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ABSTRACT Based on past experience within the company with corrosion under insulation (CUI), an external corrosion risk assessment and management program that is based on a modified risk assessment matrix was developed. This modified risk assessment matrix is tied to individual external inspection and mitigation strategies. The CUI assessment program included both corrosion of ferrous steels and external chloride stress corrosion cracking of austenitic stainless steel. To date, this program has been used to manage external corrosion risk at various chemical and refinery sites in order to reduce the risk associated with corrosion under insulation. As of mid-2004, for each dollar spent on the program, about four (4) times that in risk has been reduced. INTRODUCTION Corrosion of pressure equipment under insulation can be a significant threat to equipment integrity. As plants age, unless an external coating program has been in-place, the need for protection from external corrosion can increase as a result of coating damage and degradation. Increased susceptibility to CUI is also related to the ability to prevent water intrusion and site practices toward maintaining insulation (lagging) and insulation covering (cladding). CUI is somewhat unpredictable in that it is not readily detected by non-destructive evaluation (NDE) and may or may not happen at areas thought to be susceptible (e.g., penetrations through the insulation and covering, nozzles). Spot inspection for CUI can be misleading. Company plant experiences have shown that looking at an area thought to be susceptible to CUI may reveal no corrosion, yet thinning or leakage may occur a short distance away from the inspected susceptible area. Most commonly the CUI was the result of water flowing through the penetration and pooling at a location away from the penetration. Additionally, coatings can have a good appearance in one location, yet be completely failed with CUI ongoing at another. External chloride cracking (ECSCC) can occur in stainless steel systems that appear intact from a CUI standpoint, yet cracking occurs for the same reasons described for ferrous alloy CUI. During the late 1990?s, several sites within Shell(2) reported a number of inspection findings related to CUI, some of which were found in systems approaching 20 years in age, with coating failures that were random and not at areas judged to be susceptible, and were in systems carrying light hydrocarbons. Two of these finds are shown in Figures 1-2 below. A global integrity team was formed to evaluate these findings and consider other methods that could be used to address CUI. This team determined that use of spot inspections, localized inspection techniques, or just visual external inspection was not effective at detecting CUI. That team determined that an effective method of locating and mitigating CUI was to approach it by considering the risk of a leak in the system. The integrity team also determined that there are no perfect inspection tools to detect CUI, and that risk-based categorization allowed prioritization of maintenance and inspection resources to be used to mitigate the items in a manner that could cause the most impact in plant integrity and reliability. Depending upon the risk of leak of the pressure equipment system, various amounts of insulation removal up to 100% were specified as a part of the inspection strategy.
- Europe (0.46)
- North America > United States > Texas (0.28)
- Materials > Metals & Mining > Steel (1.00)
- Law Enforcement & Public Safety (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Well Completion > Well Integrity > Subsurface corrosion (tubing, casing, completion equipment, conductor) (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (1.00)
- Management > Risk Management and Decision-Making > Risk, uncertainty, and risk assessment (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Materials and corrosion (1.00)
ABSTRACT Many unexpected cracks occur in aging 18 years old austenitic stainless steel on cryogenic pipeline application. Operations need to be stopped for treatment and repair which results in delay transmission against customer. Systemic root cause analysis reveals that random cracks initiated on external surface when operating condition reaches room temperature. Degradation of cold thermal insulation provides accessibility for air-borne chloride to the pipe. Fatigue crack propagation through metal is driven by thermal stress during start/stop service operation period proven by microstructure analysis and NDT inspection result. Assessment reveals pipeline need to be replaced. Corrosion control for new pipeline are established. INTRODUCTION Client’s pipeline leaks were detected during normal operation of transmission. Ice is found at the bottom of insulation jacket as shown in figure 1 (left). Media from services is suspected of leaking on the grounds that an abnormal percentage of lower explosive limit (LEL) is detected by hand-held gas detector. Transmission is stopped immediately for safety reasons, an investigation is undertaken to find the root cause of deterioration, and to provide remedy. Figure 1 (right) shows one of the leakage points after insulation is removed. Liquid hydrocarbon is transported in these ten kilometers long pipeline. Normal chemical processing condition is about -100°C and 10 kg/cm. Pipe is 4 inch and 3.05 mm in nominal thickness. Its material is A312-TP304 EFW (electrical fusion weld). An insulation to reserve temperature in the pipeline is done in two layers; foam glass with mastic sealant on the first layer and weathering proof aluminum jacket on the second layer. Utilization time of this pipeline is about 10%. The pipeline is thus not in operation in most of the time. During operation suspension period, temperature rises up to 25-30°C and pressure decreases from 10 kg/cm to 2kg/cm. The pipeline has been operated for 18 years. Corrosion under insulation influenced by chloride stress corrosion cracking (CUI-CLSCC); commonly occurs in insulated ageing austenitic stainless steel process equipment . Chloride in rock wool insulation can be penetrated by water ingress . As chloride concentration increases from liquid evaporation, it is sufficient to promote the phenomenon. CLSCC susceptible temperature is 60 - 175°C, which is much higher than the operating condition of leakage pipeline . Moreover, CUI-CLSCC is not commonly occurred in foam glass material . Therefore, this problem is intriguing to industry practice; results on the investigation can improve monitoring and operation to make workplace safer.
Abstract Offshore oil and gas production environments provide severe challenges in terms of materials selection and day-to-day operations. Several issues encountered during commissioning of a North Sea platform and the remedial actions are presented. Iron contamination from debris generated during topsides construction and chlorides from the marine atmosphere provided the conditions necessary for ferric chloride pitting corrosion of uncoated 316 stainless steel (SS), duplex and super duplex SS, and 6%Mo SS pipework and vessels. Several offshore cleaning/coating methods were evaluated and a new procedure for cleaning was identified that achieved the desired goal without removal of metal or affecting the corrosion resistant alloy's passive film integrity. Corrosion protection of carbon steel bolting by encapsulation was employed to stop deterioration of an improperly applied anodic coating. Insulated SS instrument tubing was susceptible to crevice corrosion and chloride stress corrosion cracking (Cl-SCC) under wet insulation at the temperatures generated by the heat tracing. Solutions were suggested to minimize such forms of corrosion. Coatings exceeding the manufacturer's recommended thickness had been applied to several high temperature vessels and pipework to prevent SCC as well as ferric chloride pitting. The potential for coating disbondment at elevated temperatures due to high dry film thickness was evaluated through a testing program and onsite inspections. Introduction A platform topsides facility, shown in Figure 1, installed on a North Sea jacket, deteriorated substantially during the time between installation and the start of hookup/commissioning due mainly to the substandard coatings and workmanship. This degradation was exasperated by construction contamination and exposure to the marine environment. To safely, cost-effectively and in a timely manner remediate this situation, a rectification team was established, which included materials and corrosion specialists. Implementation of pragmatic solutions to the various issues encountered was required to ensure an on-time start-up. The required work scope entailed:Bolting remediation with thermoplastic encapsulation Iron and chloride contamination removal Aluminum foil for heat tracing of corrosion resistant alloy (CRA) instrument tubing High dry film thickness (DFT) coating qualification. Bolting remediation with thermoplastic encapsulation Corrosion of bolting has been long recognized as a problem for offshore platforms.(O. Andersen et al., 1996, K.P. Fischer, 2002, K.P. Fischer, 2003, I. A. Muzghi, 2004, K. Stevens, 2000, K. Stevens et al., 2003, B.M. Willis, 2000) Various remediation techniques have been used in the past including, fluoropolymer coatings, electroplating/galvanizing, and use of CRA bolting materials. At this facility, most bolts were manufactured from low alloy carbon steel to provide a good combination of high strength and reasonable cost. Zinc/nickel electroplating followed by a passivation treatment was specified to provide corrosion protection. During deck integration, it was evident that a significant quantity of bolting materials on the platform suffered corrosion due to failure and premature consumption of the electroplated " protective?? coating. As most piping systems were already installed and hydrotested, it was important to avoid replacement of bolting materials unless safety or short-to-medium term operability were threatened. The corrosion product was superficial, giving an unsightly appearance to the bolts, adjacent flanges and piping components as shown in Figure 2. No pitting corrosion was observed.
- Europe > United Kingdom > North Sea (0.45)
- Europe > Norway > North Sea (0.45)
- Europe > North Sea (0.45)
- (3 more...)
- Well Completion > Well Integrity > Subsurface corrosion (tubing, casing, completion equipment, conductor) (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Materials and corrosion (1.00)
Summary Offshore oil- and gas-production environments provide severe challenges in terms of materials selection and day-to-day operations. Several issues encountered during commissioning of a North Sea platform and the remedial actions are presented. Corrosion protection of carbon-steel bolting by encapsulation was employed to stop deterioration of an improperly applied anodic coating. Iron contamination from debris generated during topside construction and chlorides from the marine atmosphere provided the conditions necessary for ferric chloride pitting corrosion of uncoated 316 stainless steel (SS), duplex and super duplex SS, and 6% Mo SS pipework and vessels. Several offshore cleaning/coating methods were evaluated, and a new procedure for cleaning was identified that achieved the desired goal without removal of metal or affecting the corrosion-resistant alloy's passive film integrity. Insulated SS instrument tubing was susceptible to crevice corrosion and chloride stress corrosion cracking (Cl-SCC) under wet insulation at the temperatures generated by the heat tracing. Solutions were suggested to minimize such forms of corrosion. Coatings exceeding the manufacturer's recommended thickness had been applied to several high-temperature vessels and to pipework to prevent SCC as well as ferric chloride pitting. The potential for coating disbondment at elevated temperatures because of high dry-film thickness (DFT) was evaluated through a testing program and on-site inspections.
- North America > United States (1.00)
- Europe > United Kingdom > North Sea (0.25)
- Europe > Norway > North Sea (0.25)
- (2 more...)
- Well Completion > Well Integrity > Subsurface corrosion (tubing, casing, completion equipment, conductor) (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Materials and corrosion (1.00)
Abstract Chloride-Stress Corrosion Cracking (ClSCC) of austenitic stainless steels has been one of the biggest challenges in the refining industry and one of the main reasons where upgrading to stainless steel may not be the miracle solution for battling corrosion problems. Even with all that is known about this mechanism, the industry still faces failures, mainly because chlorides show up when they are not expected and accounted for, leading to economic or worse, catastrophic failures. Factors affecting ClSCC like pH, operating temperature and chloride ion concentration are considered in API 581 to designate a Severity Index. Other factors like the number of inspections, the effectiveness of the inspections and time since the last effective inspection etc. are considered to determine the Damage Factor. However, factors like presence of oxygen, effects of extreme pH and temperatures or stress relieving are not considered. A proposed Risk Assessment Tool using a new factor "susceptibility modifier" to API RP 581 Task Group was presented in November 2016 and has been incorporated in the newly released API 581 – Addendum 2 in October 2020. This paper will identify and document how these different factors affect the susceptibility of austenitic stainless steel to Chloride-Stress Corrosion cracking based on a review of currently available literature. A review of current industry best practices and a review of how the Oxygen content, the pH and application of stress relief affects Chloride-Stress Corrosion Cracking will be documented and presented. Introduction Chloride promoted stress corrosion cracking (ClSCC) is a damage mechanism that can occur in a chloride containing aqueous environment. Damage can occur during in-service or during shutdown, if chloride containing solutions are present, especially at temperatures above 66°C (150°F). Austenitic stainless steels are highly susceptible to ClSCC. Damage can occur internally (from process, wash water or firewater etc.) or it can occur externally under insulation. ClSCC is typically transgranular and highly branched. Susceptibility to ClSCC is usually assessed based on the chloride content, pH and temperature. The formal risk assessment methodology used in API RP 581 Third Edition provides a quantitative procedure to establish an inspection program using risk-based methods for pressurized fixed equipment. In API 581, Section 12 "SCC Damage Factor – Chloride Stress Corrosion Cracking," the basic assumption is that ClSCC of austenitic stainless steels can occur in a chloride-containing aqueous environment and the susceptibility to ClSCC is dependent on: • the concentration of the chloride ions, • the temperature, and • pH