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Guidelines for laying pipelines
Friday, February 15, 2008
off shore pipelines leterature
Description:
There are very few books on the market that cover offshore petroleum engineering, and there are none at all on offshore pipelines. Over a third of the growth in drilling worldwide is expected to come from offshore. The development of offshore pipelines is an extremely hot topic in the energy industry. This book is the most up-to-date reference for the engineers and developers challenged with bringing the oil and gas onshore.
Pipeline design engineers will learn how to design low-cost pipelines allowing long-term operability and safety.
Pipeline operation engineers and management personnel will learn how to operate their pipeline systems in a cost effective manner.
Deepwater pipelining is a new technology developed in the past ten years and growing quickly.
Contents:
Chapter 1: Introduction Part I: Pipeline DesignChapter 2: General Design InformationChapter 3: Diameter and Wall Thinkness Chapter 4: Hydrodynamic Stability of Pipelines Chapter 5: Pipeline Span Chapter 6: Operating Stresses Chapter 7: Pipeline Riser Design Chapter 8: Pipeline External Corrosion Protection Chapter 9: Pipeline Insulation Chapter 10: Introduction to Flexible Pipelines Part II: Pipeline InstallationChapter 11: Pipeline Laying Method Chapter 12: Bending Stress Control Chapter 13: Pipeline Stability Control Part III: Pipeline Commissioning and OperationsChapter 14: Pipeline Testing and Pre-commissioning Chapter 15: Flow AssuranceChapter 16: Pigging Operations AppendicesAppendix A: Gas-Liquid Multiphase Flow in PipelineAppendix B: Steady and Transient Solutions for Pipeline TemperatureAppendix C: Strength De-Rating of Old Pipelines
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There are very few books on the market that cover offshore petroleum engineering, and there are none at all on offshore pipelines. Over a third of the growth in drilling worldwide is expected to come from offshore. The development of offshore pipelines is an extremely hot topic in the energy industry. This book is the most up-to-date reference for the engineers and developers challenged with bringing the oil and gas onshore.
Pipeline design engineers will learn how to design low-cost pipelines allowing long-term operability and safety.
Pipeline operation engineers and management personnel will learn how to operate their pipeline systems in a cost effective manner.
Deepwater pipelining is a new technology developed in the past ten years and growing quickly.
Contents:
Chapter 1: Introduction Part I: Pipeline DesignChapter 2: General Design InformationChapter 3: Diameter and Wall Thinkness Chapter 4: Hydrodynamic Stability of Pipelines Chapter 5: Pipeline Span Chapter 6: Operating Stresses Chapter 7: Pipeline Riser Design Chapter 8: Pipeline External Corrosion Protection Chapter 9: Pipeline Insulation Chapter 10: Introduction to Flexible Pipelines Part II: Pipeline InstallationChapter 11: Pipeline Laying Method Chapter 12: Bending Stress Control Chapter 13: Pipeline Stability Control Part III: Pipeline Commissioning and OperationsChapter 14: Pipeline Testing and Pre-commissioning Chapter 15: Flow AssuranceChapter 16: Pigging Operations AppendicesAppendix A: Gas-Liquid Multiphase Flow in PipelineAppendix B: Steady and Transient Solutions for Pipeline TemperatureAppendix C: Strength De-Rating of Old Pipelines
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Cathodic Protection Management
Established
Cathodic Protection Management, Inc (CPM) was established and incorporated in 1998 specializing in the management of cathodic protection systems. This includes the design and maintenance of sacrificial and impressed current cathodic protection systems, including conventional, semi deep and deep anode groundbed systems, monitoring stations, test coupons, remote external and internal corrosion control monitoring and mitigation. In 1999 CPM became a full service corrosion control company offering engineering services, materials, and installation capabilities.
Expertise
CPM consists of individuals with sales and technical expertise in the corrosion control industry. Our staff is comprised of a balance of book and field educated personnel. Members of our staff have work experience with AC Power Generation, Transmission and Distribution, Natural Gas Transmission and Distribution, Quality Assurance/Quality Control and Engineering Consulting.
The CPM Staff also included personnel with the following direct assessment specialty credentials: Magnetic (Mag) Particle Inspection, Visual Inspection, Penetrant Inspection, Ultrasonic Inspection and Certified Welding Inspection QC1-96
At CPM, our specialties are the tasks that are consideered difficult, i.e. Stray DC current interference, Induced AC Voltage, MIC, etc.
External Corrosion Direct Assessment (ECDA) tasks are performed in accordance with National Association of Corrosion Engineers, (NACE) international and the Gas Technology Institute (GTI) as required.
Pipeline surveys that we routinely perform include but are not limited to: Close Interval (Potential) Survey (CIS or CIPS), Direct Current Voltage Gradient (DCVG), Soil Resistivity, GPS, and Depth of Cover (DOC).
Additional corrosion control/cathodic protection surveys that we perform include: Aboveground Storage Tanks, Undergound Storage Tanks, Remote Monitoring, Heat Exchangers along with other metallic Structures.
We perform inspections at Tank Farms, Refineries, Chemical Plants, Water Treatment Plants, Waste Water Treatment Plants, Water Towers, Lift Stations and Buried Vaults.
Experience
Current company activities include managing cathodic protection systems, installation projects, inspection of cathodic protection materials and installation during construction, technical assistance and consulting for various cathodic protection systems, provide QA/QC and packaging for sacrificial anodes, and material supplier to utilities, gas, petroleum and water pipeline owners, operators and contractors. Our warehouse located in Chicago is centrally located to provide materials support for the entire Midwest.
At the present time Cathodic Protection Management, Inc is associated with Manufacturers, Professional Engineers, National Association of Corrosion Engineers (NACE), Corrosion Specialists and Certified Corrosion Control Technicians.
The Principals
The principals of CPM are William P. Carlson and Eric S. Langelund.
William "Bill" CarlsonThe owner and president of CPM, William P. Carlson has worked exclusively in the corrosion control community for the past thirty years. Previously to forming CPM, he was a co-founder of the largest publicly traded Corrosion Control Company in the world where he served a s a senior Vice-President and member of the Board of Directors. During his tenure, he directed their slaes, engineering, construction and cathodic protection maintenance and materials manufacturing operations at five locations located in the Midwest. He managed the larges regional operation of the corporation with more than 100 technical and support staff.
During his career he introduced numerous new and upgraded products, established a technical sales training program complete with sales manuals and point of sale support materials, and established distributors in specific markets. Mr Carlson also excelled in specification preparation that resulted in proprietary and sole source procurment of products and services, a specialty was the "packaged systems" whereby complete systems were promoted which usually reduced or eliminated the use of "look alike" products. Introducing new products or services were promoted trrough seminars and "brown bag" presentations to decision making employees or specifiying engineers. ut e URD market, the water and wastewater market and the radio and microwave towers market are just a few that did not regularly use cathodic protection but were developed under Mr. Carson's direction and continue to be exceptionally profitable.
Introducing new products, such as Link Seals, reintroducing upgraded products such as aerial surveillance equipment and remote monitoring and pipeline coating acceptance are areas where Mr. Carlson displayed his talents. Selling the full line proved to be effective and profitable.
Mr. Carlson has extensive experience in the application of corrosion control to various structures, unique design concepts, product serviceability and reliability, installation procedures and monitoring and maintenance of cathodic protection systems. He is certified and licensed in the States of Wisconsin as an Underground Tank System Installer, Illinois in Underground Storage Tank Cathodic Protection and Indiana as an Undergound Storage Tank Installer and Retrofitter.
He holds and shares in several patents in the corrosion control field. He is a 30-year member of the National Association of Corrosion Engineers, (NACE), twice served on the NACE Board of Directors and received numerous awards including NACE's Outstanding Service Award. Mr. Carlson has participated in training courses and technical presentations at various Universities, is a guest lecturer at several Midwest Universities and is a preferred speaker at the University of Wisconsin Aboveground Storage Tank Program. Mr .Carlson has served on the O'Hare Corrosion Control Committee, Chicago Area Joint Electrolysis Committee and serves as a representative on the Joliet Underground Corrosion Control Committee.
While serving in his various positions, Mr. Carlson's expertise includes the application of cathodic protection to various facilities including cross country pipeline, bulk storage tank farms, refineries, missile silos, undergound concentric cables, tower anchors, underground storage tanks, steel lift stations and water storage tanks. He has supervised engineering and construction departments on projects located through the Midwest and has been involved in the installation of cathodic protection systems and coating repair programs.
Mr. Carlson has an extensive background in providing specialty consultants, sub-contractors and materials to handle unique project requirements and assist in peak loads. During his career he had the opportunity to work with a diversity of professional engineers, licensed contractors, environmental assessment and remediation specialists, well drilling contractors, manufacturers of various products, installers specializing in directional boring and technicians specializing in natural gas leak surveys and close interval electronic surveys. Based on this experience and association with these professionals, Mr. Carlson can select from the most qualified experts, materials and contractors to handle virtually any type of corrosion control activity.
Eric Langelund
The project engineer for CPM, Eric S. Langelund, has worked in the corrosion industry for the past ten (10) years. Mr. Langelund has a Bachelor of Science Degree from the University of Wisconsin, Milwaukee in Materials Engineering. He currently holds his Engineer-in-Training certificate and is also a NACE International certified Cathodic Protection Specialist. His experience primarily consists of providing corrosion control consulting services for new and existing cathodic protection system installations. These services include planning, designing, installing and troubleshooting cathodic protection systems for jet A fuel, natural gas, water, sewer and oil piping along with aboveground and underground storage tanks. Mr. Langelund also has extensive experience supervising technicians, writing and reviewing project specifications, laying out and reviewing project drawings, preparing submittals, bills of materials and reports.
Specific cathodic protection technical expertise for Mr. Langelund includes conducting stray DC current interference analysis, QA/QC inspection during construction, pipeline casing testing, pipeline coating investigations, ultrasonic thickness testing, potential surveys (including close interval), direct current voltage gradient (DCVG) survey, continuity and electrical isolation testing, soil resistivity measurements and current requirement testing.
Mr. Langelund is also fluent in Spanish.
While with CPM, Mr. Langelund has brought not only his technical skills, but also pipeline industry contacts. These contacts include petroleum pipeline companies along with other pipeline industry vendors. we obviously hope to use some of these contacts in our efforts to launch a successful distributorship of pipeline coating materials.
more
Cathodic Protection Management, Inc (CPM) was established and incorporated in 1998 specializing in the management of cathodic protection systems. This includes the design and maintenance of sacrificial and impressed current cathodic protection systems, including conventional, semi deep and deep anode groundbed systems, monitoring stations, test coupons, remote external and internal corrosion control monitoring and mitigation. In 1999 CPM became a full service corrosion control company offering engineering services, materials, and installation capabilities.
Expertise
CPM consists of individuals with sales and technical expertise in the corrosion control industry. Our staff is comprised of a balance of book and field educated personnel. Members of our staff have work experience with AC Power Generation, Transmission and Distribution, Natural Gas Transmission and Distribution, Quality Assurance/Quality Control and Engineering Consulting.
The CPM Staff also included personnel with the following direct assessment specialty credentials: Magnetic (Mag) Particle Inspection, Visual Inspection, Penetrant Inspection, Ultrasonic Inspection and Certified Welding Inspection QC1-96
At CPM, our specialties are the tasks that are consideered difficult, i.e. Stray DC current interference, Induced AC Voltage, MIC, etc.
External Corrosion Direct Assessment (ECDA) tasks are performed in accordance with National Association of Corrosion Engineers, (NACE) international and the Gas Technology Institute (GTI) as required.
Pipeline surveys that we routinely perform include but are not limited to: Close Interval (Potential) Survey (CIS or CIPS), Direct Current Voltage Gradient (DCVG), Soil Resistivity, GPS, and Depth of Cover (DOC).
Additional corrosion control/cathodic protection surveys that we perform include: Aboveground Storage Tanks, Undergound Storage Tanks, Remote Monitoring, Heat Exchangers along with other metallic Structures.
We perform inspections at Tank Farms, Refineries, Chemical Plants, Water Treatment Plants, Waste Water Treatment Plants, Water Towers, Lift Stations and Buried Vaults.
Experience
Current company activities include managing cathodic protection systems, installation projects, inspection of cathodic protection materials and installation during construction, technical assistance and consulting for various cathodic protection systems, provide QA/QC and packaging for sacrificial anodes, and material supplier to utilities, gas, petroleum and water pipeline owners, operators and contractors. Our warehouse located in Chicago is centrally located to provide materials support for the entire Midwest.
At the present time Cathodic Protection Management, Inc is associated with Manufacturers, Professional Engineers, National Association of Corrosion Engineers (NACE), Corrosion Specialists and Certified Corrosion Control Technicians.
The Principals
The principals of CPM are William P. Carlson and Eric S. Langelund.
William "Bill" CarlsonThe owner and president of CPM, William P. Carlson has worked exclusively in the corrosion control community for the past thirty years. Previously to forming CPM, he was a co-founder of the largest publicly traded Corrosion Control Company in the world where he served a s a senior Vice-President and member of the Board of Directors. During his tenure, he directed their slaes, engineering, construction and cathodic protection maintenance and materials manufacturing operations at five locations located in the Midwest. He managed the larges regional operation of the corporation with more than 100 technical and support staff.
During his career he introduced numerous new and upgraded products, established a technical sales training program complete with sales manuals and point of sale support materials, and established distributors in specific markets. Mr Carlson also excelled in specification preparation that resulted in proprietary and sole source procurment of products and services, a specialty was the "packaged systems" whereby complete systems were promoted which usually reduced or eliminated the use of "look alike" products. Introducing new products or services were promoted trrough seminars and "brown bag" presentations to decision making employees or specifiying engineers. ut e URD market, the water and wastewater market and the radio and microwave towers market are just a few that did not regularly use cathodic protection but were developed under Mr. Carson's direction and continue to be exceptionally profitable.
Introducing new products, such as Link Seals, reintroducing upgraded products such as aerial surveillance equipment and remote monitoring and pipeline coating acceptance are areas where Mr. Carlson displayed his talents. Selling the full line proved to be effective and profitable.
Mr. Carlson has extensive experience in the application of corrosion control to various structures, unique design concepts, product serviceability and reliability, installation procedures and monitoring and maintenance of cathodic protection systems. He is certified and licensed in the States of Wisconsin as an Underground Tank System Installer, Illinois in Underground Storage Tank Cathodic Protection and Indiana as an Undergound Storage Tank Installer and Retrofitter.
He holds and shares in several patents in the corrosion control field. He is a 30-year member of the National Association of Corrosion Engineers, (NACE), twice served on the NACE Board of Directors and received numerous awards including NACE's Outstanding Service Award. Mr. Carlson has participated in training courses and technical presentations at various Universities, is a guest lecturer at several Midwest Universities and is a preferred speaker at the University of Wisconsin Aboveground Storage Tank Program. Mr .Carlson has served on the O'Hare Corrosion Control Committee, Chicago Area Joint Electrolysis Committee and serves as a representative on the Joliet Underground Corrosion Control Committee.
While serving in his various positions, Mr. Carlson's expertise includes the application of cathodic protection to various facilities including cross country pipeline, bulk storage tank farms, refineries, missile silos, undergound concentric cables, tower anchors, underground storage tanks, steel lift stations and water storage tanks. He has supervised engineering and construction departments on projects located through the Midwest and has been involved in the installation of cathodic protection systems and coating repair programs.
Mr. Carlson has an extensive background in providing specialty consultants, sub-contractors and materials to handle unique project requirements and assist in peak loads. During his career he had the opportunity to work with a diversity of professional engineers, licensed contractors, environmental assessment and remediation specialists, well drilling contractors, manufacturers of various products, installers specializing in directional boring and technicians specializing in natural gas leak surveys and close interval electronic surveys. Based on this experience and association with these professionals, Mr. Carlson can select from the most qualified experts, materials and contractors to handle virtually any type of corrosion control activity.
Eric Langelund
The project engineer for CPM, Eric S. Langelund, has worked in the corrosion industry for the past ten (10) years. Mr. Langelund has a Bachelor of Science Degree from the University of Wisconsin, Milwaukee in Materials Engineering. He currently holds his Engineer-in-Training certificate and is also a NACE International certified Cathodic Protection Specialist. His experience primarily consists of providing corrosion control consulting services for new and existing cathodic protection system installations. These services include planning, designing, installing and troubleshooting cathodic protection systems for jet A fuel, natural gas, water, sewer and oil piping along with aboveground and underground storage tanks. Mr. Langelund also has extensive experience supervising technicians, writing and reviewing project specifications, laying out and reviewing project drawings, preparing submittals, bills of materials and reports.
Specific cathodic protection technical expertise for Mr. Langelund includes conducting stray DC current interference analysis, QA/QC inspection during construction, pipeline casing testing, pipeline coating investigations, ultrasonic thickness testing, potential surveys (including close interval), direct current voltage gradient (DCVG) survey, continuity and electrical isolation testing, soil resistivity measurements and current requirement testing.
Mr. Langelund is also fluent in Spanish.
While with CPM, Mr. Langelund has brought not only his technical skills, but also pipeline industry contacts. These contacts include petroleum pipeline companies along with other pipeline industry vendors. we obviously hope to use some of these contacts in our efforts to launch a successful distributorship of pipeline coating materials.
more
laying a pipeline with corrosion protection
Corrosion Problems in Oil Industry Need More Attention
18th February 2003Dr A K Samant, Suptdg. Chemist, Mud Services, Assam Asset, Sivasagar, Assam
Corrosion is becoming an increasing threat to the integrity of oil field structures including pipelines, casing and tubing world wide.
Failure of any of these systems could have disastrous consequences and may lead to safety problems both in onshore and offshore. In oil field, if corrosion is left unattended, it may cause failure either due to leaks in pipelines or collapse of well casing and tubing and thus significant losses of the products transported can take place. Plants would have to be shut down plant, contamination of products might take place and pollution and fire are possibilities. Since corrosion can not be eliminated entirely, the aim should be to reduce the corrosion risk to an acceptable level. Condition assessment of oil field installation, therefore, is of great concern not only in India, but all over the world. There is a need for uniform, consistent and reliable guidelines for assessment of health of existing structures, pipelines and well casings. Considering the importance of pipelines and well casings, a brief analysis of both the systems has been carried out. Protection Of PipelinesPipelines are considered as the safest and most economical method of delivering hydrocarbon products from one place to other both in offshore and onshore. However, like all other engineering plants, they are also susceptible to failure due to various reasons. In India, pipeline failures are reported both in onshore and offshore. Three-phase well fluid carrying pipelines, containing both water and corrosive gases such as carbon dioxide and hydrogen sulphide, are particularly susceptible to internal corrosion. When a new pipeline is planned to be installed, its integrity is assured by providing sufficient wall thickness, suitable material and quality control and by adopting suitable corrosion protection system. Pipelines are susceptible to both internal as well as external corrosion. The most common external corrosion protection system for pipelines is corrosion coating and installation of cathodic protection system. To achieve the effective protection, it is necessary to adopt both the above techniques together. For internal corrosion protection, mostly chemicals like corrosion inhibitors are used. However, when pipeline is found contaminated with bacteria, biocides and bactericides are used. Biocides are those chemicals, which kills the bacteria completely, whereas bactericides are chemicals, which suppress the growth of biological activity up to a permissible limit. In Indian offshore as well as onshore, fluid flowing through pipelines, have been found to be contaminated with bacteria. Failure investigation of some of the leaked pipelines showed bacterial induced corrosion as a major factor for pipeline leaks in the Indian offshore and onshore. Some operators are also using internal protective coatings as protective measure. In both the situations, quality of material used and application techniques play important role for complete protection against corrosion. This should be followed by a systematic operation of the line in such a way that they do not deviate from operational requirement specified by codes/standards. Pipelines deterioration can be minimised by periodic monitoring of pipelines using suitable measures like corrosion probes, coupons, fluid analysis and online monitoring loop lines etc. Further, maintenance measure should be both cost effective and prevent failure. Figure 1 & 2 shows diagrammatic representation of a leaking pipeline segment and use of clamp to stop leakage.
Periodic Assessment Of Pipeline ConditionFor the periodic assessment of the lines following techniques should be used: 1. Evaluation of corrosivity of fluid flowing through pipeline by corrosion monitoring probes 2. Monitoring of efficacy of cathodic protection and coating damage assessment 3. Measurement of wall thickness / metal loss in critical areas 4. Condition assessment based on analytical techniques. The purpose of above studies is to identify the most critical segment of the pipeline and detect the damage or defects before they cause serious problems. For prediction of corrosivity of flowing fluids, software is available. These software works based on the fluid parameters and operating data. Analysis of oil associated water and gas for presence of carbon di oxide and hydrogen sulphide gas, sulphate reducing bacteria and acid producing bacteria, bicarbonates and chloride ions, flow velocity, operating pressure and temperature etc. helps in assessing the corrosivity of fluid. Monitoring of efficacy of cathodic protection system and survey for detection of coating damage are performed to assess the external condition of pipeline. As mentioned earlier, pipeline failures are possible and reported, both due to internal as well as external factors. Therefore, both internal as well as external monitoring of pipeline is required for complete health assessment. The monitoring methods may be used in combination for more realistic picture of corrosion in the pipeline. Further following information should be maintained in the form of records before installation and removal of corrosion monitoring devices: 1. Operating pressure and temperature 2. Fluid analysis results like a) Water content and its composition b) CO2 and H2S content c) Number and types of bacteria 3. Flow rate 4. Pigging frequency 5. Corrosion inhibitor and bactericides dose, frequency and injection methods Corrosion control by protective coating supplemented with cathodic protection shall be provided in the initial design based on the study of environment and soil condition along the pipeline route and maintained during the service life of the pipeline system. During construction and initial phase of operations, temporary arrangement should be made to protect the pipeline cathodically. However, the pipeline system shall be permanently protected within a year of pipeline installation. External coating must be properly selected and applied. Coated pipeline shall be carefully handled and installed. Continuous potential logging (CPL) survey, once in five years or whenever inadequate CP is observed, should be carried out Pearson Survey, Direct Current Voltage Gradient (DCVG), Current Attenuation Test (CAT) Surveys to elaborate the coating defects should also be carried as and when required. Isolation of cathodically protected pipeline is recommended to minimise current requirement, facilitate testing and trouble shooting and improve current distribution. When two or more pipelines are laid in the same ROW / ROU periodical interference survey shall be conducted and suitable mitigating measures to be taken to avoid interference between the lines. Where stray current is known to exist which adversely affects the level of CP of the pipeline, additional monitoring should be carried out on monthly basis. Underground pipelines are generally routed under roads and railways in steel casings. Wherever these are essential, casing pipes should be electrically isolated from the carrier pipes by providing isolating spacers. The isolating spacers should be designed and spaced to withstand the loads caused by the movement of the carrier pipe under operational conditions. Periodic Pigging Of PipelinePigging should not only be used to remove scales and wax from internal pipe wall but effort should be to remove bacterial colonies, corrosion deposits by using suitable scrapers, and to facilitate the corrosion inhibitor film formation, thereby to reduce under deposit corrosion. Chemical injection in conjunction with pigging programme offers an efficient and cost effective technique to control internal corrosion in pipelines that carry oil with high water percentage and low flow velocities. Intelligent Pigging For Safe Operation Of PipelineIntelligent or smart pigs can detects and measure the pipe wall defects such as corrosion, weld defects and cracks. The use of intelligent pigs for inspection of pipelines has increased considerably. The most commonly used intelligent pigs use magnetic flux leakage (MFL) technique to detect corrosion pits and planar and axially oriented cracks. However, advance MFL based intelligent pig has been used to detect circumferentially oriented cracks in both oil and gas pipelines. Ultra sonic based intelligent pigs require a liquid coupling between transducers and the pipe wall and therefore restricts their use in gas lines unless they are run in a slug of liquid or the coupling has been attached by some means. The primary use of the results from an inline inspection using intelligent or smart pigging is not restricted to find out the health of the pipeline, but to calculate the maximum allowable operating pressure (MAOP) at which the pipeline can still safely be operated. Protection Of Well Casing & TubingConditions such as poor cementing, large variations in the casings metallic composition, fluid salinities, dissolved corrosive gases, etc. have been recognized as corrosion promoters in well casing and tubing. Downhole corrosion monitoring, to evaluate both - the extent of metal losses and the corrosion rate, is vital as corrosion initiation and propagation can not be predicted from theoretical estimates. Drill pipes are subjected to corrosion in the hole, standing in the rig, laying on the rack or during movement of location. Down hole corrosion is more detrimental, as it occurs in conjunction with cyclic loading. Large number of corrosion cells are formed on drill pipe and well casing surface due to material inhomogeniety and because of the presence of deposits or scales. Further, local corrosion may also be occurred due to formation of concentration cells causing pitting. Because of the presence of hydrogen sulphide and dissolved salts, corrosion fatigue and stress corrosion cracking are a major cause of drill pipe failures. Sulfide stress corrosion cracking is most common in presence of hydrogen sulfide and when the stress in the drill pipe and casing is higher. Corrosion inhibitors and biocides are used to control the corrosion and bacterial growth, but there is no assurance that they will do so, since a packer fluid remains in place until it is necessary to do remedial work on the well, which may not be for years. Therefore, leaving a water base drilling mud / brine in the hole as a packer fluid may result in development of casing or tubing leaks in the course of time. Similarly, on external surface of casing, generation of hydrogen sulphide by bacteria and high concentration of sulfates results in deterioration of cement. Corrosive fluid, water, microorganisms etc. penetrates the poor permeable cement and then able to attack the external casing metal resulting in leakage. Once leaks have started, corrosive water enters the well and can attack the casing wall. In Indian Offshore, well casing corrosion is a matter of serious concern. Some of the wells were cased more than two decades ago. Well casing survey of these wells is the prime concern. The some of the tools employed for well casing and tubing corrosion survey are Casing Inspection Tool (CIT), Multi-frequency Electromagnetic Thickness Tool (METT), Digital Cement Evaluation Tool (CET-D) & Corrosion and Protective Evaluation Tool (CPET). NACE standard RP-01-86 describes four methods or criteria for designing and evaluating cathodic protection systems for well casings. They are downhole potential profile surveys, E/Log i polarisation curves, mathematecal modelling combined with the measured wellhead potential, and average current density over the casing. Each technique has its advantages and disadvantages. None of the techniques gives direct information in polarisation of the casing surface at depth. Potential profile survey is the only technique in which the flow of protection current at depth can be confirmed. Downhole potential profile measurements have been used for a number of years in evaluating and optimising well casing cathodic protection. Recent advances in instrumentation have enabled high-resolution potential difference and casing resistance measurements to be recorded. As a consequence, current and current density profiles are free of the ambiguities present in earlier measurements. ConclusionCorrosion control is an important consideration. The periodic monitoring techniques and analytical assessment of corrosion severity is very important and critical since it provides the direction to ensure proper utilisation of materials and corrosion control methodologies. Therefore, correct and appropriate condition assessment techniques should be used to avoid premature failure and ensure maximum safety. Contact The Author: aksamant@ongc.in, aksamant@rediffmail.com
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(WO/1998/006552) PROTECTION OF PIPELINE JOINT CONNECTIONS
Biblio. Data
Description
Claims
National Phase
Notices
Documents
Note: OCR Text
Note: Text based on automatic OpticalCharacter Recognition processes. Pleaseuse the PDF version for legal matters
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PROTECTION OF PIPELINE JOINT CONNECTIONS This invention relates to pipeline joint protection. More specifically, the invention provides a method and an apparatus for protecting exposed pipe joints on weight coated pipelines used in offshore applications. It has been a common practice in the offshore pipeline industry to use weight coated pipe for pipelines which were to be located on ocean floors or other underwater surfaces. The weight coats traditionally used have been made of dense materials, frequently concrete, applied several inches thick around the circumference of the pipe. The weight coats were to protect the pipeline and also to provide sufficient weight to maintain the pipeline submerged in a non-buoyant condition.
The weight coats usually have been applied to the full length of the pipe except for a short distance, usually about one foot from the end of each pipe section. The end portion of the pipe remained without the weight coat to facilitate welding sections of the weight coated pipe together to make up the pipeline. Sections of pipe have been placed on a barge and welded sequentially onto preceding sections forming a pipeline extending from the barge. The newly formed pipeline was on rollers and as the barge moved forward, the pipeline would be carried over the rollers, lowered, and laid on the bed of the body of water.
The portions of the pipe without the weight coat had a corrosion coating applied to the surface of the pipe to prevent the pipe from corroding due to exposure to the elements. Generally, the corrosion coatings used were heat shrinking tape or a fusion bonded epoxy. After the sections of pipe were welded together various techniques were used to protect the corrosion coating on the exposed portions of pipe around each joint.
One technique was to wrap sheet metal over the weight coating adjacent the exposed portion of the pipe and band the sheet metal in place with metal bands. Generally, a 26 to 28 gauge zinc coated sheet metal was used. The space between the pipe and sheet metal was then filled with a molten mastic which would solidify as it cooled. However, in most cases, the pipeline had to be in a condition for handling immediately after the sleeves were filled so that the laying of the pipeline could proceed without delays. The mastic filling did not set or harden to a sufficiently strong material within the required
-->time to allow further processing of the pipe and the mastic would leech out into the water if the pipeline was lowered before the mastic was adequately cured.
An additional problem associated with this technique was that the banding used to hold the sheet metal in place, as well as the sheet metal itself, would corrode after the pipejoint was underwater for a period of time. Once the banding corroded, the sharp ends of the sheet metal would come loose from the pipe. This created a particular problem in areas where commercial fishing was taking place. The sharp sheet metal ends would cut fishing nets which were being dragged over the pipeline by fishing trawlers. The destruction of fishing nets by the loose sheet metal created severe financial problems for fishing industries. In some cases, corrosion resistance banding, such as stainless steel banding, was used to avoid this problem, but it was more expensive and also subject to eventual failure.
Other techniques replaced the mastic filler with other types of materials. In the method disclosed in U.S. Patent No. 5,328,648, the exposed portion of pipe was covered with a mold which was then filled with a filler material. The filler materials were granular or paniculate matter such as gravel or iron ore which would not pack solidly or uniformly. Elastomeric polyurethanes or polyureas were then injected into the mold in an attempt to fill the interstices between the granular fill materials. After the polymer components had reacted completely the mold would be removed from the surface of the infill. This method could be difficult to use when the joint protection system was applied aboard the lay barge because the filler material, often gravel, had to be loaded and carried onto the barge. Additionally, there was often a lack of uniformity in the finished infill resulting from uneven polymer distribution in the filler material which created voids. Such voids could leave the corrosion coating exposed and subject to damage from fishing trawler nets or other objects moving through the water which might encounter the submerged pipeline.
Another technique, disclosed in U.S. Patent 4,909,669, involved wrapping the exposed portions of pipe with a thermoplastic sheet. The sheet overlapped the ends of the weight coat adjacent the exposed joint and was then secured in place by screws, rivets, or straps. To increase the rigidity and impact resistance this joint protection system required the installation of reinforcing members such as plastic bars or tubes to the interior of the
-->sheet. The reinforcement bars or tubes either had to be precut and stored on the barge or else cut to the required fitting form as part of the installation process on the barge. This required additional handling and made the installation process more difficult.
Another method of reinforcing this joint protection system was to fill the lower portion of the annular space between the pipe and the plastic sheet with a material such as pre-formed foam half shells. When foam half shells were used in the lower portion of the annular space to provide support, the upper portion of the joint and the corrosion coating was in effect protected only by the plastic sheet enclosing the upper portion which had no foam covering. This could cause a particular problem if the pipelines were located where they would encounter the drag lines or trawler boards attached to the nets of fishing trawlers. The corrosion coating on the upper portion of the pipe joint could become damaged by this type of towed object.
An additional problem with this joint protection system occurred when pipelines were laid in shallow waters, i.e., less than about 200 feet deep. Pipelines in shallow waters were often buried by using high pressure water jets which were directed at the ocean floor where the pipelines were to be buried. The water jets would wash out a trench into which the pipelines would be dropped for burial. The joint protection system could be damaged when the water jets came in contact with the pipeline joint because the plastic sheet over the top of the pipejoint was not reinforced. The present invention provides a method and an apparatus for mechanically protecting exposed pipeline joint sections. The method allows quick installation on lay barges where pipeline sections are welded together and does not require a long cure time before handling. The method for protecting exposed pipeline joint sections begins by foπning a pliable sheet of cover material into a cylinder which is fitted over the exposed portions of the joint connection. The longitudinal end portions of the pliable sheet of cover material overlap the adjacent edges of the weight coating. Side edge portions of the sheet of cover material forming the cylinder are then overlapped tightly such that an annular pocket is formed about the exposed joint section. The outside side edge is then sealed to the surface of the sheet of cover material, completely encasing the exposed pipe and the annular pocket or space. Polyurethane chemicals are then injected into the empty annular space where they react to form a high density foam which fills the annular space.
-->Other polymerizing or hard setting fluid compounds such as marine mastics, quick setting concretes, polymers, or elastomeric compounds may also be used to fill the empty annular space.
The present invention provides the joint section of an underwater pipeline with mechanical protection and abrasion resistance that is not subject to corrosion problems, will not damage fishing nets, and will not be damaged by water jets used for pipeline burial.
A better understanding of the invention can be obtained when the detail description set forth below is reviewed in conjunction with the accompanying drawings, in which: Figure 1 is a depiction of two sections of weight coated pipe which have been joined by welding;
Figure 2 is a pliable sheet of cover material formed in a cylinder which is used to enclose the exposed joint section;
Figure 3 is a longitudinal view, showing the pliable sheet of cover material wrapped and sealed around the exposed joint section;
Figure 4 is a longitudinal cross section showing the joint section after the joint protection system has been applied.
Fig. 1 shows a pipeline 10 formed by welding together two pipe sections 12 & 12A each of which are covered by a weight coat 14 & 14 A, respectively. The weight coat 14 & 14A, which is formed from concrete or other suitable materials, completely covers the pipe sections 16 & 16A circumferentially and longitudinally except for a portion of each pipe end 18 & 18A of the pipe section 16 & 16A. The pipe ends 18 & 18A are left exposed to facilitate welding of the two pipe sections 12 & 12A together as sections of a pipeline. However, these exposed pipe ends 18 & 18A leave gaps of pipe not coated with weight coat in the pipeline 10, which are covered only by a corrosion coating 24.
The method of the present invention begins with installing a cover material 30 which is used to enclose and provide structural protection for the exposed corrosion coating 24 on the pipe end 18 & 18 A. As shown in Fig. 2, the preferred method uses a cover material 30 which is pliable, but strong, and can be formed into a cylindrical shape. The preferred cover material 30 is formed from high density polyethylene, however, other thermoplastic materials may be used. The pliable cover material 30 should be at least
-->about 0.02 inches thick and may be considerably thicker if a stronger support and impact resistance is desired. Water depth, pipe size, pipe weight and other factors may dictate the use of a cover material 30 which is up to about 1/2 inch in thickness. The cover material 30 may be a flat sheet or may be preformed into a cylindrical shape. The pliable sheet of cover material 30 is wrapped into a cylindrical shape around the exposed pipe ends 18 & 18A such that the inside diameter of the cylinder of cover material 30 is about the same as the outside diameter of the weight coat 14 & 14A on the pipeline 10. The cover material 30 should be long enough to overlap the adjacent edges 22 & 22 A of both sides of the weight coating 14 & 14A by several inches to allow the weight coating 14 & 14A to act as a structural support for the cover material 30. Once the cover material 30 is fitted over the adjacent edges 22 & 22A of the weight coat 14 & 14A, the side edges 34 and 36 of cover material 30 are tightly pushed together such that the side edges 34 & 36 overlap. The cover material 30 can be tightened down and held in place with cinch belts. The outside edge 34 is then sealed to the surface of the cover material 30 and a sealed sleeve 40 is formed.
The cover material 30 can be sealed by plastic welding the outside edge 34 onto the surface of the cover material 30, forming a longitudinally extending plastic weld the entire length of the cover material 30 as shown in Fig 3. Other means of sealing such as heat fusion, riveting, gluing, taping, or banding can also be used to seal the cover material 30.
The sealed cover material sleeve 40 forms a protective barrier around the exposed portion of pipe 18 & 18A which remains as a permanent part of the pipeline 10. An annular space 44 is formed around the pipe 18 & 18A by installing the cover material sleeve 40. This annular space 44 is filled by first cutting a hole 38 in the sealed cover material sleeve 40 and thereafter injecting fluid joint filler system components through the hole 38 and into the annular space 44.
The hole 38 may be drilled or cut or otherwise made in the sealed cover material sleeve 40 to thereafter allow unreacted joint filler system components to be injected into the annular space 44. The hole 38 may be precut into the cover material 30 prior to installation on the weight coated pipeline 10 or may be cut after the sealed cover material sleeve 40 is in place. The diameter of the hole 38 to be drilled is dependent upon the
-->particular type of mixing head used to inject the joint filler system components. Industry standard or conventional injection heads are acceptable.
In the preferred method, the annular space 44 is filled with a high density foam by injecting components for a rapid setting polyurethane system through the hole 38 with a mixing head. The polyurethane foam 52 serves as a shock absorber and protects the corrosion coating on the pipe 18 & 18A. Also, because the foam 52 is open celled, it can absorb water and increase the ballast effect for the pipeline 10. Alternatively, other polymerizing or hard setting compounds such as marine mastics, quick setting concretes, polymers, or elastomeric compounds may be used to fill the empty annular space. Preferably, any alternative filler material is quick hardening, such that the process of laying the pipeline is not inhibited.
The preferred polyurethane system used to form the protective high density foam 52 in this process is a combination of a isocyanate and a polyol system which when reacted rapidly cures and forms high density open celled polyurethane foam which resists degradation in sea water. The preferred isocyanate is a polymeric form of diphenylmethane diisocyanate as manufactured by Bayer Corp. The preferred polyol system is a mixture of multifunctional polyether and/or polyester polyols, catalysts for controlling the reaction rate, surfactants for enhancing cell formation, and water for a blowing agent. Acceptable blended polyol system are manufactured by Dow Chemical Co., Bayer Corp., and others.
The preferred polyurethane system produces a foam with a density of about 8 to 10 pounds per cubic foot and has about eighty percent or greater open cells. The compressive strength of the preferred polyurethane foam is approximately 150 psi or greater at 10 percent deflection and 1500 psi or greater at 90 percent deflection. Reaction of the preferred polyurethane system components can be characterized by a 15 to 20 second cream time, the time between discharge from the mixing head and the beginning of the foam rise, a 40 to 50 second rise time, the time between discharge from the mixing head and the complete foam rise, and a 180 to 240 second cure time, the time required to develop the polymer strength and dimensional stability. The cover material sleeve 40 acts as a mold and holds the foam 52 in place until it is completely cured. As shown in Figure 4, this polyurethane foam 52 completely fills
-->the annular space 44 without leaving significant void areas. No additional filler materials are needed to be used in conjunction with the polyurethane foam 52. The polyurethane foam 52 should completely fill the annular space 44 and protrude to some extent upward through the hole 38 on the sealed cover material sleeve 40. Fig. 4 shows the completed protective covering of the joint protection system according to the present invention. The sealed cover material sleeve 40 together with the polyurethane foam 52 provide a protective system which protects the exposed pipe 18 & 18A and the corrosion coating 24 during handling and laying of d e pipeline 10 and continues to provide protection from damage due to drag lines or trawler boards attached to fishing trawler nets. Further, the sealed cover material sleeve 40 is not subject to the corrosion problems of prior art systems and therefore does not create a underwater hazard or a danger to fishing nets. Additionally, die protective system provided by the present invention acts to deflect the high pressure water jets used to bury pipelines in shallow waters which have resulted in damage to the corrosion coating on pipe joints protected by prior art systems.
From the foregoing, it can be seen that the present invention provides a method and apparatus for protecting the corrosion coating 24 on exposed pipeline joints such as 12 & 12A on weight coated pipelines 10 used in offshore applications. The method allows quick installation on a lay barge where pipeline sections are being welded together for offshore installation. The corrosion coating 24 on the pipeline joint connections 18 & 18A which have no weight coating is protected by forming a pliable sheet of polyethylene into a cylindrical cover material sleeve 40 over the pipeline joint connection. Polyurethane chemicals are used to react and form a high density foam 52 which fills the annular space 44 between the pipe 18 & 18A and the cover material sleeve 40. The cover material sleeve 40 and the foam 52 work together to protect the joint connection.
It should be understood that there can be improvements and modifications made of the embodiments of the invention described in detail above without departing from the spirit or scope of the invention as set forth in the accompanying claims.
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CATHODIC PROTECTION OF SUB SEA PIPELINES
18th February 2003Dr A K Samant, Suptdg. Chemist, Mud Services, Assam Asset, Sivasagar, Assam
Corrosion is becoming an increasing threat to the integrity of oil field structures including pipelines, casing and tubing world wide.
Failure of any of these systems could have disastrous consequences and may lead to safety problems both in onshore and offshore. In oil field, if corrosion is left unattended, it may cause failure either due to leaks in pipelines or collapse of well casing and tubing and thus significant losses of the products transported can take place. Plants would have to be shut down plant, contamination of products might take place and pollution and fire are possibilities. Since corrosion can not be eliminated entirely, the aim should be to reduce the corrosion risk to an acceptable level. Condition assessment of oil field installation, therefore, is of great concern not only in India, but all over the world. There is a need for uniform, consistent and reliable guidelines for assessment of health of existing structures, pipelines and well casings. Considering the importance of pipelines and well casings, a brief analysis of both the systems has been carried out. Protection Of PipelinesPipelines are considered as the safest and most economical method of delivering hydrocarbon products from one place to other both in offshore and onshore. However, like all other engineering plants, they are also susceptible to failure due to various reasons. In India, pipeline failures are reported both in onshore and offshore. Three-phase well fluid carrying pipelines, containing both water and corrosive gases such as carbon dioxide and hydrogen sulphide, are particularly susceptible to internal corrosion. When a new pipeline is planned to be installed, its integrity is assured by providing sufficient wall thickness, suitable material and quality control and by adopting suitable corrosion protection system. Pipelines are susceptible to both internal as well as external corrosion. The most common external corrosion protection system for pipelines is corrosion coating and installation of cathodic protection system. To achieve the effective protection, it is necessary to adopt both the above techniques together. For internal corrosion protection, mostly chemicals like corrosion inhibitors are used. However, when pipeline is found contaminated with bacteria, biocides and bactericides are used. Biocides are those chemicals, which kills the bacteria completely, whereas bactericides are chemicals, which suppress the growth of biological activity up to a permissible limit. In Indian offshore as well as onshore, fluid flowing through pipelines, have been found to be contaminated with bacteria. Failure investigation of some of the leaked pipelines showed bacterial induced corrosion as a major factor for pipeline leaks in the Indian offshore and onshore. Some operators are also using internal protective coatings as protective measure. In both the situations, quality of material used and application techniques play important role for complete protection against corrosion. This should be followed by a systematic operation of the line in such a way that they do not deviate from operational requirement specified by codes/standards. Pipelines deterioration can be minimised by periodic monitoring of pipelines using suitable measures like corrosion probes, coupons, fluid analysis and online monitoring loop lines etc. Further, maintenance measure should be both cost effective and prevent failure. Figure 1 & 2 shows diagrammatic representation of a leaking pipeline segment and use of clamp to stop leakage.
Periodic Assessment Of Pipeline ConditionFor the periodic assessment of the lines following techniques should be used: 1. Evaluation of corrosivity of fluid flowing through pipeline by corrosion monitoring probes 2. Monitoring of efficacy of cathodic protection and coating damage assessment 3. Measurement of wall thickness / metal loss in critical areas 4. Condition assessment based on analytical techniques. The purpose of above studies is to identify the most critical segment of the pipeline and detect the damage or defects before they cause serious problems. For prediction of corrosivity of flowing fluids, software is available. These software works based on the fluid parameters and operating data. Analysis of oil associated water and gas for presence of carbon di oxide and hydrogen sulphide gas, sulphate reducing bacteria and acid producing bacteria, bicarbonates and chloride ions, flow velocity, operating pressure and temperature etc. helps in assessing the corrosivity of fluid. Monitoring of efficacy of cathodic protection system and survey for detection of coating damage are performed to assess the external condition of pipeline. As mentioned earlier, pipeline failures are possible and reported, both due to internal as well as external factors. Therefore, both internal as well as external monitoring of pipeline is required for complete health assessment. The monitoring methods may be used in combination for more realistic picture of corrosion in the pipeline. Further following information should be maintained in the form of records before installation and removal of corrosion monitoring devices: 1. Operating pressure and temperature 2. Fluid analysis results like a) Water content and its composition b) CO2 and H2S content c) Number and types of bacteria 3. Flow rate 4. Pigging frequency 5. Corrosion inhibitor and bactericides dose, frequency and injection methods Corrosion control by protective coating supplemented with cathodic protection shall be provided in the initial design based on the study of environment and soil condition along the pipeline route and maintained during the service life of the pipeline system. During construction and initial phase of operations, temporary arrangement should be made to protect the pipeline cathodically. However, the pipeline system shall be permanently protected within a year of pipeline installation. External coating must be properly selected and applied. Coated pipeline shall be carefully handled and installed. Continuous potential logging (CPL) survey, once in five years or whenever inadequate CP is observed, should be carried out Pearson Survey, Direct Current Voltage Gradient (DCVG), Current Attenuation Test (CAT) Surveys to elaborate the coating defects should also be carried as and when required. Isolation of cathodically protected pipeline is recommended to minimise current requirement, facilitate testing and trouble shooting and improve current distribution. When two or more pipelines are laid in the same ROW / ROU periodical interference survey shall be conducted and suitable mitigating measures to be taken to avoid interference between the lines. Where stray current is known to exist which adversely affects the level of CP of the pipeline, additional monitoring should be carried out on monthly basis. Underground pipelines are generally routed under roads and railways in steel casings. Wherever these are essential, casing pipes should be electrically isolated from the carrier pipes by providing isolating spacers. The isolating spacers should be designed and spaced to withstand the loads caused by the movement of the carrier pipe under operational conditions. Periodic Pigging Of PipelinePigging should not only be used to remove scales and wax from internal pipe wall but effort should be to remove bacterial colonies, corrosion deposits by using suitable scrapers, and to facilitate the corrosion inhibitor film formation, thereby to reduce under deposit corrosion. Chemical injection in conjunction with pigging programme offers an efficient and cost effective technique to control internal corrosion in pipelines that carry oil with high water percentage and low flow velocities. Intelligent Pigging For Safe Operation Of PipelineIntelligent or smart pigs can detects and measure the pipe wall defects such as corrosion, weld defects and cracks. The use of intelligent pigs for inspection of pipelines has increased considerably. The most commonly used intelligent pigs use magnetic flux leakage (MFL) technique to detect corrosion pits and planar and axially oriented cracks. However, advance MFL based intelligent pig has been used to detect circumferentially oriented cracks in both oil and gas pipelines. Ultra sonic based intelligent pigs require a liquid coupling between transducers and the pipe wall and therefore restricts their use in gas lines unless they are run in a slug of liquid or the coupling has been attached by some means. The primary use of the results from an inline inspection using intelligent or smart pigging is not restricted to find out the health of the pipeline, but to calculate the maximum allowable operating pressure (MAOP) at which the pipeline can still safely be operated. Protection Of Well Casing & TubingConditions such as poor cementing, large variations in the casings metallic composition, fluid salinities, dissolved corrosive gases, etc. have been recognized as corrosion promoters in well casing and tubing. Downhole corrosion monitoring, to evaluate both - the extent of metal losses and the corrosion rate, is vital as corrosion initiation and propagation can not be predicted from theoretical estimates. Drill pipes are subjected to corrosion in the hole, standing in the rig, laying on the rack or during movement of location. Down hole corrosion is more detrimental, as it occurs in conjunction with cyclic loading. Large number of corrosion cells are formed on drill pipe and well casing surface due to material inhomogeniety and because of the presence of deposits or scales. Further, local corrosion may also be occurred due to formation of concentration cells causing pitting. Because of the presence of hydrogen sulphide and dissolved salts, corrosion fatigue and stress corrosion cracking are a major cause of drill pipe failures. Sulfide stress corrosion cracking is most common in presence of hydrogen sulfide and when the stress in the drill pipe and casing is higher. Corrosion inhibitors and biocides are used to control the corrosion and bacterial growth, but there is no assurance that they will do so, since a packer fluid remains in place until it is necessary to do remedial work on the well, which may not be for years. Therefore, leaving a water base drilling mud / brine in the hole as a packer fluid may result in development of casing or tubing leaks in the course of time. Similarly, on external surface of casing, generation of hydrogen sulphide by bacteria and high concentration of sulfates results in deterioration of cement. Corrosive fluid, water, microorganisms etc. penetrates the poor permeable cement and then able to attack the external casing metal resulting in leakage. Once leaks have started, corrosive water enters the well and can attack the casing wall. In Indian Offshore, well casing corrosion is a matter of serious concern. Some of the wells were cased more than two decades ago. Well casing survey of these wells is the prime concern. The some of the tools employed for well casing and tubing corrosion survey are Casing Inspection Tool (CIT), Multi-frequency Electromagnetic Thickness Tool (METT), Digital Cement Evaluation Tool (CET-D) & Corrosion and Protective Evaluation Tool (CPET). NACE standard RP-01-86 describes four methods or criteria for designing and evaluating cathodic protection systems for well casings. They are downhole potential profile surveys, E/Log i polarisation curves, mathematecal modelling combined with the measured wellhead potential, and average current density over the casing. Each technique has its advantages and disadvantages. None of the techniques gives direct information in polarisation of the casing surface at depth. Potential profile survey is the only technique in which the flow of protection current at depth can be confirmed. Downhole potential profile measurements have been used for a number of years in evaluating and optimising well casing cathodic protection. Recent advances in instrumentation have enabled high-resolution potential difference and casing resistance measurements to be recorded. As a consequence, current and current density profiles are free of the ambiguities present in earlier measurements. ConclusionCorrosion control is an important consideration. The periodic monitoring techniques and analytical assessment of corrosion severity is very important and critical since it provides the direction to ensure proper utilisation of materials and corrosion control methodologies. Therefore, correct and appropriate condition assessment techniques should be used to avoid premature failure and ensure maximum safety. Contact The Author: aksamant@ongc.in, aksamant@rediffmail.com
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(WO/1998/006552) PROTECTION OF PIPELINE JOINT CONNECTIONS
Biblio. Data
Description
Claims
National Phase
Notices
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Note: OCR Text
Note: Text based on automatic OpticalCharacter Recognition processes. Pleaseuse the PDF version for legal matters
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PROTECTION OF PIPELINE JOINT CONNECTIONS This invention relates to pipeline joint protection. More specifically, the invention provides a method and an apparatus for protecting exposed pipe joints on weight coated pipelines used in offshore applications. It has been a common practice in the offshore pipeline industry to use weight coated pipe for pipelines which were to be located on ocean floors or other underwater surfaces. The weight coats traditionally used have been made of dense materials, frequently concrete, applied several inches thick around the circumference of the pipe. The weight coats were to protect the pipeline and also to provide sufficient weight to maintain the pipeline submerged in a non-buoyant condition.
The weight coats usually have been applied to the full length of the pipe except for a short distance, usually about one foot from the end of each pipe section. The end portion of the pipe remained without the weight coat to facilitate welding sections of the weight coated pipe together to make up the pipeline. Sections of pipe have been placed on a barge and welded sequentially onto preceding sections forming a pipeline extending from the barge. The newly formed pipeline was on rollers and as the barge moved forward, the pipeline would be carried over the rollers, lowered, and laid on the bed of the body of water.
The portions of the pipe without the weight coat had a corrosion coating applied to the surface of the pipe to prevent the pipe from corroding due to exposure to the elements. Generally, the corrosion coatings used were heat shrinking tape or a fusion bonded epoxy. After the sections of pipe were welded together various techniques were used to protect the corrosion coating on the exposed portions of pipe around each joint.
One technique was to wrap sheet metal over the weight coating adjacent the exposed portion of the pipe and band the sheet metal in place with metal bands. Generally, a 26 to 28 gauge zinc coated sheet metal was used. The space between the pipe and sheet metal was then filled with a molten mastic which would solidify as it cooled. However, in most cases, the pipeline had to be in a condition for handling immediately after the sleeves were filled so that the laying of the pipeline could proceed without delays. The mastic filling did not set or harden to a sufficiently strong material within the required
-->time to allow further processing of the pipe and the mastic would leech out into the water if the pipeline was lowered before the mastic was adequately cured.
An additional problem associated with this technique was that the banding used to hold the sheet metal in place, as well as the sheet metal itself, would corrode after the pipejoint was underwater for a period of time. Once the banding corroded, the sharp ends of the sheet metal would come loose from the pipe. This created a particular problem in areas where commercial fishing was taking place. The sharp sheet metal ends would cut fishing nets which were being dragged over the pipeline by fishing trawlers. The destruction of fishing nets by the loose sheet metal created severe financial problems for fishing industries. In some cases, corrosion resistance banding, such as stainless steel banding, was used to avoid this problem, but it was more expensive and also subject to eventual failure.
Other techniques replaced the mastic filler with other types of materials. In the method disclosed in U.S. Patent No. 5,328,648, the exposed portion of pipe was covered with a mold which was then filled with a filler material. The filler materials were granular or paniculate matter such as gravel or iron ore which would not pack solidly or uniformly. Elastomeric polyurethanes or polyureas were then injected into the mold in an attempt to fill the interstices between the granular fill materials. After the polymer components had reacted completely the mold would be removed from the surface of the infill. This method could be difficult to use when the joint protection system was applied aboard the lay barge because the filler material, often gravel, had to be loaded and carried onto the barge. Additionally, there was often a lack of uniformity in the finished infill resulting from uneven polymer distribution in the filler material which created voids. Such voids could leave the corrosion coating exposed and subject to damage from fishing trawler nets or other objects moving through the water which might encounter the submerged pipeline.
Another technique, disclosed in U.S. Patent 4,909,669, involved wrapping the exposed portions of pipe with a thermoplastic sheet. The sheet overlapped the ends of the weight coat adjacent the exposed joint and was then secured in place by screws, rivets, or straps. To increase the rigidity and impact resistance this joint protection system required the installation of reinforcing members such as plastic bars or tubes to the interior of the
-->sheet. The reinforcement bars or tubes either had to be precut and stored on the barge or else cut to the required fitting form as part of the installation process on the barge. This required additional handling and made the installation process more difficult.
Another method of reinforcing this joint protection system was to fill the lower portion of the annular space between the pipe and the plastic sheet with a material such as pre-formed foam half shells. When foam half shells were used in the lower portion of the annular space to provide support, the upper portion of the joint and the corrosion coating was in effect protected only by the plastic sheet enclosing the upper portion which had no foam covering. This could cause a particular problem if the pipelines were located where they would encounter the drag lines or trawler boards attached to the nets of fishing trawlers. The corrosion coating on the upper portion of the pipe joint could become damaged by this type of towed object.
An additional problem with this joint protection system occurred when pipelines were laid in shallow waters, i.e., less than about 200 feet deep. Pipelines in shallow waters were often buried by using high pressure water jets which were directed at the ocean floor where the pipelines were to be buried. The water jets would wash out a trench into which the pipelines would be dropped for burial. The joint protection system could be damaged when the water jets came in contact with the pipeline joint because the plastic sheet over the top of the pipejoint was not reinforced. The present invention provides a method and an apparatus for mechanically protecting exposed pipeline joint sections. The method allows quick installation on lay barges where pipeline sections are welded together and does not require a long cure time before handling. The method for protecting exposed pipeline joint sections begins by foπning a pliable sheet of cover material into a cylinder which is fitted over the exposed portions of the joint connection. The longitudinal end portions of the pliable sheet of cover material overlap the adjacent edges of the weight coating. Side edge portions of the sheet of cover material forming the cylinder are then overlapped tightly such that an annular pocket is formed about the exposed joint section. The outside side edge is then sealed to the surface of the sheet of cover material, completely encasing the exposed pipe and the annular pocket or space. Polyurethane chemicals are then injected into the empty annular space where they react to form a high density foam which fills the annular space.
-->Other polymerizing or hard setting fluid compounds such as marine mastics, quick setting concretes, polymers, or elastomeric compounds may also be used to fill the empty annular space.
The present invention provides the joint section of an underwater pipeline with mechanical protection and abrasion resistance that is not subject to corrosion problems, will not damage fishing nets, and will not be damaged by water jets used for pipeline burial.
A better understanding of the invention can be obtained when the detail description set forth below is reviewed in conjunction with the accompanying drawings, in which: Figure 1 is a depiction of two sections of weight coated pipe which have been joined by welding;
Figure 2 is a pliable sheet of cover material formed in a cylinder which is used to enclose the exposed joint section;
Figure 3 is a longitudinal view, showing the pliable sheet of cover material wrapped and sealed around the exposed joint section;
Figure 4 is a longitudinal cross section showing the joint section after the joint protection system has been applied.
Fig. 1 shows a pipeline 10 formed by welding together two pipe sections 12 & 12A each of which are covered by a weight coat 14 & 14 A, respectively. The weight coat 14 & 14A, which is formed from concrete or other suitable materials, completely covers the pipe sections 16 & 16A circumferentially and longitudinally except for a portion of each pipe end 18 & 18A of the pipe section 16 & 16A. The pipe ends 18 & 18A are left exposed to facilitate welding of the two pipe sections 12 & 12A together as sections of a pipeline. However, these exposed pipe ends 18 & 18A leave gaps of pipe not coated with weight coat in the pipeline 10, which are covered only by a corrosion coating 24.
The method of the present invention begins with installing a cover material 30 which is used to enclose and provide structural protection for the exposed corrosion coating 24 on the pipe end 18 & 18 A. As shown in Fig. 2, the preferred method uses a cover material 30 which is pliable, but strong, and can be formed into a cylindrical shape. The preferred cover material 30 is formed from high density polyethylene, however, other thermoplastic materials may be used. The pliable cover material 30 should be at least
-->about 0.02 inches thick and may be considerably thicker if a stronger support and impact resistance is desired. Water depth, pipe size, pipe weight and other factors may dictate the use of a cover material 30 which is up to about 1/2 inch in thickness. The cover material 30 may be a flat sheet or may be preformed into a cylindrical shape. The pliable sheet of cover material 30 is wrapped into a cylindrical shape around the exposed pipe ends 18 & 18A such that the inside diameter of the cylinder of cover material 30 is about the same as the outside diameter of the weight coat 14 & 14A on the pipeline 10. The cover material 30 should be long enough to overlap the adjacent edges 22 & 22 A of both sides of the weight coating 14 & 14A by several inches to allow the weight coating 14 & 14A to act as a structural support for the cover material 30. Once the cover material 30 is fitted over the adjacent edges 22 & 22A of the weight coat 14 & 14A, the side edges 34 and 36 of cover material 30 are tightly pushed together such that the side edges 34 & 36 overlap. The cover material 30 can be tightened down and held in place with cinch belts. The outside edge 34 is then sealed to the surface of the cover material 30 and a sealed sleeve 40 is formed.
The cover material 30 can be sealed by plastic welding the outside edge 34 onto the surface of the cover material 30, forming a longitudinally extending plastic weld the entire length of the cover material 30 as shown in Fig 3. Other means of sealing such as heat fusion, riveting, gluing, taping, or banding can also be used to seal the cover material 30.
The sealed cover material sleeve 40 forms a protective barrier around the exposed portion of pipe 18 & 18A which remains as a permanent part of the pipeline 10. An annular space 44 is formed around the pipe 18 & 18A by installing the cover material sleeve 40. This annular space 44 is filled by first cutting a hole 38 in the sealed cover material sleeve 40 and thereafter injecting fluid joint filler system components through the hole 38 and into the annular space 44.
The hole 38 may be drilled or cut or otherwise made in the sealed cover material sleeve 40 to thereafter allow unreacted joint filler system components to be injected into the annular space 44. The hole 38 may be precut into the cover material 30 prior to installation on the weight coated pipeline 10 or may be cut after the sealed cover material sleeve 40 is in place. The diameter of the hole 38 to be drilled is dependent upon the
-->particular type of mixing head used to inject the joint filler system components. Industry standard or conventional injection heads are acceptable.
In the preferred method, the annular space 44 is filled with a high density foam by injecting components for a rapid setting polyurethane system through the hole 38 with a mixing head. The polyurethane foam 52 serves as a shock absorber and protects the corrosion coating on the pipe 18 & 18A. Also, because the foam 52 is open celled, it can absorb water and increase the ballast effect for the pipeline 10. Alternatively, other polymerizing or hard setting compounds such as marine mastics, quick setting concretes, polymers, or elastomeric compounds may be used to fill the empty annular space. Preferably, any alternative filler material is quick hardening, such that the process of laying the pipeline is not inhibited.
The preferred polyurethane system used to form the protective high density foam 52 in this process is a combination of a isocyanate and a polyol system which when reacted rapidly cures and forms high density open celled polyurethane foam which resists degradation in sea water. The preferred isocyanate is a polymeric form of diphenylmethane diisocyanate as manufactured by Bayer Corp. The preferred polyol system is a mixture of multifunctional polyether and/or polyester polyols, catalysts for controlling the reaction rate, surfactants for enhancing cell formation, and water for a blowing agent. Acceptable blended polyol system are manufactured by Dow Chemical Co., Bayer Corp., and others.
The preferred polyurethane system produces a foam with a density of about 8 to 10 pounds per cubic foot and has about eighty percent or greater open cells. The compressive strength of the preferred polyurethane foam is approximately 150 psi or greater at 10 percent deflection and 1500 psi or greater at 90 percent deflection. Reaction of the preferred polyurethane system components can be characterized by a 15 to 20 second cream time, the time between discharge from the mixing head and the beginning of the foam rise, a 40 to 50 second rise time, the time between discharge from the mixing head and the complete foam rise, and a 180 to 240 second cure time, the time required to develop the polymer strength and dimensional stability. The cover material sleeve 40 acts as a mold and holds the foam 52 in place until it is completely cured. As shown in Figure 4, this polyurethane foam 52 completely fills
-->the annular space 44 without leaving significant void areas. No additional filler materials are needed to be used in conjunction with the polyurethane foam 52. The polyurethane foam 52 should completely fill the annular space 44 and protrude to some extent upward through the hole 38 on the sealed cover material sleeve 40. Fig. 4 shows the completed protective covering of the joint protection system according to the present invention. The sealed cover material sleeve 40 together with the polyurethane foam 52 provide a protective system which protects the exposed pipe 18 & 18A and the corrosion coating 24 during handling and laying of d e pipeline 10 and continues to provide protection from damage due to drag lines or trawler boards attached to fishing trawler nets. Further, the sealed cover material sleeve 40 is not subject to the corrosion problems of prior art systems and therefore does not create a underwater hazard or a danger to fishing nets. Additionally, die protective system provided by the present invention acts to deflect the high pressure water jets used to bury pipelines in shallow waters which have resulted in damage to the corrosion coating on pipe joints protected by prior art systems.
From the foregoing, it can be seen that the present invention provides a method and apparatus for protecting the corrosion coating 24 on exposed pipeline joints such as 12 & 12A on weight coated pipelines 10 used in offshore applications. The method allows quick installation on a lay barge where pipeline sections are being welded together for offshore installation. The corrosion coating 24 on the pipeline joint connections 18 & 18A which have no weight coating is protected by forming a pliable sheet of polyethylene into a cylindrical cover material sleeve 40 over the pipeline joint connection. Polyurethane chemicals are used to react and form a high density foam 52 which fills the annular space 44 between the pipe 18 & 18A and the cover material sleeve 40. The cover material sleeve 40 and the foam 52 work together to protect the joint connection.
It should be understood that there can be improvements and modifications made of the embodiments of the invention described in detail above without departing from the spirit or scope of the invention as set forth in the accompanying claims.
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CATHODIC PROTECTION OF SUB SEA PIPELINES
Mission Vision and Quality Polivy
Quality Policy
We are committed to provide cost effective cathodic protection solutions to meet our customers requirements
We will not compromise on the quality of our services for commercial gain
We will continually review and upgrade our QMS in order to contnually improve upon our products and services
Kunal Shah
CEO
We are committed to provide cost effective cathodic protection solutions to meet our customers requirements
We will not compromise on the quality of our services for commercial gain
We will continually review and upgrade our QMS in order to contnually improve upon our products and services
Kunal Shah
CEO
Thursday, February 14, 2008
Protective Metallic Coatings
Metallic coatings provide a layer that changes the surface properties of the workpiece to those of the metal being applied. The workpiece becomes a composite material exhibiting properties generally not achievable by either material if used alone. The coatings provide a durable, corrosion resistant layer, and the core material provides the load bearing capability. The deposition of metal coatings, such as chromium, nickel, copper, and cadmium, is usually achieved by wet chemical processes that have inherent pollution control problems. (corrosion costs study)
See how our Sponsor can help you with galvanized testing and evaluation
Alternative metal deposition methods have replaced some of the wet processes and may play a greater role in metal coating in the future. Metallic coatings are deposited by electroplating, electroless plating, spraying, hot dipping, chemical vapor deposition and ion vapor deposition. Some important coatings are cadmium, chromium, nickel, aluminum and zinc.Plating and surface treatment processes are typically batch operations, in which metal objects are dipped into and then removed from baths containing various reagents to achieve the desired surface condition. The processes involve moving the object being coated through a series of baths designed to produce the desired end product. These processes can be manual or highly automated operations, depending on the level of sophistication and modernization of the facility and the application.
Corrosion Costs and Preventive Strategies Study
The most widely used metallic coating method for corrosion protection is galvanizing, which involves the application of metallic zinc to carbon steel for corrosion control purposes. Hot-dip galvanizing is the most common process, and as the name implies, it consists of dipping the steel member into a bath of molten zinc. Information released by the U.S. Commerce Department in 1998 stated that about 8.6 million metric tons of hot-dip galvanized steel and 2.8 million metric tons of electrolytic galvanized steel were produced in 1997. The total market for metallizing and galvanizing in the United States is estimated at $1.4 billion. This figure is the total material cost of the metal coating and the cost of processing, and does not include the cost of the carbon steel member being galvanized/metallized.
Metallizing is defined as the application of very thin metallic coatings for either active corrosion protection (zinc or aluminum anodes) or as a protective layer (stainless steels and alloys). Application can be by flame spraying or electroplating. Other advanced processes such as plasma arc spraying can be used for exotic refractory metals for very demanding applications, but most of the advanced processes are not used for corrosion control. The metallizing anode market ranges from $5 million to $10 million annually, and is also growing due to the recognition by government agencies that life-cycle costs are significant if corrosion mitigation is not specified from the start. (reference)
Information Module
Electroplating
Electroless plating
Zinc coatings
Pack cementation
Cladding
Thermal spraying
Physical vapor deposition
Inorganic coatings
more
See how our Sponsor can help you with galvanized testing and evaluation
Alternative metal deposition methods have replaced some of the wet processes and may play a greater role in metal coating in the future. Metallic coatings are deposited by electroplating, electroless plating, spraying, hot dipping, chemical vapor deposition and ion vapor deposition. Some important coatings are cadmium, chromium, nickel, aluminum and zinc.Plating and surface treatment processes are typically batch operations, in which metal objects are dipped into and then removed from baths containing various reagents to achieve the desired surface condition. The processes involve moving the object being coated through a series of baths designed to produce the desired end product. These processes can be manual or highly automated operations, depending on the level of sophistication and modernization of the facility and the application.
Corrosion Costs and Preventive Strategies Study
The most widely used metallic coating method for corrosion protection is galvanizing, which involves the application of metallic zinc to carbon steel for corrosion control purposes. Hot-dip galvanizing is the most common process, and as the name implies, it consists of dipping the steel member into a bath of molten zinc. Information released by the U.S. Commerce Department in 1998 stated that about 8.6 million metric tons of hot-dip galvanized steel and 2.8 million metric tons of electrolytic galvanized steel were produced in 1997. The total market for metallizing and galvanizing in the United States is estimated at $1.4 billion. This figure is the total material cost of the metal coating and the cost of processing, and does not include the cost of the carbon steel member being galvanized/metallized.
Metallizing is defined as the application of very thin metallic coatings for either active corrosion protection (zinc or aluminum anodes) or as a protective layer (stainless steels and alloys). Application can be by flame spraying or electroplating. Other advanced processes such as plasma arc spraying can be used for exotic refractory metals for very demanding applications, but most of the advanced processes are not used for corrosion control. The metallizing anode market ranges from $5 million to $10 million annually, and is also growing due to the recognition by government agencies that life-cycle costs are significant if corrosion mitigation is not specified from the start. (reference)
Information Module
Electroplating
Electroless plating
Zinc coatings
Pack cementation
Cladding
Thermal spraying
Physical vapor deposition
Inorganic coatings
more
Why Metals Corrode
Metals corrode because we use them in environments where they are chemically unstable. Only copper and the precious metals (gold, silver, platinum, etc.) are found in nature in their metallic state. All other metals, to include iron-the metal most commonly used-are processed from minerals or ores into metals which are inherently unstable in their environments.
This golden statue in Bangkok, Thailand, is made of the only metal which is thermodynamically stable in room temperature air. All other metals are unstable and have a tendency to revert to their more stable mineral forms. Some metals form protective ceramic films (passive films) on their surfaces and these prevent, or slow down, their corrosion process. The woman in the picture below is wearing anodized titanium earrings. The thickness of the titanium oxide on the metal surface refracts the light and causes the rainbow colors on her earrings. Her husband is wearing stainless steel eyeglasses. The passive film that formed on his eyeglasses is only about a dozen atoms thick, but this passive film is so protective that his eyeglasses are protected from corrosion. We can prevent corrosion by using metals that form naturally protective passive films, but these alloys are usually expensive, so we have developed other means of corrosion control.
Return to Corrosion Fundamentals
Cathodic protection for dummies
Electrochemical Cells
Oxidation and Reduction Electrochemical Reactions Oxidation and Reduction:Metals are elements that tend to lose electrons when they are involved in chemical reactions, and nonmetals are those elements that tend to gain electrons. Sometimes these elements form ions, charged elements or groups of elements. Metallic ions, because they are formed from atoms that have lost electrons, are positively charged (the nucleus is unchanged). When an atom or ion loses electrons it is said to have been oxidized. A common oxidation reaction in corrosion is the oxidation of neutral iron atoms to positively charged iron ions:
Fe » Fe+2 + 2e-
The electrons lost from a metal must go somewhere, and they usually end up on a nonmetallic atom forming a negatively charged nonmetallic ion. Because the charge of these ions has become smaller (more negative charges) the ion or atom which has gained the electron(s) is said to have been reduced.
4H+ +O2 + 4e- » 2H2O
or
2H+ +2e- » H2
While other reduction reactions are possible, the reduction of oxygen is involved in well over 90% of all corrosion reactions. Thus the amount of oxygen present in an environment, and its ability to absorb electrons, is an important factor in determining the amount of oxidation, or corrosion, of metal that occurs.
Mnemonic device: Many people have a hard time remembering what oxidation and reduction mean in terms of chemical reactions. If you just remember that reduction means “get smaller,” then you can remember that the electrical charge on a reduced chemical has gotten smaller (has more negative charges). The opposite reaction, oxidation, means that the charge has gotten larger (not so easy to remember).
The two metal strips shown below are exposed to the same acid. Both metals undergo similar oxidation reactions: \
Cu » Cu+2 + 2e-
and
Zn » Zn+2 + 2e-
Cu » Cu+2 + 2e-
and
Zn » Zn+2 + 2e-
The electrons freed by the oxidation reactions are consumed by reduction reactions. On the copper the reduction reaction is:
4H+ +O2 +4e- » 2H2O
The corrosion rate of the copper is limited by the amount of dissolved oxygen in acid. On the zinc the reduction reaction is:
2H+ +2e- » H2
The hydrogen ions are converted to hydrogen gas molecules and can actually be seen bubbling off from the acid. If we now connect the two metal samples with a wire and measure the electricity through the connecting wire, we find that one of the electrodes becomes different in potential than the other and that the corrosion rate of the copper decreases while the corrosion rate of the zinc increases. By connecting the two metals, we have made the copper a cathode in an electrochemical cell, and the zinc has become an anode. The accelerated corrosion of the zinc may be so much that all of the oxidation of the copper stops and it becomes protected from corrosion. We call this method of corrosion control cathodic protection. The reaction at the copper (cathode) becomes:
2H+ +2e- » H2
The voltage of the copper shifts to a point where hydrogen ion reduction can occur at the copper surface. The oxidation (corrosion) of the copper cathode may completely stop due to the electrical connection to the zinc anode. The reaction at the zinc (anode) remains the same,
Zn » Zn+2 + 2e-
but the reaction rate increases due to the fact that the surface area of the clean (uncorroding) copper surface can now support a reduction reaction at a high rate. Thus connecting these two metals virtually stopped the corrosion of the copper and increased the corrosion rate of the zinc. We say that the zinc cathodically protected the copper from corrosion. Cathodic protection is a common means of corrosion control.
Mnemonic device: Anodes are those portions of an electrochemical cell that have mostly oxidation reactions. Cathodes are those locations of an electrochemical cell that have mostly reduction reactions. One way to remember which kind of reaction predominates at each kind of electrode is to note that anode comes before cathode in the alphabet just like oxidation comes before reduction. Anodes oxidize; cathodes reduce.
Cathodic Protection
Cathodic protection is an electrical means of corrosion control. Cathodic protection can be applied using sacrificial (galvanic) anodes or by means of more complicated impressed current systems.
This Louisiana fishing boat has sacrificial zinc anodes welded to the hull to slow down corrosion. No pattern is apparent to how the anodes were attached-the design philosophy seems to be that if one anode is good, more is better.
Cathodic protection is an electrical means of corrosion control. Cathodic protection can be applied using sacrificial (galvanic) anodes or by means of more complicated impressed current systems.
This Louisiana fishing boat has sacrificial zinc anodes welded to the hull to slow down corrosion. No pattern is apparent to how the anodes were attached-the design philosophy seems to be that if one anode is good, more is better.
The Kennedy Space Center's cathodic protection research has concentrated on the use of sacrificial and impressed current systems for minimizing corrosion of embedded steel in concrete structures.
Return to Corrosion Control Page
Corrosion fundamentals
Fundamentals of Corrosion and Corrosion Control
Corrosion of a Coated Handrail
Corroded Rain Gutter
Corrosion on the Nose of the Statue of Liberty
Corrosion can be defined as the degradation of a material due to a reaction with its environment.
Degradation implies deterioration of physical properties of the material. This can be a weakening of the material due to a loss of cross-sectional area, it can be the shattering of a metal due to hydrogen embrittlement, or it can be the cracking of a polymer due to sunlight exposure.
Materials can be metals, polymers (plastics, rubbers, etc.), ceramics (concrete, brick, etc.) or composites-mechanical mixtures of two or more materials with different properties. Because metals are the most used type of structural materials most of this web site will be devoted to the corrosion of metals.
Most corrosion of metals is electrochemical in nature. Click here for a brief introduction to electrochemistry.
Why metals corrode
Electrochemistry
Forms of corrosion
Corrosion Control
Sources of additional informatio
more
Electrochemistry Fundamentals
The following brief introduction to chemistry and electrochemistry is intended to give the user of this website a basic understanding of corrosion. There are hundreds of websites that provide more detailed explanations of the ideas presented-so many that we have not even attempted to link to them.
The Nature of Matter Atoms Ions Molecules Acid and Bases
Electrochemical Cells Oxidation and Reduction Electrochemical Reactions
Return to Corrosion Fundamentals
more
Corrosion of a Coated Handrail
Corroded Rain Gutter
Corrosion on the Nose of the Statue of Liberty
Corrosion can be defined as the degradation of a material due to a reaction with its environment.
Degradation implies deterioration of physical properties of the material. This can be a weakening of the material due to a loss of cross-sectional area, it can be the shattering of a metal due to hydrogen embrittlement, or it can be the cracking of a polymer due to sunlight exposure.
Materials can be metals, polymers (plastics, rubbers, etc.), ceramics (concrete, brick, etc.) or composites-mechanical mixtures of two or more materials with different properties. Because metals are the most used type of structural materials most of this web site will be devoted to the corrosion of metals.
Most corrosion of metals is electrochemical in nature. Click here for a brief introduction to electrochemistry.
Why metals corrode
Electrochemistry
Forms of corrosion
Corrosion Control
Sources of additional informatio
more
Electrochemistry Fundamentals
The following brief introduction to chemistry and electrochemistry is intended to give the user of this website a basic understanding of corrosion. There are hundreds of websites that provide more detailed explanations of the ideas presented-so many that we have not even attempted to link to them.
The Nature of Matter Atoms Ions Molecules Acid and Bases
Electrochemical Cells Oxidation and Reduction Electrochemical Reactions
Return to Corrosion Fundamentals
more
Electrochemistry and corrosion science
go here
Forms of Corrosion
The forms of corrosion described here use the terminology in use at NASA-KSC. There are other equally valid methods of classifying corrosion, and no universally-accepted terminology is in use. Keep in mind that a given situation may lead to several forms of corrosion on the same piece of material.
(Click on Title for a Detail Explanation)
Illustration
Form of Corrosion
Uniform Corrosion
This is also called general corrosion. The surface effect produced by most direct chemical attacks (e.g., as by an acid) is a uniform etching of the metal.
Galvanic Corrosion
Galvanic corrosion is an electrochemical action of two dissimilar metals in the presence of an electrolyte and an electron conductive path. It occurs when dissimilar metals are in contact.
Concentration Cell Corrosion
Concentration cell corrosion occurs when two or more areas of a metal surface are in contact with different concentrations of the same solution.
Pitting Corrosion
Pitting corrosion is localized corrosion that occurs at microscopic defects on a metal surface. The pits are often found underneath surface deposits caused by corrosion product accumulation.
Crevice Corrosion
Crevice or contact corrosion is the corrosion produced at the region of contact of metals with metals or metals with nonmetals. It may occur at washers, under barnacles, at sand grains, under applied protective films, and at pockets formed by threaded joints.
Filiform Corrosion
This type of corrosion occurs on painted or plated surfaces when moisture permeates the coating. Long branching filaments of corrosion product extend out from the original corrosion pit and cause degradation of the protective coating.
Intergranular Corrosion
Intergranular corrosion is an attack on or adjacent to the grain boundaries of a metal or alloy.
Stress Corrosion Cracking
Stress corrosion cracking (SCC) is caused by the simultaneous effects of tensile stress and a specific corrosive environment. Stresses may be due to applied loads, residual stresses from the manufacturing process, or a combination of both.
Corrosion Fatigue
Corrosion fatigue is a special case of stress corrosion caused by the combined effects of cyclic stress and corrosion. No metal is immune from some reduction of its resistance to cyclic stressing if the metal is in a corrosive environment.
Fretting Corrosion
The rapid corrosion that occurs at the interface between contacting, highly loaded metal surfaces when subjected to slight vibratory motions is known as fretting corrosion.
Erosion Corrosion
Erosion corrosion is the result of a combination of an aggressive chemical environment and high fluid-surface velocities.
Dealloying
Dealloying is a rare form of corrosion found in copper alloys, gray cast iron, and some other alloys. Dealloying occurs when the alloy loses the active component of the metal and retains the more corrosion resistant component in a porous "sponge" on the metal surface.
Hydrogen Damage
Hydrogen embrittlement is a problem with high-strength steels, titanium, and some other metals. Control is by eliminating hydrogen from the environment or by the use of resistant alloys.
Corrosion in Concrete
Concrete is a widely-used structural material that is frequently reinforced with carbon steel reinforcing rods, post-tensioning cable or prestressing wires. The steel is necessary to maintain the strength of the structure, but it is subject to corrosion.
Microbial Corrosion
Microbial corrosion (also called microbiologically -influenced corrosion or MIC) is corrosion that is caused by the presence and activities of microbes. This corrosion can take many forms and can be controlled by biocides or by conventional corrosion control methods.
Return to Corrosion Fundamentals Page
more
Cathodic Protection Basics
The basic principle of CP is simple. A metal dissolution is reduced through the application of a cathodic current. Cathodic protection is often applied to coated structures, with the coating providing the primary form of corrosion protection. The CP current requirements tend to be excessive for uncoated systems.
See how our Sponsor can help you with cathodic protection
The first application of CP dates back to 1824, long before its theoretical foundation was established. Cathodic protection has probably become the most widely used method for preventing the corrosion deterioration of metallic structures in contact with any forms of electrolytically conducting environments, i.e. environments containing enough ions to conduct electricity such as soils, seawater and basically all natural waters. Cathodic protection basically reduces the corrosion rate of a metallic structure by reducing its corrosion potential, bringing the metal closer to an immune state. The two main methods of achieving this goal are by either:
Using sacrificial anodes with a corrosion potential lower than the metal to be protected (see the seawater galvanic series)
Using an impressed current provided by an external current source
more
Forms of Corrosion
The forms of corrosion described here use the terminology in use at NASA-KSC. There are other equally valid methods of classifying corrosion, and no universally-accepted terminology is in use. Keep in mind that a given situation may lead to several forms of corrosion on the same piece of material.
(Click on Title for a Detail Explanation)
Illustration
Form of Corrosion
Uniform Corrosion
This is also called general corrosion. The surface effect produced by most direct chemical attacks (e.g., as by an acid) is a uniform etching of the metal.
Galvanic Corrosion
Galvanic corrosion is an electrochemical action of two dissimilar metals in the presence of an electrolyte and an electron conductive path. It occurs when dissimilar metals are in contact.
Concentration Cell Corrosion
Concentration cell corrosion occurs when two or more areas of a metal surface are in contact with different concentrations of the same solution.
Pitting Corrosion
Pitting corrosion is localized corrosion that occurs at microscopic defects on a metal surface. The pits are often found underneath surface deposits caused by corrosion product accumulation.
Crevice Corrosion
Crevice or contact corrosion is the corrosion produced at the region of contact of metals with metals or metals with nonmetals. It may occur at washers, under barnacles, at sand grains, under applied protective films, and at pockets formed by threaded joints.
Filiform Corrosion
This type of corrosion occurs on painted or plated surfaces when moisture permeates the coating. Long branching filaments of corrosion product extend out from the original corrosion pit and cause degradation of the protective coating.
Intergranular Corrosion
Intergranular corrosion is an attack on or adjacent to the grain boundaries of a metal or alloy.
Stress Corrosion Cracking
Stress corrosion cracking (SCC) is caused by the simultaneous effects of tensile stress and a specific corrosive environment. Stresses may be due to applied loads, residual stresses from the manufacturing process, or a combination of both.
Corrosion Fatigue
Corrosion fatigue is a special case of stress corrosion caused by the combined effects of cyclic stress and corrosion. No metal is immune from some reduction of its resistance to cyclic stressing if the metal is in a corrosive environment.
Fretting Corrosion
The rapid corrosion that occurs at the interface between contacting, highly loaded metal surfaces when subjected to slight vibratory motions is known as fretting corrosion.
Erosion Corrosion
Erosion corrosion is the result of a combination of an aggressive chemical environment and high fluid-surface velocities.
Dealloying
Dealloying is a rare form of corrosion found in copper alloys, gray cast iron, and some other alloys. Dealloying occurs when the alloy loses the active component of the metal and retains the more corrosion resistant component in a porous "sponge" on the metal surface.
Hydrogen Damage
Hydrogen embrittlement is a problem with high-strength steels, titanium, and some other metals. Control is by eliminating hydrogen from the environment or by the use of resistant alloys.
Corrosion in Concrete
Concrete is a widely-used structural material that is frequently reinforced with carbon steel reinforcing rods, post-tensioning cable or prestressing wires. The steel is necessary to maintain the strength of the structure, but it is subject to corrosion.
Microbial Corrosion
Microbial corrosion (also called microbiologically -influenced corrosion or MIC) is corrosion that is caused by the presence and activities of microbes. This corrosion can take many forms and can be controlled by biocides or by conventional corrosion control methods.
Return to Corrosion Fundamentals Page
more
Cathodic Protection Basics
The basic principle of CP is simple. A metal dissolution is reduced through the application of a cathodic current. Cathodic protection is often applied to coated structures, with the coating providing the primary form of corrosion protection. The CP current requirements tend to be excessive for uncoated systems.
See how our Sponsor can help you with cathodic protection
The first application of CP dates back to 1824, long before its theoretical foundation was established. Cathodic protection has probably become the most widely used method for preventing the corrosion deterioration of metallic structures in contact with any forms of electrolytically conducting environments, i.e. environments containing enough ions to conduct electricity such as soils, seawater and basically all natural waters. Cathodic protection basically reduces the corrosion rate of a metallic structure by reducing its corrosion potential, bringing the metal closer to an immune state. The two main methods of achieving this goal are by either:
Using sacrificial anodes with a corrosion potential lower than the metal to be protected (see the seawater galvanic series)
Using an impressed current provided by an external current source
more
Corrosion protection coatings
Coatings for corrosion protection
10 of 12
For steels, corrosion resistance (against predominantly aqueous corrosion) can be achieved through three different coatings:
Barrier,Sacrificial, andInherent
more
10 of 12
For steels, corrosion resistance (against predominantly aqueous corrosion) can be achieved through three different coatings:
Barrier,Sacrificial, andInherent
more
Cathodic Protection Operation and Maintenance Requirements
All regulated underground storage tanks system (USTs) must have cathodic protection.
State and federal rules require corrosion protection for UST systems because unprotected steel UST systems corrode and release product through corrosion holes. You already meet the requirements for corrosion protection if your UST system matches one of the following performance standards for new USTs:
Tank and piping completely made of noncorrodible material, such as fiberglass. Corrosion protection is also provided if tank and piping are completely isolated from contact with the surrounding soil by being enclosed in noncorrodible material (sometimes called "jacketed" with noncorrodible material).
Tank and piping made of steel having a corrosion-resistant coating AND having cathodic protection (such as an sti-P3® tank with appropriate piping). A corrosion-resistant coating electrically isolates the coated metal from the surrounding environment to help protect against corrosion. Asphaltic coating does not qualify as a corrosion-resistant coating.
Tank made of steel clad with a thick layer of noncorrodible material (such as an ACT-100® tank). This option does not apply to piping. Galvanized steel is not a noncorrodible material.
Impressed current system. An impressed current system uses a rectifier to convert alternating current to direct current (see picture below). This current is sent through an insulated wire to the "anodes," which are special metal bars buried in the soil near the UST. The current then flows through the soil to the UST system, and returns to the rectifier through an insulated wire attached to the UST. The UST system is protected because the current going to the UST system overcomes the corrosion-causing current normally flowing away from it.
Sacrificial anode system. Another type of cathodic protection (see picture below) is called a sacrificial anode or galvanic system. Although sacrificial anode systems work with new USTs (sti-P3® tanks single or double wall), corrosion protection experts generally agree that sacrificial anodes do not work effectively or economicall with most existing steel USTs. Only a qualified cathodic protection expert candetermine what kind of cathodic protection will work at your UST site.
Operation and maintenance requirements
A qualified cathodic protection tester must test the system within six months after installation and every three years thereafter.
A negative potential of –850 millivolts or –0.85 volts should be obtained between the UST system and a reference electrode touching the soil above the tank.
Results of the last two inspections performed by a qualified cathodic protection tester must be kept.
In addition, an impressed current system must be checked by the owners or operators every 60 days to ensure that the system is operating properly.
A log must be kept for the last three check ups to show that the impressed current system is operating properly.
The records may be kept at a central office rather than the facility itself.
more
State and federal rules require corrosion protection for UST systems because unprotected steel UST systems corrode and release product through corrosion holes. You already meet the requirements for corrosion protection if your UST system matches one of the following performance standards for new USTs:
Tank and piping completely made of noncorrodible material, such as fiberglass. Corrosion protection is also provided if tank and piping are completely isolated from contact with the surrounding soil by being enclosed in noncorrodible material (sometimes called "jacketed" with noncorrodible material).
Tank and piping made of steel having a corrosion-resistant coating AND having cathodic protection (such as an sti-P3® tank with appropriate piping). A corrosion-resistant coating electrically isolates the coated metal from the surrounding environment to help protect against corrosion. Asphaltic coating does not qualify as a corrosion-resistant coating.
Tank made of steel clad with a thick layer of noncorrodible material (such as an ACT-100® tank). This option does not apply to piping. Galvanized steel is not a noncorrodible material.
Impressed current system. An impressed current system uses a rectifier to convert alternating current to direct current (see picture below). This current is sent through an insulated wire to the "anodes," which are special metal bars buried in the soil near the UST. The current then flows through the soil to the UST system, and returns to the rectifier through an insulated wire attached to the UST. The UST system is protected because the current going to the UST system overcomes the corrosion-causing current normally flowing away from it.
Sacrificial anode system. Another type of cathodic protection (see picture below) is called a sacrificial anode or galvanic system. Although sacrificial anode systems work with new USTs (sti-P3® tanks single or double wall), corrosion protection experts generally agree that sacrificial anodes do not work effectively or economicall with most existing steel USTs. Only a qualified cathodic protection expert candetermine what kind of cathodic protection will work at your UST site.
Operation and maintenance requirements
A qualified cathodic protection tester must test the system within six months after installation and every three years thereafter.
A negative potential of –850 millivolts or –0.85 volts should be obtained between the UST system and a reference electrode touching the soil above the tank.
Results of the last two inspections performed by a qualified cathodic protection tester must be kept.
In addition, an impressed current system must be checked by the owners or operators every 60 days to ensure that the system is operating properly.
A log must be kept for the last three check ups to show that the impressed current system is operating properly.
The records may be kept at a central office rather than the facility itself.
more
Cathodic protection fundamentals
Cathodic protection
From Wikipedia, the free encyclopedia
Jump to: navigation, search
Aluminium anodes mounted on a steel jacket structure
Cathodic protection (CP) is a technique to control the corrosion of a metal surface by making that surface the cathode of an electrochemical cell.
It is a method used to protect metal structures from corrosion. Cathodic protection systems are most commonly used to protect steel, water/fuel pipelines and storage tanks; steel pier piles, ships, offshore oil platforms and onshore oil well casings.
A side effect of improperly performed cathodic protection may be production of molecular hydrogen, leading to its absorption in the protected metal and subsequent hydrogen embrittlement.
Cathodic protection is an effective method of preventing stress corrosion cracking.
Contents[hide]
1 Origins
2 Galvanic CP
3 Impressed Current CP
4 Testing
5 Galvanized Steel
6 Standards
7 External links
//
more
Galvanic corrosion is an electrochemical action of two dissimilar metals in the presence of an electrolyte and an electron conductive path. It occurs when dissimilar metals are in contact.
It is recognizable by the presence of a buildup of corrosion at the joint between the dissimilar metals. For example, when aluminum alloys or magnesium alloys are in contact with steel (carbon steel or stainless steel), galvanic corrosion can occur and accelerate the corrosion of the aluminum or magnesium. This can be seen on the photo above where the aluminum helicopter blade has corroded near where it was in contact with a steel counterbalance.
Galvanic Series In Sea Water
Noble(least active)
PlatinumGoldGraphiteSilver18-8-3 Stainless steel, type 316 (passive)18-8 Stainless steel, type 304 (passive)Titanium13 percent chromium stainless steel, type 410 (passive)7NI-33Cu alloy75NI-16Cr-7Fe alloy (passive)Nickel (passive)Silver solderM-BronzeG-Bronze70-30 cupro-nickelSilicon bronzeCopperRed brassAluminum bronzeAdmiralty brassYellow brass76NI-16Cr-7Fe alloy (active)Nickel (active)Naval brassManganese bronzeMuntz metalTinLead18-8-3 Stainless steel, type 316 (active)18-8 Stainless steel, type 304 (active)13 percent chromium stainless steel, type 410 (active)Cast ironMild steelAluminum 2024CadmiumAlcladAluminum 6053Galvanized steelZincMagnesium alloysMagnesium
Anodic(most active)
The natural differences in metal potentials produce galvanic differences, such as the galvanic series in sea water. If electrical contact is made between any two of these materials in the presence of an electrolyte, current must flow between them. The farther apart the metals are in the galvanic series, the greater the galvanic corrosion effect or rate will be. Metals or alloys at the upper end are noble while those at the lower end are active. The more active metal is the anode or the one that will corrode.
Control of galvanic corrosion is achieved by using metals closer to each other in the galvanic series or by electrically isolating metals from each other. Cathodic protection can also be used to control galvanic corrosion effects.
The scuba tank above suffered galvanic corrosion when the brass valve and the steel tank were wetted by condensation. Electrical isolation flanges like those shown on the right are used to prevent galvanic corrosion. Insulating gaskets, usually polymers, are inserted between the flanges, and insulating sleeves and washers isolate the bolted connections.
KSC conducts research on the effects of galvanic corrosion. The photo below shows the corrosion caused by a stainless steel screw causing galvanic corrosion of aluminum. The picture shows the corrosion resulting from only six months exposure at the Atmospheric Test Site.
more
From Wikipedia, the free encyclopedia
Jump to: navigation, search
Aluminium anodes mounted on a steel jacket structure
Cathodic protection (CP) is a technique to control the corrosion of a metal surface by making that surface the cathode of an electrochemical cell.
It is a method used to protect metal structures from corrosion. Cathodic protection systems are most commonly used to protect steel, water/fuel pipelines and storage tanks; steel pier piles, ships, offshore oil platforms and onshore oil well casings.
A side effect of improperly performed cathodic protection may be production of molecular hydrogen, leading to its absorption in the protected metal and subsequent hydrogen embrittlement.
Cathodic protection is an effective method of preventing stress corrosion cracking.
Contents[hide]
1 Origins
2 Galvanic CP
3 Impressed Current CP
4 Testing
5 Galvanized Steel
6 Standards
7 External links
//
more
Galvanic corrosion is an electrochemical action of two dissimilar metals in the presence of an electrolyte and an electron conductive path. It occurs when dissimilar metals are in contact.
It is recognizable by the presence of a buildup of corrosion at the joint between the dissimilar metals. For example, when aluminum alloys or magnesium alloys are in contact with steel (carbon steel or stainless steel), galvanic corrosion can occur and accelerate the corrosion of the aluminum or magnesium. This can be seen on the photo above where the aluminum helicopter blade has corroded near where it was in contact with a steel counterbalance.
Galvanic Series In Sea Water
Noble(least active)
PlatinumGoldGraphiteSilver18-8-3 Stainless steel, type 316 (passive)18-8 Stainless steel, type 304 (passive)Titanium13 percent chromium stainless steel, type 410 (passive)7NI-33Cu alloy75NI-16Cr-7Fe alloy (passive)Nickel (passive)Silver solderM-BronzeG-Bronze70-30 cupro-nickelSilicon bronzeCopperRed brassAluminum bronzeAdmiralty brassYellow brass76NI-16Cr-7Fe alloy (active)Nickel (active)Naval brassManganese bronzeMuntz metalTinLead18-8-3 Stainless steel, type 316 (active)18-8 Stainless steel, type 304 (active)13 percent chromium stainless steel, type 410 (active)Cast ironMild steelAluminum 2024CadmiumAlcladAluminum 6053Galvanized steelZincMagnesium alloysMagnesium
Anodic(most active)
The natural differences in metal potentials produce galvanic differences, such as the galvanic series in sea water. If electrical contact is made between any two of these materials in the presence of an electrolyte, current must flow between them. The farther apart the metals are in the galvanic series, the greater the galvanic corrosion effect or rate will be. Metals or alloys at the upper end are noble while those at the lower end are active. The more active metal is the anode or the one that will corrode.
Control of galvanic corrosion is achieved by using metals closer to each other in the galvanic series or by electrically isolating metals from each other. Cathodic protection can also be used to control galvanic corrosion effects.
The scuba tank above suffered galvanic corrosion when the brass valve and the steel tank were wetted by condensation. Electrical isolation flanges like those shown on the right are used to prevent galvanic corrosion. Insulating gaskets, usually polymers, are inserted between the flanges, and insulating sleeves and washers isolate the bolted connections.
KSC conducts research on the effects of galvanic corrosion. The photo below shows the corrosion caused by a stainless steel screw causing galvanic corrosion of aluminum. The picture shows the corrosion resulting from only six months exposure at the Atmospheric Test Site.
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Cathodic Protection
The science of cathodic protection (CP) was born in 1824, when Sir Humphrey Davy made a presentation to the Royal Society of London: "The rapid decay of the copper sheeting on His Majesty's ships of war, and the uncertainty of the time of its duration, have long attracted the attention of those persons most concerned in the naval interest of the count. ... I entered into an experimental investigation upon copper. In pursuing this investigation, I have ascertained many facts ... to illustrate some obscure parts of electrochemical science... seem to offer important application." Davy succeeded in protecting copper against corrosion from seawater by the use of iron anodes.
See how our Sponsor can help you with CP
From that beginning, CP has grown to have many uses in marine and underground structures, water storage tanks, gas pipelines, oil platform supports, and many other facilities exposed to a corrosive environment (see Corrosion Costs Study findings). Recently, it is proving to be an effective method for protecting reinforcing steel from chloride-induced corrosion. (reference)
Electronic rust prevention for cars, does it work?
The basic principle of CP is simple. A metal dissolution is reduced through the application of a cathodic current. Cathodic protection is often applied to coated structures, with the coating providing the primary form of corrosion protection. The CP current requirements tend to be excessive for uncoated systems. The first application of CP dates back to 1824, long before its theoretical foundation was established. Cathodic protection has probably become the most widely used method for preventing the corrosion deterioration of metallic structures in contact with any forms of electrolytically conducting environments, i.e. environments containing enough ions to conduct electricity such as soils, seawater and basically all natural waters. Cathodic protection basically reduces the corrosion rate of a metallic structure by reducing its corrosion potential, bringing the metal closer to an immune state.
Cathodic Protection 101 (709 KB)
Test your skills with a self test
Corrosion Costs and Preventive Strategies Study
The cost of cathodic protection of metallic structures subject to corrosion can be divided into the cost of materials and the cost of installation and operation. Industry data have provided estimates for the 1998 sales of various hardware components totaling $146 million. The largest share of the cathodic protection market is taken up by sacrificial anodes at $60 million, of which magnesium has the greatest market share. Major markets for sacrificial anodes are the water heater market and the underground storage tank market.
The costs of installation of the various cathodic protection (CP) components for underground structures vary significantly depending on the location and the specific details of the construction. For 1998, the average total cost for installing CP systems was estimated at $0.98 billion (range: $0.73 billion to $1.22 billion). The total cost for replacing sacrificial anodes in water heaters and the cost for corrosion-related replacement of water heaters was estimated at $1.24 billion per year; therefore, the total estimated cost for cathodic and anodic protection is $2.22 billion per year. (reference)
Information Module
Sacrificial anodes
Impressed current
Groundbed design
Backfill materials
more
At CPM we specialize in corrosion control for metallic structures which are buried in soils, submerged in water or imbedded in concrete.We solve corrosion related problems for buried and submerged pipeline facilities, underground and aboveground storage tanks, docks and piers, rapid transit systems, bridges, parking structures, electric power generation and transmission facilities as well as steel reinforced structural elements and process equipment.
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See how our Sponsor can help you with CP
From that beginning, CP has grown to have many uses in marine and underground structures, water storage tanks, gas pipelines, oil platform supports, and many other facilities exposed to a corrosive environment (see Corrosion Costs Study findings). Recently, it is proving to be an effective method for protecting reinforcing steel from chloride-induced corrosion. (reference)
Electronic rust prevention for cars, does it work?
The basic principle of CP is simple. A metal dissolution is reduced through the application of a cathodic current. Cathodic protection is often applied to coated structures, with the coating providing the primary form of corrosion protection. The CP current requirements tend to be excessive for uncoated systems. The first application of CP dates back to 1824, long before its theoretical foundation was established. Cathodic protection has probably become the most widely used method for preventing the corrosion deterioration of metallic structures in contact with any forms of electrolytically conducting environments, i.e. environments containing enough ions to conduct electricity such as soils, seawater and basically all natural waters. Cathodic protection basically reduces the corrosion rate of a metallic structure by reducing its corrosion potential, bringing the metal closer to an immune state.
Cathodic Protection 101 (709 KB)
Test your skills with a self test
Corrosion Costs and Preventive Strategies Study
The cost of cathodic protection of metallic structures subject to corrosion can be divided into the cost of materials and the cost of installation and operation. Industry data have provided estimates for the 1998 sales of various hardware components totaling $146 million. The largest share of the cathodic protection market is taken up by sacrificial anodes at $60 million, of which magnesium has the greatest market share. Major markets for sacrificial anodes are the water heater market and the underground storage tank market.
The costs of installation of the various cathodic protection (CP) components for underground structures vary significantly depending on the location and the specific details of the construction. For 1998, the average total cost for installing CP systems was estimated at $0.98 billion (range: $0.73 billion to $1.22 billion). The total cost for replacing sacrificial anodes in water heaters and the cost for corrosion-related replacement of water heaters was estimated at $1.24 billion per year; therefore, the total estimated cost for cathodic and anodic protection is $2.22 billion per year. (reference)
Information Module
Sacrificial anodes
Impressed current
Groundbed design
Backfill materials
more
At CPM we specialize in corrosion control for metallic structures which are buried in soils, submerged in water or imbedded in concrete.We solve corrosion related problems for buried and submerged pipeline facilities, underground and aboveground storage tanks, docks and piers, rapid transit systems, bridges, parking structures, electric power generation and transmission facilities as well as steel reinforced structural elements and process equipment.
more
Corrosion as an Electrochemical Process
A piece of bare iron left outside where it is exposed to moisture will rust quickly. It will do so even more quickly if the moisture is salt water. The corrosion rate is enhanced by an electrochemical process in which a water droplet becomes a voltaic cell in contact with the metal, oxidizing the iron.
What is corrosion protection?
Unprotected underground metal components of the UST system can corrode and release product through corrosion holes. Corrosion can begin as pitting on the metal surface. As the pitting becomes deeper, holes may develop. Even a small corrosion hole can leak hundreds of gallons of petroleum into the surrounding environment over a year. In addition to tanks and piping, metal components can include flexible connectors, swing joints, and turbines. All metal UST system components that are in contact with the ground and routinely contain product must be protected from corrosion. All USTs installed after December 22, 1988 must meet one of the following performance standards for corrosion protection:
Tank and piping completely made of noncorrodible material, such as fiberglass-reinforced plastic.
Tank and piping made of steel having a corrosion-resistant coating AND having cathodic protection. (click here for more information on Cathodic Protection.)
Tank made of steel clad with a thick layer of noncorrodible material (this option does not apply to piping).
Tank and piping are installed without additional corrosion protection measures provided that a corrosion expert has determined that the site is not corrosive enough to cause it to have a release due to corrosion during its operating life and owners/operators maintain records that demonstrate compliance with this requirement.
Tank and piping construction and corrosion protection are determined by the implementing agency to be designed to prevent the release or threatened release of any stored regulated substance in a manner that is no less protective of human health and the environment than the options listed above.
UST systems must also be designed, constructed, and installed in accordance with a national code of practice and according to manufacturers instructions.
UST systems installed before December 1988 must be protected from corrosion. These USTs must meet one of the corrosion protection standards listed above or meet one of the upgrade options described below (or close properly):
Interior lining,
Cathodic protection*, and
Internal lining combined with cathodic protection*.
* NOTE: Prior to adding cathodic protection, the integrity of the tank must have been ensured using one of the following methods:
the tank is internally inspected and assessed to ensure that the tank is structurally sound and free of corrosion or holes,
the tank has been installed for less than 10 years and uses monthly monitoring for releases,
the tank has been installed for less than 10 years and is assessed for corrosion holes by conducting two tightness tests--the first occurs prior to adding cathodic protection and the second occurs 3 to 6 months following the first operation of cathodic protection, and
Alternative Integrity Assessment: the tank is assessed for corrosion holes by a method that is determined by the implementing agency to prevent releases in a manner that is no less protective of human health and the environment than those listed immediately above.
Upgrading bare metal piping is accomplished by adding cathodic protection. NOTE: Metal pipe sections and fittings that have released product as a result of corrosion or other damage must be replaced. Piping entirely made of (or enclosed in) noncorrodible material does not need cathodic protection.
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Why might you fail to be in compliance even if you have the required prevention equipment?
It takes more than equipment to be in compliance and to have a safe facility. You must operate and maintain this equipment properly over time or you will not benefit from having the equipment.
Failure to operate and maintain equipment can lead to new releases. A spill bucket that is allowed to crack or fill up with debris is useless as spill protection. An overfill device that is not maintained may not function and your site will suddenly have a large overfill release to clean up. Corrosion protection devices or systems that are not regularly operated and maintained properly can fail and result in an expensive cleanup at your UST site.
Be sure you review the information sources on our Web pages devoted to "Operation and Maintenance of USTs".
Top of page
How do you properly close an UST?
To properly close an UST:
Notify the regulatory authority at least 30 days before you close your UST.
Determine if contamination from your UST is present in the surrounding environment. If there is contamination, you may have to take corrective action. For at least 3 years, keep a record of the actions you take to determine if contamination is present at the site (or you can mail this record to your regulatory authority).
Either remove the UST from the ground or leave it in the ground. In both cases, the tank must be emptied and cleaned by removing all liquids, dangerous vapor levels, and accumulated sludge. These potentially very hazardous actions need to be carried out carefully by trained professionals who follow standard safety practices. If you leave the UST in the ground, have it filled with a harmless, chemically inactive solid, like sand.
NOTE: Check with your state to determine any state-specific requirements for closing UST systems.
Top of page
What are the reporting and recordkeeping requirements?
UST owners must notify state or local authorities of the existence of an UST and its leak prevention measures, or of the permanent closure of an UST. Technical regulations also set guidelines for notifying authorities of spills of more than 25 gallons.
Owners and operators must also keep records on:
Inspection and test results for the cathodic protection system.
Repairs or upgrades.
Site assessment results after closure
A corrosion expert's analysis of the corrosion potential of the site if corrosion protection equipment is not used.
Click here for more information on reporting and recordkeeping.
Top of page
Local Navigation
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A to Z Subject Index
Compliance Help
Frequent Questions
Laws
Regulations Standards
Policy Guidance
Publications
Related Links
Program Facts
State & Local Contacts
Underground Storage Tanks Program in Indian Country
Regional EPA Contacts
EPA
more
Corrosion protection methods
"Corrosion Protection"...
Dave Wilson, Editor, writes:
We see from your search that you're looking for information on the term "Corrosion Protection", and we have a large number of manufacturers' news releases and technical articles here on Engineeringtalk which will be of interest. Let me be your guide. Start with the news release Choosing the right bearing coating from Schaeffler (UK), which we summarised at the time by saying "Dr Steve Lacey, Schaeffler UK Engineering Manager, discusses the importance of selecting the right coating or corrosion-resistant material for rolling bearings operating in harsh environments". A couple of weeks before, we featured the news release Metal chain resists corrosion from Tsubakimoto UK: "Tsubaki NEP chain uses a combination of three layers of surface coating, with a highly resistant base layer that bonds a harder wear-resistant coating onto the chain bushes". In October 2007, we covered the news from Britool concerning its Britool socketry range - take a look at Socketry range expands which says: "Britool's socketry range has received another 20 boxed socket sets, 15 sets of sockets on clip rails and five extension bar sets".
more
Tank and piping completely made of noncorrodible material, such as fiberglass-reinforced plastic.
Tank and piping made of steel having a corrosion-resistant coating AND having cathodic protection. (click here for more information on Cathodic Protection.)
Tank made of steel clad with a thick layer of noncorrodible material (this option does not apply to piping).
Tank and piping are installed without additional corrosion protection measures provided that a corrosion expert has determined that the site is not corrosive enough to cause it to have a release due to corrosion during its operating life and owners/operators maintain records that demonstrate compliance with this requirement.
Tank and piping construction and corrosion protection are determined by the implementing agency to be designed to prevent the release or threatened release of any stored regulated substance in a manner that is no less protective of human health and the environment than the options listed above.
UST systems must also be designed, constructed, and installed in accordance with a national code of practice and according to manufacturers instructions.
UST systems installed before December 1988 must be protected from corrosion. These USTs must meet one of the corrosion protection standards listed above or meet one of the upgrade options described below (or close properly):
Interior lining,
Cathodic protection*, and
Internal lining combined with cathodic protection*.
* NOTE: Prior to adding cathodic protection, the integrity of the tank must have been ensured using one of the following methods:
the tank is internally inspected and assessed to ensure that the tank is structurally sound and free of corrosion or holes,
the tank has been installed for less than 10 years and uses monthly monitoring for releases,
the tank has been installed for less than 10 years and is assessed for corrosion holes by conducting two tightness tests--the first occurs prior to adding cathodic protection and the second occurs 3 to 6 months following the first operation of cathodic protection, and
Alternative Integrity Assessment: the tank is assessed for corrosion holes by a method that is determined by the implementing agency to prevent releases in a manner that is no less protective of human health and the environment than those listed immediately above.
Upgrading bare metal piping is accomplished by adding cathodic protection. NOTE: Metal pipe sections and fittings that have released product as a result of corrosion or other damage must be replaced. Piping entirely made of (or enclosed in) noncorrodible material does not need cathodic protection.
Top of page
Why might you fail to be in compliance even if you have the required prevention equipment?
It takes more than equipment to be in compliance and to have a safe facility. You must operate and maintain this equipment properly over time or you will not benefit from having the equipment.
Failure to operate and maintain equipment can lead to new releases. A spill bucket that is allowed to crack or fill up with debris is useless as spill protection. An overfill device that is not maintained may not function and your site will suddenly have a large overfill release to clean up. Corrosion protection devices or systems that are not regularly operated and maintained properly can fail and result in an expensive cleanup at your UST site.
Be sure you review the information sources on our Web pages devoted to "Operation and Maintenance of USTs".
Top of page
How do you properly close an UST?
To properly close an UST:
Notify the regulatory authority at least 30 days before you close your UST.
Determine if contamination from your UST is present in the surrounding environment. If there is contamination, you may have to take corrective action. For at least 3 years, keep a record of the actions you take to determine if contamination is present at the site (or you can mail this record to your regulatory authority).
Either remove the UST from the ground or leave it in the ground. In both cases, the tank must be emptied and cleaned by removing all liquids, dangerous vapor levels, and accumulated sludge. These potentially very hazardous actions need to be carried out carefully by trained professionals who follow standard safety practices. If you leave the UST in the ground, have it filled with a harmless, chemically inactive solid, like sand.
NOTE: Check with your state to determine any state-specific requirements for closing UST systems.
Top of page
What are the reporting and recordkeeping requirements?
UST owners must notify state or local authorities of the existence of an UST and its leak prevention measures, or of the permanent closure of an UST. Technical regulations also set guidelines for notifying authorities of spills of more than 25 gallons.
Owners and operators must also keep records on:
Inspection and test results for the cathodic protection system.
Repairs or upgrades.
Site assessment results after closure
A corrosion expert's analysis of the corrosion potential of the site if corrosion protection equipment is not used.
Click here for more information on reporting and recordkeeping.
Top of page
Local Navigation
Basic Information
Where You Live
A to Z Subject Index
Compliance Help
Frequent Questions
Laws
Regulations Standards
Policy Guidance
Publications
Related Links
Program Facts
State & Local Contacts
Underground Storage Tanks Program in Indian Country
Regional EPA Contacts
EPA
more
Corrosion protection methods
"Corrosion Protection"...
Dave Wilson, Editor, writes:
We see from your search that you're looking for information on the term "Corrosion Protection", and we have a large number of manufacturers' news releases and technical articles here on Engineeringtalk which will be of interest. Let me be your guide. Start with the news release Choosing the right bearing coating from Schaeffler (UK), which we summarised at the time by saying "Dr Steve Lacey, Schaeffler UK Engineering Manager, discusses the importance of selecting the right coating or corrosion-resistant material for rolling bearings operating in harsh environments". A couple of weeks before, we featured the news release Metal chain resists corrosion from Tsubakimoto UK: "Tsubaki NEP chain uses a combination of three layers of surface coating, with a highly resistant base layer that bonds a harder wear-resistant coating onto the chain bushes". In October 2007, we covered the news from Britool concerning its Britool socketry range - take a look at Socketry range expands which says: "Britool's socketry range has received another 20 boxed socket sets, 15 sets of sockets on clip rails and five extension bar sets".
more
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