A test spool containing two sets of sensors has been inserted in a high pressure environment of a natural gas production plant. The two flange-type sensors are configured so that moisture was more likely to accumulate at one than the other. Electrochemical noise (EN), linear polarization resistance (LPR), and harmonic distortion analysis (HDA) are used in combination to monitor the corrosion occurring in the plant. The 100-day corrosion data for the vertical and horizontal sensors show that corrosion rates were low and averaged ~0.0055 mm/yr. The measured B values were 0.035 V for the vertical sensor and 0.033V for the horizontal sensor, higher than the typical assume value of 0.026 V. The pitting factors were similar between the two sensors except that the vertical set had a prolonged higher pitting factor of 0.1 at the initiation of the test.
Natural gas transmission pipelines are essential to the economics and security of most nations. In the US and Canada, the 180,000 mile network of steel transmission pipelines is more than 50 years old and has suffered some deterioration due to corrosion. While corrosion can occur on both external and internal surfaces of pipelines, internal corrosion is the subject of interest for this paper. Current methods of determining internal corrosion attack in pipelines rely on after-the-fact inspections using smart pigs.
A study1 conducted in the USA from 1970 to 1984 reported that 54% of the service failures to gas pipelines were attributable to outside forces such as earth movement, weather, and third party equipment operation. In addition, 17% were attributable to material failures, and 17% to corrosion. A later study2 in Canada from 1980 to 1997 concluded that 63% of pipeline failures were caused by corrosion, with 50% due to internal corrosion and 13% due to external corrosion.
Internal corrosion of gas transmission pipelines is dependent entirely on the purity of the gas. The presence of moisture, salts, organics, CO2, and sulfur containing species such as H2S can initiate and accelerate corrosion of the transmission pipelines.
Although corrosion failures represent a significant proportion of the number of total failures of natural gas pipelines, it is now possible, using currently existing technology, to reduce the number of those failures. A proposed corrosion monitoring strategy involves the coupling of advanced corrosion sensors with advanced pigs. Corrosion sensors can be used both internally and externally in critical pipeline sections, in non-pigable pipeline sections, and routinely placed throughout the pipeline network. Corrosion sensors are important because they can be placed in critical pipeline sections, where there is high corrosion activity or where pigs cannot be used. They can provide daily information where none is now available.
The advantages of placing corrosion sensors in pigable sections of the pipeline network are fourfold: (1) regularly-spaced corrosion sensors can be coupled with modeling software that will translate corrosion measurements into a measure of corrosion damage and an assessment of likelihood of pipeline failure before that failure occurs; (2) measurements from corrosion sensors can be used to improve the efficiency of pig inspections by flagging pipeline sections with significant corrosion activity for future inspections; (3) because the use of pigs is expensive, corrosion sensors can extend the period of time between pig inspections; (4) the sensors have the added benefits of being able to determine inhibitor effectiveness and of detecting the frequency of two-phase slug flow (liquid and gas).
