of corrosion will be included and an initial assumption about corrosion distribution will be made. WG-ICDA is sufficiently flexible to allow the use of existing wet gas models within the framework of the overall process. 3) Direct (or Detailed) Examinations: The pipe is excavated and examined at locations prioritized to have the highest likelihood of corrosion. The examination must have sufficient detail to determine the existence, extent, and severity of corrosion. Examination of the internal surface of a pipe can involve non-destructive examination methods sufficient to identify and characterize internal defects. 4) Post-Assessment: Analysis of the indirect and direct examination data is performed to determine overall pipeline integrity, prioritize repairs, and set the interval for the next assessment. If the results of excavations do not match the original assumption, the corrosion distribution model will be updated to guide the next excavations (i.e., the operator returns to step 2).

The Corrosion of Carbon Steel and Stainless Steel in Simulated Geothermal Media

1985 ◽  
Vol 38 (8) ◽  
pp. 1133 ◽  
Author(s):  
BG Pound ◽  
MH Abdurrahman ◽  
MP Glucina ◽  
GA Wright ◽  
RM Sharp
Keyword(s):  
Carbon Steel ◽  
Corrosion Rate ◽  
Stainless Steels ◽  
Polarization Resistance ◽  
Iron Sulfide ◽  
Low Carbon Steel ◽  
Passive Films ◽  
Low Carbon ◽  
Corrosion Rates ◽  
Good Agreement

The corrosion rates of low-carbon steel, and 304, 316 and 410/420 stainless steels in simulated geothermal media containing hydrogen sulfide have been measured by means of the polarization resistance technique. Good agreement was found between weight-loss and polarization resistance measurements of the corrosion rate for all the metals tested. Carbon steel formed a non-adherent film of mackinawite (Fe1 + xS). The lack of protection afforded to the steel by the film resulted in an approximately constant corrosion rate. The stainless steels also exhibited corrosion rates that were independent of time. However, the 410 and 420 alloys formed an adherent film consisting mainly of troilite ( FeS ) which provided only limited passivity. In contrast, the 304 and 316 alloys appeared to be essentially protected by a passive film which did not seem to involve an iron sulfide phase. However, all the stainless steels, particularly the 410 and 420 alloys, showed pitting, which indicated that some breakdown of the passive films occurred.

Corrosion Tests of Zircaloy Hull Waste to Confirm Applicability of Corrosion Model and to Evaluate Influence Factors on Corrosion Rate under Geological Disposal Conditions

2014 ◽  
Vol 1665 ◽  
pp. 195-202 ◽  
Author(s):  
Osamu Kato ◽  
Hiromi Tanabe ◽  
Tomofumi Sakuragi ◽  
Tsutomu Nishimura ◽  
Tsuyoshi Tateishi
Keyword(s):  
Corrosion Rate ◽  
Corrosion Behavior ◽  
Pure Water ◽  
Influence Factors ◽  
Spent Fuel ◽  
Geological Disposal ◽  
Corrosion Tests ◽  
Temperature Range ◽  
Corrosion Rates ◽  
Temperature Ranges

ABSTRACTCorrosion behavior is a key issue in the assessment of disposal performance for activated waste such as spent fuel assemblies (i.e., hulls and end-pieces) because corrosion is expected to initiate radionuclide (e.g., C-14) leaching from such waste. Because the anticipated corrosion rate is extremely low, understanding and modeling Zircaloy (Zry) corrosion behavior under geological disposal conditions is important in predicting very long-term corrosion. Corrosion models applicable in the higher temperature ranges of nuclear reactors have been proposed based on considerable testing in the 523−633 K temperature range.In this study, corrosion tests were carried out to confirm the applicability of such existing models to the low temperature range of geological disposal, and to examine the influence of material, environmental, and other factors on corrosion rates under geological disposal conditions. A characterization analysis of the generated oxide film was also performed.To confirm applicability, the corrosion rate of Zry-4 in pure water with a temperature change from 303 K to 433 K was obtained using a hydrogen measuring technique, giving a corrosion rate for 180 days of 8 × 10-3 μm/y at 303 K.To investigate the influence of various factors, corrosion tests were carried out. The corrosion rates for Zry-2 and Zry-4 were almost same, and increased with a temperature increase from 303 K to 353 K. The influence of pH (12.5) compared with pure water was about 1.4 at 180 days at 303 K.

scholarly journals Effects of tungsten, chromium and zirconium on the corrosion behavior of ternary amorphous W–Cr–Zr alloys in 1 M NaOh solution

1970 ◽  
Vol 9 (9) ◽  
pp. 39-43
Author(s):  
Basu Ram Aryal ◽  
Jagadeesh Bhattarai
Keyword(s):  
Corrosion Resistance ◽  
Corrosion Rate ◽  
Open Circuit Potential ◽  
Open Circuit ◽  
Corrosion Rates ◽  
Corrosion Resistance Property ◽  
Naoh Solution ◽  
Order Of Magnitude ◽  
Sputter Deposited ◽  
Zr Alloys

Simultaneous additions of tungsten, chromium and zirconium in the chromium- and zirconium-enriched sputter-deposited binary W-xCr and W-yZr are effective to improve the corrosion resistance property of the ternary amorphous W- xCr-yZr alloys after immersion for 240 h in 1 M NaOH solution open to air at 25°C. The corrosion rates of all the examined sputter-deposited (10-57)W-(18-42)Cr-(25-73)Zr alloys is higher than those of alloy-constituting elements (that is, tungsten, chromium and zirconium) in aggressive 1 M NaOH solution open to air at 25°C. The corrosion rates of all the examined sputter−deposited W–xCr–yZr alloys containing 10-57 at% tungsten, 18-42 at% chromium and 25-73 at% zirconium were in the range of 1.5-2.5 × 10−3 mm/y or lower which are more than two orders of magnitude lower than that of sputter-deposited tungsten and even about one order of magnitude lower than those of the sputter-deposited zirconium in 1 M NaOH solution. Keywords: Ternary W–Cr–Zr alloys; Amorphous; Corrosion rate; Open circuit potential; 1 M NaOH. DOI: http://dx.doi.org/10.3126/sw.v9i9.5516 SW 2011; 9(9): 39-43

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