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Abstract The storage of used nuclear fuel (UNF) in dry canister storage systems (DCSSs) at Independent Spent Fuel Storage Installations sites is a temporary measure to accommodate UNF inventory until it can be transferred to a repository for permanent disposal. It is recognized that spent fuel may require storage in DCSSs for much longer periods than were originally anticipated. The eddy current method is presented as a potential tool for inspecting the outer surfaces of DCSS canisters for degradation, particularly atmospheric stress corrosion cracking (SCC). Previous work has focused on modeling that was performed to explore the feasibility of sizing SCC flaws in canisters using an eddy current technique. A multi-frequency approach was simulated and frequency responses from 5 kHz to 100 kHz are presented in an effort to identify potential distinguishing features that will facilitate accurate depth sizing of atmospheric SCC flaws from eddy current measurements. This paper presents the results of efforts to date to benchmark the modeling results with laboratory data. Introduction In the United States, over 72,000 metric tons of used nuclear fuel (UNF) have been accumulated through the operation of nuclear power plants for commercial power generation through the end of 2013, and this inventory of UNF is projected to grow by approximately 2400 metric tons each year.1 Currently, the inventory is distributed among storage pools at reactor sites with supplemental storage capacity provided by dry storage facilities known as Independent Spent Fuel Storage Installations (ISFSIs). At the ISFSI sites, dry cask storage systems (DCSSs) contain UNF that has been removed from the storage pools. Several DCSS designs consist of a metal container that is placed inside of a thick concrete over-pack. Fuel is loaded into the metal containers, dried, and then the container is filled with an inert gas and sealed to ensure that the integrity of the fuel is maintained. The sealed container is placed inside of the thick concrete over-pack, which provides radiological shielding and some protection from environmental elements.
Abstract A condition monitoring system for corrosion and stray current monitoring is being supplied and installed into the new metro line in Copenhagen known as the Cityringen project. The objective of the system is to provide a combination of : 1. Pre-warning system for corrosion occurring within the concrete cover so as to spot the onset of corrosion at reinforcement depth using a number of anode ladder sensors and electrical resistance (ER) sensors. 2. To understand the areas of stray current flow through the tunnel and station walls through the use of sense electrode sensors. The data will be used to refine the uncertainties and assumptions in service life model predictions of concrete durabilities developed prior to the structure design . This paper describes the implementation of the monitoring system and the design consideration/ philosophy used when determining measurement location throughout the system and the challenges presented and overcome. Introduction The Copenhagen Metro is a rapid transport system serving Copenhagen, Frederiksberg, and Tarnby in Denmark and is owned and operated by Metroselskabet. The system first opened in 2002 and with two lines, M1 and M2. In 2011, construction began on the new circle line M3 (Cityringen) around Copenhagen that will consist of 2 × 17.4 km tunnels and 17 new stations all at 30 m below ground. The Cityringen metro system, like the two lines M1 and M2, will be a driverless metro system which will operate 24 hrs a day. The metro system will operate on a 3 rail floating 750V direct current (DC) system and incorporate a stray current collecting steel mesh reinforcement under the rails for the entire length. In the existing systems, a corrosion protection system has also been installed at Islands Brygge station (IBS) to provide protection to the reinforcing steel in the station diaphragm walls.
- Transportation > Ground > Rail (0.89)
- Commercial Services & Supplies > Security & Alarm Services (0.54)
- 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)
- Data Science & Engineering Analytics > Information Management and Systems (0.95)
Improving the Controlled Humidity Protection Systems by Addition of Vapor Phase Corrosion Inhibitors
Bavarian, Behzad (California State University) | Reiner, Lisa (California State University) | Ikder, Yashar (California State University) | Miksic, Boris (Cortec Corporation) | Samimi, Babak (California State University)
Abstract Controlled Humidity Protection (CHP) reduces corrosion created by exposing items to high relative humidity (exceeding 40%). Although, controlled humidity protection systems, in theory, can suppress the cathodic reaction and lower the corrosion rate, in reality, the amount of moisture and oxygen in presence of corrosive species like chloride that is required to initiate the corrosion reaction for steel is extremely low, and once corrosion reaction starts there is no defense mechanism to stop it. Addition of the vapor phase corrosion inhibitors to the CHP provide a more effective corrosion protection for materials exposed to the environment during short term storage. A dry air controlled humidity system can reduce the moisture level, but it will not be able to prevent corrosion. The advantage of the vapor phase corrosion inhibitor addition to CHP system is the creation of a strong physisorption to the material surface that minimizes any surface contact with corrosive species or water due to its hydrophobic film. Therefore, vapor phase corrosion inhibitors addition can provide superior advantages over the controlled humidity protection system in the presence of aggressive environments that contain excessive salt, oxygen and moisture. Introduction Trillions of dollars are lost to corrosion each decade. The vast majority of natural degradation to materials is classified as uniform corrosion with atmospheric corrosion being the most prevalent type. In atmospheric corrosion, a material that is subjected to air moisture and pollutants is at serious risk. The U.S. Government reports that corrosion damage for military defense exceeds $20 billion per year. Preservation and mothballing equipment during storage is extremely important in maintaining military preparedness. The Department of Defense has an enormous amount of equipment and facilities that are susceptible to corrosion. Military forces operate worldwide where corrosion related effects including humidity, fluctuating temperature, salt spray and harsh desert environments can attack the surface of materials reducing availability and deteriorating performance. DoD corrosion related maintenance costs are estimated at $23 billion each year.
- Europe (1.00)
- North America > United States > Texas > Harris County > Houston (0.16)
- 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 The use of corrosion sidestream units can enhance understanding of corrosion mechanisms and optimize the chemical injection rates. However, as always, there are pitfalls, challenges and weaknesses related to the test method and the experiences described here may be helpful for future field studies. Usually, it is not possible to mimic the full range of field conditions in the laboratory environment, which can potentially lead to insufficient and misleading information. Field studies may seem as challenging operations, however the resulting data is often significantly more realistic compared to the information obtained in laboratory studies, and often provides quality data for decision support. With emerging technologies, the field studies can be performed with a minimum workload for the operational personnel. The main workload is normally up front of the test, and the duration of the test is normally less important as it has minimal impact on operational routine. This opens a window of opportunity for time and cost effective studies of slow evolving corrosion mechanisms, for example microbiologically influenced corrosion (MIC), and finding suitable mitigation treatments for them. Experience dictates that in many cases, the use of corrosion sidestream units may be equally or more cost effective when matched with laboratory evaluation methods. Introduction During last several decades, the economic consequences of corrosion in various oil and gas (O&G) operations have been well documented. Internal corrosion causes immense damages to low-alloyed steel offshore infrastructures such as pipelines and water injection systems. Thus, the impact of corrosion on the operational capacity and life cycle of various assets and infrastructures in the O&G industry is increasingly coming into focus. Degradation of ferrous alloys is a consequence of chemical, electrochemical and/or mechanical interactions of a specific ferrous alloy with its surrounding environment that results in material loss.3 Wide ranges of mitigation treatments are applied to combat the ongoing corrosion in the production process. Some mitigation options include the use of production chemicals. Depending on the origin of corrosion, different chemicals can be applied: corrosion inhibitors, biocides and H2S scavengers. They can be applied separately or together to achieve a synergetic effect.
- North America > United States (1.00)
- Europe > United Kingdom > North Sea (0.40)
- Europe > Norway > North Sea (0.40)
- (2 more...)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.55)
- Well Completion > Well Integrity > Subsurface corrosion (tubing, casing, completion equipment, conductor) (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (1.00)
- (2 more...)
Abstract Installed ultrasonic sensor systems are becoming more commonly used and accepted as a method to improve data integrity and increase productivity for Oil & Gas asset inspections – especially with underground, insulated, offshore, and other hard-to-access thickness monitoring locations (TMLs). Example applications where installed sensor technologies have been deployed successfully include crude overhead lines, sour water service, offshore risers for sand monitoring, and midstream buried pipelines. Many additional applications of these systems are anticipated to augment static thickness monitoring, improve the accuracy of thickness data/trending, and reduce pressure-boundary penetration of conventional corrosion probes while allowing both remote and real-time monitoring where desirable. This paper will review the development of a new, flexible, permanently installed monitoring system. Concepts for optimizing the measurement system will be discussed, including hard-wired and wireless approaches, proper transducer selection, temperature compensation, and statistical data analysis. Introduction Metal loss due to corrosion and erosion is a widespread issue in the oil and gas (O&G) and Power Generation industries for tanks, high-energy piping, pressure vessels, and other critical assets. Metal loss can result in loss of pressure containment, with resulting consequences that can include loss of life, damage to assets, disruption of service, environmental harm, loss of public image, and fines. As such, asset inspections are required by operators and are mandated in regulations and codes such as 29CFR-1910; API 570, ASME Sections V & XI, ASTM E797, and NACE IP 34101. While there are many methods for measuring wall thickness, a predominant method is the use of portable ultrasonic equipment. Ultrasound is non-intrusive, accurate, and relatively low cost to employ in most situations. However, it does have several shortcomings, including that the ultrasonic transducer or probe needs to be applied in direct contact to the external surface of the pipe; this sometimes requires scaffolding, excavation, and stripping of coatings or insulation. Thus, the cost of access to the structure often far exceeds the basic cost of inspection. Furthermore, a trained and certified inspector is required to operate the ultrasonic instrumentation, requiring personnel to sometimes be exposed to potentially hazardous environments. The accuracy and repeatability of ultrasonic measurements are operator-dependent, and recent studies have shown that the probability-of-detection (POD) can be poor. Finally, the measurements are only performed periodically, taking a snap-shot of plant condition.
- Geophysics > Seismic Surveying > Borehole Seismic Surveying (0.61)
- Geophysics > Borehole Geophysics (0.61)
Unexpected Sour Cracking Resistance of Duplex and Superduplex Steels
Siegmund, Gerit (ExxonMobil Production Deutschland GmbH) | Schmitt, Guenter (IFINKOR-Institute for Maintenance and Corrosion Protection Technologies n.f.p.Ltd.) | Kuhl, Lars (IFINKOR-Institute for Maintenance and Corrosion Protection Technologies n.f.p.Ltd.)
Abstract The SSC and SCC performance of duplex steel UNS S31803(1) (1.4462) and superduplex steel UNS S32760 (1.4501) was tested with welded round tensile bars under constant load of 90% AYS (measured at the test temperature) fully submerged in brines with 10 to 45 g/L chloride in the presence of 150 mg/L bicarbonate under partial pressures (at test temperature) of 5 bar CO2 plus 0.5, 0.7 and 1.0 bar H2S at temperatures of 28.5, 90, 100, 130 and 180°C with an exposure time of 720 h. In none of the corrosion systems tested cracking was observed. Moderate localized surface activation was encountered yielding mostly shallow pits due to selective phase dissolution. It appears that the performance profile of these groups of stainless steels is still not completely known specifically at higher temperatures, and is obviously largely underestimated. Introduction Continuous and cyclic steam injection is a long known technique to enhance oil production from reservoirs containing heavy crudes. ExxonMobil Production Deutschland GmbH? plans to enhance existing steam injection in an older oil field raising the current well head temperatures from about 100 °C to approximately 180 °C. Although there are various similar applications around the world, materials selection for this application is challenging because environmental conditions differ considerably from field to field and cannot easily be compared. Important variables are: • temperatures • water-oil ratio (WOR) • chloride and bicarbonate content of brine • partial pressures of H2S, CO2 • pH under production conditions • presence of oxygen
- Europe (0.47)
- North America > United States > Texas (0.20)
Abstract A new type of sensor has been developed for measuring on-line corrosion in industrial process units with high sensitivity. The sensor is based on a vibrating tuning fork which changes frequency as it corrodes. Most resonator or mass balance sensors are based on the principle that mass increase or decrease (e.g. corrosion) causes frequency to decrease or increase, respectively. This effect can be problematic for detecting corrosion because corrosion scale can adhere to the tuning fork and result in a null mass effect with little change in frequency despite significant corrosion. This tuning fork design is constructed by welding a small corrodible base stem insert connecting the non-corroding paddles to the non-corroding diaphragm so that only the tuning fork base stems can corrode. As a result, corrosion reduces the system spring constant and frequency decreases. Scale deposition has little integrity compared to metal and does not cause a change in spring constant. This combination enables a reliable corrosion measurement even when corrosion scale builds up on the corrodible element. Laboratory testing and field experiences have demonstrated that corrosion can be accurately measured in real-time with high sensitivity without interference from deposit buildup. Introduction Corrosion measurement tools for industrial applications are commonly used and are commercially available from a number of sources. The simplest device is a corrosion coupon made out of the material of interest which can be periodically extracted and measured to quantify metal loss. However, coupons do not afford real-time measurement capability and require accessibility to remove the coupon. Various acoustic methodologies are available as point sensors or more sophisticated guided wave systems. These methods are typically applied as inspection tools or services. Although point ultrasonic sensors are now available offering real-time metal thickness, they do not provide information regarding the fluid corrosivity. Various technologies have been developed as online, real-time corrosion sensors such as fiber optics, multi-electrode arrays, linear polarization resistance (LPR) probes and electrical resistance (ER) ,sensors. Electrical Resistance sensors are the most widely used in hydrocarbon environments but their use is limited by durability, sensitivity and useful life. In order to increase ER probe sensitivity, the corrodible element must be made thinner resulting in a shorter useful life. Longer lived, thicker sensing element ER probes suffer from reduced sensitivity and high noise levels. Electrical resistance is highly temperature dependent and measurements are especially noisy when temperature is not well controlled. Measurements may also be compromised by the deposition of semi-conductive scales such as iron sulfide. The focus of the present work is to develop a durable sensor with a life of approximately five to ten years (for corrosion rates that average around 0.2-0.5mm/y) with sensitivity to detect a corrosion rate change on the order of 0.1mm/y within several days of measurement.
Abstract The design of offshore wind foundations is still evolving as large projects are being commissioned or planned for the northern part of Europe. Monopile foundations represent the most common design, but other structure types are also being installed, such as jackets, tripods and gravity foundations. In comparison with offshore structures for oil and gas production, wind foundations present some new challenges for corrosion protection. As the structures are unmanned, the requirements for operation and maintenance must be kept at a minimum. At the same time, the huge water volume in the closed compartment of monopiles raises some concerns about MIC at seabed. The cathodic protection (CP) being applied both outside and inside also involves certain challenges. In this respect, several new approaches for inspection and corrosion monitoring have been applied. The paper reviews specific corrosion risks, such as macro galvanic elements, MIC and insufficient CP. Experiences from evaluating such issues by using various inspection and monitoring techniques are discussed. The applied techniques include UT examination, CP surveys with drop cells and environmental depth profiling. Corrosion has been evaluated using both small coupons and full-length coupons, while real-time measurements have included ER sensors as well as potential and current measurement. Introduction The design of offshore wind farm foundations is still evolving in order to reduce Cost of Energy and harness energy in locations at greater depths. At the same time, there is a demand for larger turbines with an increased reliability to minimize costly offshore maintenance. This tendency creates an increasing need for customized inspecting and monitoring of the structural integrity of wind turbine foundations. While the methods applied to offshore oil and gas installations are well-established, the strategies for offshore wind structures still undergo a learning curve. Experiences from early projects are steadily growing, but simultaneously the designs in new projects change to optimize performance and costs. Large offshore wind farms have existed for 10-15 years. Today, 80 major offshore wind farms and 2850 turbines are operating in the northern part of Europe. Most of the foundations are based on the monopile design, but other structure types are also being installed, such as jackets, tripods and gravity foundations.
- Europe > Germany (0.32)
- North America > United States > Texas > Harris County > Houston (0.16)
- 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)
- Health, Safety, Environment & Sustainability > Environment (1.00)
- (3 more...)