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.

Self Directed Integrity Assessment of Non-Piggable Pipelines

2015 ◽  
Author(s):  
Ashish Khera ◽  
Rajesh Uprety ◽  
Bidyut B. Baniah
Keyword(s):  
Oil And Gas ◽  
Oil And Gas Industry ◽  
Management Plan ◽  
Gas Industry ◽  
Internal Corrosion ◽  
Integrity Assessment ◽  
Regulatory Standards ◽  
The Us ◽  
Integrity Management ◽  
External Corrosion

The responsibility for managing an asset safely, efficiently and to optimize productivity lies solely with the pipeline operators. To achieve these objectives, operators are implementing comprehensive pipeline integrity management programs. These programs may be driven by a country’s pipeline regulator or in many cases may be “self-directed” by the pipeline operator especially in countries where pipeline regulators do not exist. A critical aspect of an operator’s Integrity Management Plan (IMP) is to evaluate the history, limitations and the key threats for each pipeline and accordingly select the most appropriate integrity tool. The guidelines for assessing piggable lines has been well documented but until recently there was not much awareness for assessment of non-piggable pipelines. A lot of these non-piggable pipelines transverse through high consequence areas and usually minimal historic records are available for these lines. To add to the risk factor, usually these lines also lack any baseline assessment. The US regulators, that is Office of Pipeline Safety had recognized the need for establishment of codes and standards for integrity assessment of all pipelines more than a decade ago. This led to comprehensive mandatory rules, standards and codes for the US pipeline operators to follow regardless of the line being piggable or non-piggable. In India the story has been a bit different. In the past few years, our governing body for development of self-regulatory standards for the Indian oil and gas industry that is Oil Industry Safety Directorate (OISD) recognized a need for development of a standard specifically for integrity assessment of non-piggable pipelines. The standard was formalized and accepted by the Indian Ministry of Petroleum in September 2013 as OISD 233. OISD 233 standard is based on assessing the time dependent threats of External Corrosion (EC) and Internal Corrosion (IC) through applying the non-intrusive techniques of “Direct Assessment”. The four-step, iterative DA (ECDA, ICDA and SCCDA) process requires the integration of data from available line histories, multiple indirect field surveys, direct examination and the subsequent post assessment of the documented results. This paper presents the case study where the Indian pipeline operators took a self-initiative and implemented DA programs for prioritizing the integrity assessment of their most critical non-piggable pipelines even before the OISD 233 standard was established. The paper also looks into the relevance of the standard to the events and other case studies following the release of OISD 233.

External Corrosion Growth-Rate From Soil Properties

2010 ◽  
Author(s):  
Khalid A. Farrag
Keyword(s):  
Growth Rate ◽  
Corrosion Rate ◽  
Soil Properties ◽  
Growth Rates ◽  
Soil Conditions ◽  
Soil Parameters ◽  
Time Interval ◽  
Soil Redox Potential ◽  
Corrosion Rates ◽  
External Corrosion

External corrosion growth rate is an essential parameter to establish the time interval between successive pipe integrity evaluations. Actual corrosion rates are difficult to measure or predict. NACE Standard RP0502 [1] recommends several methods including comparison with historical data, buried coupons, electrical resistance (ER), and Linear Polarization Resistance (LPR) measurements. This paper presents a testing program and procedure to validate the use of the LPR and ER methods to enhance the estimation of corrosion growth rates and improve the selection of reassessment intervals of gas transmission pipelines. Laboratory and field tests were performed using the LPR and ER technologies. The evaluation of soil parameters that affect localized corrosion included its type, moisture content, pH, resistivity, drainage characteristics, chloride and sulfite levels, and soil Redox potential. The results show that the LPR device provides instantaneous measurement of corrosion potential and it may be used to reflect the variations of corrosion rates with the changes of soil conditions, moisture, and temperature. However, LPR measurements are more efficient in saturated soils with uncertainty about its validity in partially and totally dry soils. Consequently, seasonal changes in soil conditions make it difficult to estimate total corrosion growth rate. On the other hand, the measurements using the ER method provided consistent estimates for long-term corrosion growth rates. Corrosion growth rates were also evaluated from a previous study by the National Institute of Standards (NIST) [2]. A procedure was developed to correlate soil properties to corrosion rates from the ER measurements and NIST data. The procedure was implemented in a computer program to provide an estimate of corrosion rate based on the soil input data and allows the operator to use the ER probes to improve the reliability of corrosion rate estimates.

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.

scholarly journals Fatigue detection and analysis of drilling tools based on metal magnetic memory method

2021 ◽  
Vol 2045 (1) ◽  
pp. 012010
Author(s):  
J W Zhang ◽  
J C Fan
Keyword(s):  
Oil And Gas ◽  
Horizontal Wells ◽  
Magnetic Memory ◽  
Metal Magnetic Memory ◽  
Drilling Tool ◽  
Internal Corrosion ◽  
Drilling Tools ◽  
Drill Pipes ◽  
External Corrosion ◽  
Metal Magnetic Memory Method

Abstract With the vigorous development of offshore oil and gas resources in the world, underwater extended reach horizontal wells have been widely used. However, due to the complicated stress and serious corrosion of drill pipes in horizontal wells, drill pipes are vulnerable to damage. After a period of service at sea, some drill tools will be placed in coastal areas for a long time. The cumulative fatigue of drilling tools is not easy to master. In the past year or two, drilling tool failure has become more and more frequent. In order to evaluate the fatigue of drilling tools in different periods and master the quantitative fatigue of drilling tools, the metal magnetic memory method has its unique advantages in detecting the stress concentration and early damage of ferromagnetic materials. The self-developed metal magnetic memory detection device is used to detect the drilling tools in the drilling tool base. The results show that the gradient peak value and ladder are used to detect the drilling tools in the drilling tool base. The average degree can be used to classify the fatigue of drilling tools, and the metal magnetic memory method is more than sensitive to various defects of drilling tools, such as penetration, internal corrosion, external corrosion, wall thickness thinning, etc.

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.

Pipeline Material Reliability Analysis Regarding to Probability of Failure Using Corrosion Degradation Model

2011 ◽  
Vol 422 ◽  
pp. 705-715 ◽  
Author(s):  
Patuan Alfon ◽  
Johny W. Soedarsono ◽  
Dedi Priadi ◽  
S Sulistijono
Keyword(s):  
Reliability Analysis ◽  
Oil And Gas ◽  
Oil And Gas Industry ◽  
Probability Of Failure ◽  
Distribution Method ◽  
Gas Industry ◽  
Internal Corrosion ◽  
Corrosion Failure ◽  
Calculation Results ◽  
External Corrosion

Reliability of equipment of the oil and gas industry is vital, whereas on pipeline transmission system, decreasing the integrity of the pipeline is generally caused by corrosion. Failure that occurs due to corrosion deterioration influenced by the environment within a certain time, and has exceeded the nominal thickness of the pipe so there is a failure. This study used the reliability analysis approach based on modeling corrosion degradation ratio that is determined by the amount of the corrosion rate externally and internally. Using the Weibull probabilistic distribution method, results that the reliability of pipeline will decrease with increasing lifetime. It was identified that internal corrosion has a major contribution to the remaining life of pipeline. From the calculation results obtained by external corrosion has the greatest reliability over 60 years, followed by internal corrosion less than 30 years and the least is by cumulative corrosion which is less than 20 years. From the value of reliability, it can be known probability of failure (POF) which is the anti reliability.

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.

Demonstrating good practice in the safe operation of gas assets with predictive analytics

2017 ◽  
Vol 57 (2) ◽  
pp. 437
Author(s):  
Hennie Engelbrecht ◽  
Nesa Abbaspour
Keyword(s):  
Oil And Gas ◽  
Predictive Analytics ◽  
Good Practice ◽  
Cost Effective ◽  
Oil And Gas Industry ◽  
Gas Field ◽  
Internal Corrosion ◽  
Maintenance And Inspection ◽  
Inspection Data ◽  
Maintenance Schedules

The oil and gas industry operates large and complex facilities. Technical integrity (and thus licence to operate) must be maintained through routine inspection and maintenance regimes. Corrosion attacks every component at every stage in the life of every oil and gas field or plant (Schlumberger 1994). Globally, corrosion management accounts for US2.5Tr cross-industry spend (NACE International 2016). Risk-based approaches for internal corrosion based on susceptibility of a process item to corrode, have been utilised to assist with identifying appropriate and more cost-effective maintenance and inspection strategies. The aim of such approaches is to protect integrity and not compromise safety; however, they do nothing to minimise regret cost. These approaches use only known physical characteristics of piping equipment and rely on repeat inspection data to calculate corrosion rates and associated maintenance schedules. The present paper will leverage the challenges and shortcomings of using existing risk-based inspection (RBI) approaches and demonstrate how Accenture in collaboration with Woodside and others is utilising predictive analytics to more accurately determine likelihood of corrosion to exist in a more granular resolution, thus managing likelihood and consequence of corrosion to produce an improved risk-based model. The analytics model considers physical, geospatial and external factors for external corrosion. This is a work in progress, with very promising initial results, that leads into the implementation of an improved RBI strategy, enabling Woodside to reduce inspection scope, physical site activity and associated management cost. In addition, it better manages plant risk in conjunction with smart visualisation tools.

Pragmatic Approach to Estimate Corrosion Rates for Pipelines Subject to Complex Corrosion

2014 ◽  
Author(s):  
Markus R. Dann ◽  
Luc Huyse
Keyword(s):  
Measurement Errors ◽  
Oil And Gas ◽  
High Density ◽  
Probabilistic Methods ◽  
Life Assessment ◽  
Remaining Life ◽  
Pragmatic Approach ◽  
Internal Corrosion ◽  
Corrosion Rates ◽  
Remaining Life Assessment

Corrosion is a common degradation process for most oil and gas pipelines in operation that can lead to leak and rupture failures. To avoid failures due to corrosion, integrity management plans for pipelines require fitness-for-service (FFS) assessments and remaining life analysis of the corrosion features that are detected by in-line inspections (ILIs). The objective of the present paper is to support the deterministic integrity and remaining life assessment of pipelines by introducing a pragmatic approach for the determination of corrosion rates from two inspections. The proposed approach is primarily tailored towards upstream and subsea pipelines that are subject to very high density internal corrosion rather than transmission pipelines with low to moderate densities of external features. ILI data may be subject to significant measurement errors and feature matching for two ILIs can become highly unreliable if high-density corrosion is present. To address these uncertainties, the backbone of the proposed approach is to focus on corrosion clusters rather than individual corrosion pits and a filtering process is utilized to identify true corrosion growth. The introduced approach is supported by theoretical knowledge and practical experience. The approach can be easily executed in spreadsheet software tools without the application of advanced statistical and probabilistic methods for the deterministic remaining life assessment in practice.

On the Probabilistic Distribution of External Pitting Corrosion Rate in Buried Pipelines

2008 ◽  
Author(s):  
F. Caleyo ◽  
J. C. Vela´zquez ◽  
J. M. Hallen ◽  
J. E. Araujo ◽  
E. Perez-Baruch
Keyword(s):  
Corrosion Rate ◽  
Power Law ◽  
Pitting Corrosion ◽  
Oil And Gas ◽  
Degradation Mechanism ◽  
Clay Loam ◽  
Buried Pipelines ◽  
Southern Mexico ◽  
External Corrosion ◽  
Corrosion Pits

External pitting corrosion constitutes the degradation mechanism responsible for about 66% of the incidents reported in the last decade for oil and gas pipelines in Mexico. Thus, major efforts are underway to improve the characterization and modeling of pitting corrosion of buried pipelines. Special attention is devoted to estimate the average corrosion rate and corrosion rate variance because they are the key parameters in the estimation of the trend in pipeline reliability. This work presents the results of field and simulation studies in which soil and pipe data were gathered together with the maximum depth of external corrosion pits found at more than 250 excavation sites across southern Mexico. The distributions of parameters such as chloride, bicarbonate and sulfate levels, resistivity, pH, pipe/soil potential, humidity, redox potential, soil texture and coating type have been used to predict the distribution of pitting corrosion rate of pipelines in contact with clay, clay-loam and sandy-clay-loam soils. The time dependence of the pitting corrosion rate was fitted to a power law through a multivariate regression analysis with the maximum pit depth as the dependent variable and the pipeline age and the soil and coating properties as the independent variables. Monte Carlo simulations were conducted in which random values drawn from the distributions fitted to the field data were used to evaluate the power law model proposed for the corrosion rate. For each soil type, the distribution that best fitted the corrosion rate data was found. The results of this study will provide reliability analysts with a more accurate description of the growth rate of external corrosion pits. It is expected that this information will positively impact on integrity management plans addressing the threat posed by this damage mechanism.

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