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Place: The primary factor that affects internal corrosion in transmission pipelines is fow rate. Transmission/refnery-ready crude oils (including dilbit) contain very little corrosion-causing water or sediment, but internal corrosion can occur if the fow conditions in the pipeline allow these materials to accumulate and persist on the pipe foor for extended periods of time. No crude oil grades have yet been proven to be more corrosive than others, but there are measurable variations in certain corrosion-related properties of crude oil. ASTM G2051 is an industry guide for evaluating three important crude oil properties that can have an impact on internal corrosion: these are wettability, emulsion-forming tendency, and effect of crude oil on the corrosiveness of brine. Based on our investigation so far, there does not appear to be any correlation between the crude oil grade and these corrosion-related crude properties. Our tests have shown these properties to vary as much within a crude grade as they do between different crude grades. Moghissi: Corrosion in crude oil pipelines is often attributed to microbiologically infuenced corrosion (MIC). The most signifcant factor in evaluating the likelihood of MIC is whether water and solids suspended in the oil remain entrained or fall to the bottom of the pipe. The critical velocity for entrainment depends upon physical properties of the oil (e.g., heavy crudes have lower critical velocities) and throughput. With everything else being the same, pipelines with slow fow (below critical velocity) tend to be more susceptible to corrosion than those with high fow (above critical velocity). Mosher: The primary method of crude oil corrosion within transmission lines is underdeposit corrosion. Particles settling at the bottom of the pipeline establish an environment that can promote a waterwetted surface. The chemical properties of the settled water and presence/absence of active bacteria could vary between crude oil sources, but (to my knowledge) there is no literature comparing the corrosiveness of waters from different crude oils. However, several papers have been published that show crude oils can inhibit the corrosiveness of water when mixed together. Settling NACE International, Vol. 52, No. 5 of solids during the transportation process is largely governed by elevation changes in the pipeline. In areas of overbends or under bends in the pipeline, the fuid dynamics can promote the settling of particles where they would otherwise be carried safely through the pipe. I have seen no evidence— scientifc or statistical—indicating that one type of crude is noticeably more corrosive than another under standard pipeline operating conditions. Papavinasam: Industry has established that the BS&W; of oil transmission pipelines is lower than 1% (typically lower than 0.5 %) volume to volume. The result of low amounts of water in oil transmission pipelines is a low probability of internal corrosion. However, locations where water accumulates may be susceptible to corrosion. ASTM G205 classifes the crude oils into four categories in terms of how they affect the corrosivity of the water phase and provides detailed and systematic procedures for determining the corrosivity of the water phase in the presence of crude oil. Tests carried out by various research and testing laboratories conclude that the corrosivity of various crude oils is low and that of dilbit is in the same range as that of other crude oils. Richter: The density difference between oil and water causes the water to tend to separate at the bottom of the pipe. This is more prone to occur with light crude oil as compared to heavy crude oil, and increases the possibility of corrosion. In addition, heavy crude oils are more likely to contain benefcial compounds that can help protect the pipeline from corrosion. These benefcial compounds can contribute to high acid numbers and/or high sulfur content. Although benefcial at lower temperatures, such as in transmission pipelines, these compounds can become corrosive at high temperatures, such as in refneries. A water wetting model is included in the MULTICORP corrosion prediction software developed by Ohio University, which allows for prediction of the fow rate necessary to keep the water entrained. Been: The presence of a small quantity of water in crude oil is inevitable. However, <0.5% of water is not considered to be a corrosion concern unless conditions exist that enable the precipitation and accumulation of this water on the pipe wall. Water drop-out and accumulation can occur at low velocities and under stagnant conditions. A model described in NACE SP0208-20082 can be used to determine the velocities at which water could drop out of crude oil as a function of the crude oil density and viscosity; the effect of temperature is minimal. Water is less likely to drop out at lower velocities when entrained in heavier crude such as dilbit as compared to typical light crude. These velocities are well below our normal operating velocities on our transmission pipelines. Increasing fow velocity and turbulence after a period of low velocity or line stoppage will reintroduce the water back into the main oil stream. Suitable models to predict the deposition of solids are not available. However, it is well understood that the deposition of sediments is minimized in highly turbulent flow. Where conditions are amenable to deposition and underdeposit corrosion, laboratory underdeposit corrosion tests have indicated that relatively low corrosion rates are expected over a wide range of crude densities. MP: How does the industry identify corrosion in a transmission pipeline or determine if a transmission pipeline is susceptible to corrosion? Been: The occurrence of internal corrosion is initially considered during the pipeline design phase, when the line is designed to operate normally under turbulent fow conditions to prevent the deposition of water and sediments. Prior to and during operation, predictive models are used to identify potential susceptible locations, with continuous consideration of changes in operational parameters. Cleaning pigs and intelligent pigs are used to regularly assess the pipeline condition during operation. Richter: Corrosion is identifed with systematic inspections, which include measuring the wall thickness and the corrosion rate. The susceptibility to corrosion is determined in part by predictions based on the water chemistry, fow characteristics, temperature, and in part by corrosion measurements. Typically, corrosion in crude oil pipelines occurs due to dissolved acid gases and water, both of which have been mostly May 2013 MATERIALS PERFORMANCE 31