Prevention of Corrosion in Pipelines
Source: http://primis.phmsa.dot.gov/iim/docstr/finalreport_pipelinecorrosion.pdf
Corrosion is defined as the deterioration of a material, usually a metal, that results from a reaction with its environment. Pipelines can be subject to external corrosion and internal corrosion. The most common form of corrosion is pitting corrosion, but various forms of environmentally assisted cracking, such as stress-corrosion cracking (SCC), hydrogen-stress cracking, hydrogen-induced cracking, and sulfide-stress cracking (SSC), also have been observed.
External corrosion is controlled with coatings and cathodic protection. Cathodic protection is a method to prevent corrosion by imposing a direct current onto the pipe at places where the coating is missing. Corrosion problems can arise if the coating becomes disbonded from the pipe and allows groundwater to contact the steel pipe but shields that portion of the pipe from the cathodic-protection currents.
Preventive measures for internal corrosion vary according to the type of product carried in the pipeline and the type of contamination.
Typically, sales-quality dry gas will not corrode interior surfaces of a pipeline. However, natural gas, as it comes from the well, may contain small amounts of contaminants such as water, carbon dioxide, and hydrogen sulfide. If the water condenses, it can react with the carbon dioxide or hydrogen sulfide to form an acid that might collect in a low spot and cause internal corrosion.
Internal corrosion also can occur in hazardous liquid pipelines that carry corrosive liquids or liquids that contain corrosive contaminants. Liquid pipelines can experience internal corrosion anywhere along their length where electrolytes or solids drop out and wet the surface or where sags in the pipeline provide a place for electrolytes to collect.
Dehydration is the most commonly applied measure to protect against internal corrosion in gas pipelines and in liquid pipelines that contain oil with free water or other electrolytes.
Coatings or plastic liners sometimes are used to control internal corrosion, but they are not failsafe because breaks in the coating or pinholes in the liner can allow liquids to contact the pipe. Therefore, many operators who use coatings or liners also employ additional preventive measures.
Other preventive measures include the use of buffering agents, cleaning pigs to remove corrosive liquids or solids, and drip legs to trap contaminants.
If microbiologically influenced corrosion (MIC) is a problem in liquid pipelines, biocides can be injected into the pipeline. To prevent MIC in gas pipelines, the electrolyte at the pipe wall must be removed by drying the gas.
Methods for monitoring internal corrosion include the use of removable corrosion coupons or probes to measure moisture level, liquid conductivity, pH, or wall thickness.
Another form of degradation falls within the definition of corrosion is environmentally assisted cracking (EAC), in which the combined action of a tensile stress and a corrosive environment causes cracks to form in the metal. There are a number of different cracking mechanisms within the category of EAC; the most important are SCC, hydrogen-stress cracking, and SSC. In comparison with pitting corrosion, EAC results in relatively few significant incidents.
Since its discovery in 1965 as a possible cause of failures in pipelines, external SCC has caused, on average, one to two failures per year in the United States. The failures involved older pipe that had been coated in the field, or in one case, not coated at all. No instances of SCC have been reported for the newer pipe with mill-applied coatings, despite the fact that some pipelines with mill-applied coatings have been in service for more than 40 years. This is believed due to several factors that include better surface preparation, compressive residual stresses from the grit blasting, and improved coating properties. It is widely accepted that the use of such coatings is an effective way to prevent SCC.
To date, there have been no reported cases of internal SCC in North America. However, with the increasing use of ethanol as a gasoline additive, the pipeline industry is considering the transport of denatured ethanol in its pipelines. Recently, concern has been raised about the possibility of internal SCC in pipelines that would transport ethanol or ethanol/gasoline blends, as SCC has been observed inside storage tanks and user terminals that contain fuel-grade ethanol. The determination of safe conditions for transporting ethanol and ethanol/gasoline blends in pipelines is currently the subject of intense research.
Hydrogen-stress cracking is a delayed-failure mechanism that sometimes occurs in high-strength steels that have absorbed hydrogen produced at the surface through an electrochemical reaction (corrosion or cathodic protection). Line-pipe steels of grades up to and including at least X80 that exhibit normal properties are not considered susceptible to hydrogen-stress cracking. However, some hydrogen-stress cracking failures have occurred in unusually hard regions of X52 pipe. Hard spots can be detected with magnetic-flux leakage in-line inspection (ILI) pigs. The preferred method of preventing hard-spot failures is to locate and remove the hard spots rather than try to eliminate the source of the hydrogen.
SSC is a type of spontaneous brittle failure that occurs in steels and other high-strength alloys upon contact with moist hydrogen sulfide and other sulfidic environments. Some researchers consider SSC a type of SCC, while others consider it a type of hydrogen-stress cracking. SSC in pipelines can occur from two sources: internally, from transporting wet, sour products, or from water containing sulfatereducing bacteria (SRB); and externally, from SRB in soil or water that contact the pipe. Reported failures due to SSC are relatively few. Internal SSC is far more common than external, which is rare. Susceptibility to SSC is a function of a number of variables; two of the more important are strength or hardness of the steel and the level of tensile stresses. For any steel, there is a minimum applied stress, called the threshold stress, below which failure due to SSC will not occur. The threshold stress decreases as the strength level increases. Therefore, the common way to prevent SSC failures is to maintain a maximum strength level of 80,000 psi for steel pipe that is exposed to wet hydrogen sulfide environments. It also is important to control the welding processes to make sure that they do not induce regions of high hardness and high residual stress.
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