File Name: external corrosion and corrosion control of buried water mains .zip
Download this paper. This basic methodology works equally well in deep water as it does in shallow. There are however some very important differences in the way corrosion control systems operate in deep water versus shallow water.
Not a MyNAP member yet? Register for a free account to start saving and receiving special member only perks. The offshore pipeline industry, since its first ventures into the Gulf of Mexico and the waters off California more than 40 years ago, has steadily improved its operating practices, with new materials, more robust designs, and more efficient techniques for construction, operation, and maintenance.
Today it operates with confidence in waters as deep as 1, feet, with near-term plans for depths of 3, feet Salpukas, Technology is being developed for pipelines in much deeper waters, up to perhaps 6, feet. Despite this progress, the marine environment is a challenging one for pipelines, and maintaining their integrity requires vigilance. Repairs and inspection are costly for underwater pipelines, and the emphasis is accordingly on preventing damage and deterioration.
Corrosion protection has advanced to a state at which pipelines may serve far beyond their original expected service lives although isolated corrosion is still a troublesome and costly source of pinhole leaks. Leak detection programs use combinations of visual detection from boats and aircraft, automated metering of pressures and flows in pipelines, and monitoring of the flows in entire pipeline networks.
Workers are highly trained to carry out routine operations and maintenance; more recently, enhanced training for emergency response has been mandated by regulators. Much of the pipeline inventory has remained in use beyond its originally intended service life.
About one-fourth of the pipeline mileage in the federal waters of the outer continental shelf is more than 20 years old, and the average age is rising steadily Minerals Management Service, Pipelines in state waters are even older, with some dating from the early s, when offshore pipeline construction began. Coatings, cathodic corrosion protection, and internal corrosion monitoring have improved substantially since then. Still, corrosion —especially internal corrosion—is inexorable, and requires continual inspection and monitoring.
This problem is likely to grow more serious; as gas fields decline, gas pipelines will carry more liquids, and be potentially subject to increasing corrosion.
On the other hand, corrosion, while the most common reported cause of pipeline failures, presents relatively small risks. Corrosion failures tend to be small pinhole leaks, and are generally detected in time to prevent large losses of oil or gas.
As noted in Chapter 2 , the average oil pollution per corrosion incident is a little less than 13 barrels;. Marine pipelines are constructed of high-strength carbon steels in several grades, depending on size, internal operating pressure, bending and longitudinal stresses expected during construction, and anticipated environmental conditions. All piping, materials, and fittings are specified to be consistent with industry standards, promulgated by technical societies such as the American Petroleum Institute and the American Society of Mechanical Engineers.
OPS and MMS regulations specify minimum operating design and construction, post-construction, and testing standards for pipelines and components. Both agencies ' regulations cite these industry standards frequently. Corrosion may occur either internally or externally to a pipeline. It tends to occur at predictable locations. Internal corrosion in likely at low spots in pipelines and at riser elbows, where brine, bacteria, and other corrosive agents collect. Corrosion engineers take preventive measures that give priority to such high-risk locations.
Corrosion defects in pipelines develop gradually, and generally manifest themselves as small pinhole leaks, through which small amounts of product escape. A corrosion-induced failure is not a spectacular event. Small leaks of this kind are easily detectable by routine helicopter overflight. The marine environment is generally uniform and stable with respect to its corrosivity.
Pipelines are protected against corrosion by bonded coatings. On larger diameter pipelines, which would otherwise float when empty or be subject to excessive displacement by waves and currents, a concrete weight coating is added to provide stability, and incidentally some mechanical protection from objects such as the anchors of small vessels.
Specifications for corrosion-preventive coatings and their application and testing are available from several associations representing the pipeline industry and coating firms. OPS regulations prescribe testing requirements and intervals for verifying the adequacy of such protection. Criteria for hazardous liquid that is, petroleum pipelines are less prescriptive, setting only general performance standards for internal and external corrosion control; in practice, however, corrosion protection practices are similar to those used for gas pipelines.
To prevent the electrochemical process of external corrosion, marine pipelines use cathodic protection systems, which apply a small voltage to the pipe, either from an external power source or through the electrochemical reaction of two dissimilar metals. The original system anodes are generally depleted after 10 to 15 years of service and replaced with new ones. A drawback of this system is occasional interruption of electric power, supplied by generators on platforms; although occasional brief interruptions are not harmful, the relative inaccessibility of the rectifiers can make outages more frequent and longer than desirable.
The adequacy of corrosion protection—and in particular protection from external corrosion—at intermediate points, between anodes, is difficult to verify. For these reasons, impressed current systems are not often used today. Today, so-called sacrificial cathodic protection is more common. It involves the use of anodes of a sacrificial material such as aluminum or zinc, electrically bonded and attached to the pipeline as clamp-on bracelets.
These anodes are sized and spaced along the pipeline to provide uniform cathodic protection for at least 25 to 30 years, taking into account the anticipated extent of coating damage, the anode depletion rate, and other factors. One drawback of sacrificial systems is that depleted anodes cannot be as readily replaced as the single point anodes of the impressed current system.
In addition, the anodes on smaller pipes, without weight coatings, may be damaged during pipeline installation, rendering them nonfunctional and reducing the safety factor built into the system. On larger lines—the most common—the outer diameter of the anode is the same as that of the weight coating, making such damage unlikely.
Thus, the maintenance problems associated with impressed current systems are eliminated, but replaced with other possible problems. Also, as with the impressed current systems, the adequacy of protection in the intermediate sections of pipelines may be questionable unless advanced techniques such as cathodic protection surveys by remotely operated vehicles ROVs are used.
ROVs are already commonly used to assess the external physical conditions of unburied pipelines. Equipped with magnetic tracking devices and controlled from the surface, these vehicles follow the pipeline, providing visual surveys of the pipeline and bottom conditions along the route. New systems to record corrosion control data using ROVs have not yet achieved widespread use, but are increasingly accepted by the pipeline industry Weldon and Kroon, This technique produces data for only one or two points, so there is some difficulty in judging the protective status of the rest of the pipeline, which depends on such things as the condition of protective coatings and the integrity of anode-to-pipe connections.
There are two ways to get more information, whose merits depend on specific conditions of the pipeline, such as length and depth, water clarity, type of corrosion coating, whether or not the pipe is buried, and the type of corrosion protection used:. Spot monitoring of the pipeline potential is generally limited to locations where other maintenance or construction activities are being carried out by divers.
The locations of such work are independent of anode locations, which are potentially more valuable monitoring points. Still, the additional information can be useful in the absence of other monitoring opportunities.
Close-interval potential surveys provide a nearly continuous plot of the pipeline potential. They also can carry video cameras, which reveal even minor coating defects on pipelines that are not covered with sediments. The phenomenon of internal corrosion is well understood by the pipeline industry, but requires increasing attention as pipelines and oil and gas producing fields age.
In both gas and liquid lines, corrosive mixtures of foreign materials such as brine, drilling fluids, and bacteria from production reservoirs, not removed by production equipment, travel in the product stream. Metal loss from internal corrosion is generally concentrated at the bottoms of the pipe and at low spots, especially in gas lines because the corrosive substances tend to be heavier than oil or gas. In some cases, a combination of erosion and corrosion can occur.
As more pipelines transport mixtures of produced fluids oil, gas, and water , corrosion problems have become more complex, but they remain manageable. The internal corrosion problem has grown more challenging in natural gas lines during the past 10 to 15 years, owing to changes in operating and economic conditions. At one time, gas accepted for purchase or transportation by many systems, was required to be dry free of entrained liquid or liquid vapors of any type, including water, hydrocarbons, distillates, or condensates produced with the natural gas.
Today pipelines are more likely to carry such liquids to shore, because of the value of the recovered liquids and the operational efficiencies of separation ashore, as well as the limited water disposal options offshore. Cooler temperatures around the pipeline on the ocean floor cause condensation of entrained liquid vapors, including water, resulting in formation of corrosive liquids Darwin, Shifts of production to deeper waters will tend to increase condensation of many of these corrosive fluids, because pipelines will carry more mixed fluids longer distances from producing fields to treatment and separation facilities, and in cooler waters.
Internal corrosion is more difficult than external corrosion to locate and quantify, owing mainly to the relative inaccessibility of intermediate sampling points on offshore pipelines. Onshore, monitoring can be performed at valve sites, stations, instrument locations, and other points, to help isolate and locate active internal corrosion. Offshore there is typically no opportunity to establish monitoring points except at the originating platform.
This location is of limited use in establishing the existence of corrosion downstream. It is far more desirable to have monitoring points at both intermediate and end points of a pipeline. Even under the best of circumstances, onshore or offshore, it may be difficult to determine where fluid velocities and pipeline profiles combine to allow water to drop out of the fluid, or to cause erosion of the pipeline; the chemistry of the fluid and the nature of entrained substances all affect internal corrosion activity.
Operators use various indirect means of monitoring internal corrosion. Fluids are often monitored continuously for corrosion products at both termini of pipelines. Small sacrificial pieces known as coupons, immersed in the flowing gas or liquid, can be removed to test for the extent of internal corrosion.
Gas pipelines most commonly use corrosion inhibitors. Liquid pipelines can rely on the flow of the liquid to keep entrained water in suspension, thus limiting accumulation of corrosive substances on the walls of the pipe. Sometimes it is possible to obtain a general indication of the rate of corrosion activity in a pipeline system by monitoring the content of iron in water emitted from the.
A high iron content would indicate need for a detailed survey and remedial action. As production declines in some offshore fields, and liquid velocity drops to the point at which water settles out, internal corrosion control in liquid pipelines will be more important. Cleaning pigs—hard rubber or inflatable plastic spheres or cylindrical devices that travel with the product flow—are often used to move foreign substances to a downstream location where they are removed from the system.
The recovered material is analyzed to determine the adequacy of the internal corrosion control measures, including any chemical inhibitor programs in use. In many pipeline systems mainly those with subsea connections with other pipelines , the use of pigs is difficult or impossible. Where feasible, it is an important means of increasing the effectiveness of internal corrosion control, used by most pipeline operators.
It not only removes corrosive materials and gives operators information on corrosion activity in the pipe, but also brings corrosion inhibiting chemicals in better contact with the pipe surface. Newer technologies have been developed to provide more precise identification and location of problem areas. In-line inspection ILI devices also known as smart pigs , discussed later in this chapter, are suitable for some pipelines, but are limited generally by the physical characteristics of existing pipeline systems, such as tight bends, restrictions in subsea junctions, and the lack of room on platforms for pig launching and receiving equipment.
Retrofitting may be difficult and expensive. Research is underway by the pipeline industry to reduce the length and weight and improve the accuracy of such devices. Internal corrosion tends to occur fairly consistently in several distinct locations of offshore pipelines: in the bends at the bases of risers pipes that connect seabed pipelines to platforms , where corrosive liquids tend to accumulate especially in gas lines ; and in small-diameter flowlines pipelines connected directly to producing wells , where corrosive liquids and sand are contained in the unprocessed fluids.
Knowledge of these patterns allows the targeted use of specific inspection measures and remediation techniques. Equipment and piping maintenance performed on marine pipeline facilities that are above the water line is very similar to that performed onshore. Maintenance procedures and inspection and calibration intervals are established based on the type of equipment involved, the potential consequences of failure, and the likelihood of various failure modes.
The purpose of this preventive maintenance is to prevent equipment failure which could have adverse safety, environmental, operational, or financial consequences. Repairs are performed as needed, according to established procedures. The same general principles apply to marine pipelines facilities on the seabed.
Corrosion of metallic pipelines is a significant source of failures and a financial burden to drinking water utilities. A large portion of drinking water infrastructure is reaching the end of its useful service life. In the United States, the annual total of water main breaks attributed primarily to corrosion was estimated as , breaks per year. As part of an ongoing Water Research Foundation project WRF , technical and economic considerations for cathodic protection CP installation and retrofit of buried water pipelines have been investigated to generate a best practice guide tailored for water utilities. CP of metallic structures is commonly achieved by galvanic protection or impressed current protection, depending on the specificities of the system.
Buried Water Mains Solving Corrosion Problems at Water Main Breaks. 8. Cathodic Protection Performance Verification. Topics to be.
American Water Works Assoc. Andrew E. Romer , Graham E.
Corrosion and cathodic protection CP are electrochemical phenomena. Understanding corrosion and CP requires a basic knowledge of chemistry and electrochemistry. Electrochemistry is a branch of chemistry dealing with chemical changes that accompany the passage of an electric current, or a process in which a chemical reaction produces an electric current. Examples of structures where cathodic protection is employed include underground tanks and pipelines; aboveground storage tanks; water tank interiors; ship hulls; ballast tanks; docks; sheet piling; land and water foundation piles; bridge substructures; tube sheets; oil heater treaters; and reinforcing steel in concrete.
In order to ensure smooth and uninterrupted flow of oil and gas to the end users, it is imperative for the field operators, pipeline engineers, and designers to be corrosion conscious as the lines and their component fittings would undergo material degradations due to corrosion. This paper gives a comprehensive review of corrosion problems during oil and gas production and its mitigation. The chemistry of corrosion mechanism had been examined with the various types of corrosion and associated corroding agents in the oil and gas industry. Factors affecting each of the various forms of corrosion were also presented.
The sacrificial metal then corrodes instead of the protected metal. For structures such as long pipelines , where passive galvanic cathodic protection is not adequate, an external DC electrical power source is used to provide sufficient current.
Norsworthy, Richard. As important as cathodic protection is to external corrosion control, it may not be the most important issue facing those concerned with preventing external corrosion. The NACE International SP document clearly states the intent of the document is to provide guidance for effective control of external corrosion. Many seem to ignore the intent of this document and concern themselves only with cathodic protection and related criteria. We must consider the other parts of the document and how to effectively control external corrosion with all possible methods with an understanding of how these methods work together to provide expected performance. SP This standard practice presents procedures and practices for achieving effective control of external corrosion on buried or submerged metallic piping systems.
Not a MyNAP member yet? Register for a free account to start saving and receiving special member only perks. The offshore pipeline industry, since its first ventures into the Gulf of Mexico and the waters off California more than 40 years ago, has steadily improved its operating practices, with new materials, more robust designs, and more efficient techniques for construction, operation, and maintenance. Today it operates with confidence in waters as deep as 1, feet, with near-term plans for depths of 3, feet Salpukas, Technology is being developed for pipelines in much deeper waters, up to perhaps 6, feet.
These have an outer coating of highly insulating material to prevent the ingress of water that will also act as a barrier to cathodic protection currents. If possible an.
Strategic management dictates that the arrangement for corrosion control and monitoring should be made during project construction. Contractual obligation cannot absorb such a cost. Emenike, C. Report bugs here.
Gan, Z. Sun, G. Sabde, D.
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