MANAGING CORROSION OF PIPELINES THAT TRANSPORT CRUDE OILS

Oil and gas pipelines play a critical role in delivering the energy resources needed to power communities around the world. In the United States alone, according to the U.S. Department of Transportation (DOT), more than 2.5 million miles of pipelines — enough pipeline to circle the earth approximately 100 times — deliver oil and gas to homes and businesses.

While pipelines are recognized by government agencies such as the DOT and the National Transportation Safety Board (NTSB) as being one of the safest and most efficient means of transporting these commodities, their use still poses an intrinsic risk due to failures and leaks. Although major pipeline failures occur infrequently, several pipeline incidents in recent years have put the issue of pipeline safety into prominent view. In response, both the Canadian National Energy Board (NEB) and the DOT are implementing measures that promote pipeline safety and security.

To better understand how corrosion can impact the safety and reliability of transmission pipelines, NACE International asked several of its members in the oil and gas industry to comment on the challenges faced by the industry when managing corrosion of pipelines, in particular the pipelines that transport crude oils. This report will be presented in two parts with the second article in April.

Panelists are Jenny Been with TransCanada Pipelines; Oliver Moghissi with DNV; Michael Mosher with Alberta Innovates-Technology Futures; Sankara Papavinasam, FNACE,(1) with CanmetMATERIALS; Trevor Place with Enbridge Pipelines; and Sonja Richter with Ohio University. (See their biographies in the sidebar, “Meet the Panelists.”)

NACE: The oil industry is facing concerns by the general public that heavy crude oils, particularly diluted bitumen (dilbit), are corrosive and can lead to leaks and oil spills from transmission pipelines. What are the main challenges the industry faces when managing corrosion of pipelines that transport crude oils?

Moghissi: Internal corrosion is one of many possible threats to a crude oil transmission pipeline that must be managed. It should be noted that crude oil by itself is not corrosive at pipeline conditions, but water can drop out of the crude oil and allow corrosion to occur where it accumulates.

Water carried by heavy crude oils, including dilbit, does not significantly differ in corrosivity from water carried by other crudes. Corrosion in crude oil pipelines is addressed by conventional corrosion control practices and is generally effective. However, pipelines travel over long distances, and what is considered unlikely at one location can become significant when summed over a pipeline infrastructure.

Place: Crude oils, including dilbit, are not corrosive in pipelines. The main technical challenge is that trace water and sediments — not the crude oil — cause corrosion. The presence of crude oil, including the dilbits we have tested, actually decreases the corrosiveness of the standard brine used in standard testing. Although we know that we have a minimally corrosive system, we think it may be possible to reduce corrosion even further — and this possibility is what drives our research and development efforts.

It is challenging to accurately measure very small or very rare things, and the corrosion that occurs in transmission pipelines is typically isolated and progresses rather slowly; this makes it difficult to identify and assess the likelihood of internal corrosion, and also to evaluate the beneficial effects of mitigation activities.

Mosher: One of the main challenges facing the industry with respect to managing corrosion of crude oil transmission pipelines is the difficulty in predicting internal corrosion. Most internal corrosion in crude oil transmission pipelines is caused by the settling of solid particles that can carry water to the pipe surface. Transmission tariffs are set to limit basic sediment and water (BS&W) to <1% (often 0.5%). The solid particles tend to be encapsulated by a layer of water that may concentrate water on the pipe wall surface. This creates the potential for corrosion to occur if the flow conditions of the pipeline system allow for these solids to settle out.

The water (an electrolyte) is a necessary component of the corrosion cell. Without it, corrosion will not occur at appreciable rates within the transmission pipeline. This type of corrosion is typically referred to as underdeposit corrosion and will often manifest as localized pitting. Moreover, pitting corrosion can proceed rapidly or lay dormant for extended periods of time, making this type of corrosion particularly difficult to predict.

Richter: The main challenge is to manage the water that is transported along with the crude oil and is responsible for the corrosion that occurs if it is in contact with the pipeline wall. Crude oils are not corrosive at temperatures encountered in pipelines. It is not until crude oils are heated in refineries that they can become corrosive. The industry severely limits the amount of water allowed into transmission lines to <0.5% by weight.

While this small amount of water (which is heavier than the oil) can easily be kept off the pipeline wall and entrained in the crude oil, it is a challenge for the industry if production (and flow rates) decreases, making it more challenging to keep the water entrained and off the pipeline walls. However, heavier crude oils entrain the water more easily than lighter crude oils, which is beneficial for corrosion protection.

Papavinasam: The main challenge the industry faces is to establish public confidence that the risk due to internal corrosion of oil transmission pipelines is low and that the risk can continue to be managed at the lower level using established engineering practices. Under normal oil transmission pipeline operating conditions, corrosion occurs by an electrochemical mechanism. Crude oil (including dilbit), being a non-conducting electrolyte, does not support corrosion. However, if the crude oil contains water, then corrosion may take place in those locations where water drops out of crude oil and comes in contact with the metallic surface. The bulk crude oil may indirectly affect the corrosion by influencing the locations where water may accumulate and by influencing the corrosivity of water in those locations.

The pipeline operators keep the risk of internal corrosion in oil transmission pipelines at a lower level by limiting the amount of water to <1% BS&W (typically to <0.5%). However, based on some non-scientific reports and extrapolation of corrosive conditions of refineries (operating above 200 oC) to the conditions of oil transmission pipelines (operating typically below 70o C), some members of the public are concerned that crude oils are corrosive.

NACE: What are the characteristics of crude oils and the transportation process that could lead to transmission pipeline corrosion? Are some crude oil grades more corrosive than others?

Place: The primary factor that affects internal corrosion in transmission pipelines is flow rate. Transmission/refinery-ready crude oils (including dilbit) contain very little corrosion-causing water or sediment, but internal corrosion can occur if the flow conditions in the pipeline allow these materials to accumulate and persist on the pipe floor 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 influenced corrosion (MIC). The most significant 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 flow (below critical velocity) tend to be more susceptible to corrosion than those with high flow (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 water-wetted surface. 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 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 fluid dynamics can promote the settling of particles where they would otherwise be carried safely through the pipe. I have seen no evidence — scientific 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 classifies crude oils into four categories in terms of how they affect corrosivity of the water phase and provides detailed and systematic procedures for determining corrosivity of the water phase in the presence of crude oil. Tests carried out by various research and testing laboratories conclude that 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 beneficial compounds that can help protect the pipeline from corrosion.

These beneficial compounds can contribute to high acid numbers and/or high sulfur content. Although beneficial at lower temperatures, such as in transmission pipelines, these compounds can become corrosive at high temperatures such as in refineries. A water wetting model is included in the MULTICORP corrosion prediction software developed by Ohio University, which allows for prediction of the flow 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 dropout 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 flow 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.

Been: The occurrence of internal corrosion is initially considered during the pipeline design phase when the line is designed to operate normally under turbulent flow 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 identified 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, flow 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 separated out before the crude oil enters the transmission pipeline.

Moghissi: The most common way to predict susceptibility to corrosion is to determine water content (usually measured as BS&W) and compare pipeline throughput to the critical entrainment velocity. Consideration can be given for the water chemistry, presence of corrosion inhibitors (including both carryover or injected), any biocide treatments, and whether the pipeline is pigged. Ultimately, the existence of corrosion damage can be verified by methods such as inline inspection (ILI), pressure testing, and/or internal corrosion direct assessment (ICDA). Each of these methods has different strengths and weaknesses.

Papavinasam: The industry assesses the susceptibility of oil transmission pipelines to internal corrosion by two processes: direct assessment and ILI. NACE SP0208-2008 documents the use of the direct assessment method and proposes a four-step process to identify the causes of corrosion in oil transmission pipelines: pre-assessment (collect and analyze pipeline operating data); indirect inspection (identify locations susceptible to corrosion based on operating data collected); direct inspection (inspect the locations predicted to be susceptible to internal corrosion); and post-assessment (establish the frequency of subsequent inspections). NACE SP0208-2008 also lists several models that can be used to predict the location of water accumulation in the indirect inspection step.

NACE Task Group 477 is developing a standard report to provide guidelines for selecting the most appropriate model for this purpose. NACE SP0102-20103 provides guidelines to perform ILI where instrumented tools (commonly known as intelligent pigs) are sent through the pipeline for determining the remaining wall thickness of the pipeline.

Mosher: ILI tools, such as magnetic flux leakage (MFL), ultrasonic testing (UT), or a combination of both, give the pipeline operator a “snapshot in time” of the internal and external condition of their pipeline. Corrosion features over a certain threshold are measured by the instrument as it passes through the pipeline. In addition, the location of the pig is recorded using a global positioning system (GPS). The tool gives the location of any anomalies detected along the length of the pipeline inspected.

Anomalies of significant size/depths will often be validated by an excavation of the pipe. Often operators will use sequential ILI runs to predict the corrosion rates of anomalies and schedule future ILI runs based on their calculations. Other methods of identification include the NACE protocol for ICDA of liquid petroleum pipelines (NACE SP0208-2008) and hydrotesting.

Place: Corrosion typically takes time to occur on a transmission pipeline and pipelines could easily operate for more than 20 years before sufficient evidence of corrosion would demonstrate susceptibility. In the past, such identification was usually afforded though inline pipeline integrity inspection tools (smart pigging) used to identify areas of internal corrosion metal loss. This was a purely “reactive” evaluation of corrosion susceptibility.

Enbridge now uses proactive operational analysis. An in-house susceptibility model based on theoretical analysis, in conjunction with our extensive pipeline operational history of more than 60 years, is used to assess the likelihood that water could accumulate in a pipeline. The primary driver in this analysis, as discussed previously, is flow conditions. The ability of flowing oil to harmlessly transport trace corrodents like water and sediment is related to velocity, density and viscosity of the oil. I believe most pipeline operators use either a theoretical model; an empirical experience-based model; or, like Enbridge, both.

(1)FNACE denotes a NACE International Fellow.

source : http://www.pipelineandgasjournal.com/managing-corrosion-pipelines-transport-crude-oils?page=6