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occur," he comments. Water accumulation in a pipeline can vary depending on the type of crude oil being transported, and NACE Standard SP0208-2008,2 which is applicable to dilbit as well as conventional crude oils, provides several models to predict how water may IKK]U]TI\M .WZ M`IUXTM I PQOP ÆW_ ZI\M which is typically associated with a lower likelihood of corrosion, will promote the entrainment of the water and solid particles, PMTXQVO \PMU \W ÆW_ ITWVO \PM XQXMTQVM without dropping out of the oil and coming QV\W KWV\IK\ _Q\P \PM [\MMT XQXM 1N \PM ÆW_ rate drops to a lower level, then the water IVL [WTQL[ UIa ÆW_ ITWVO \PM JW\\WU WN \PM pipeline and come in contact with the steel wall, which may increase the likelihood of KWZZW[QWV 1N \PM XQXM ÆW_ Q[ [\IOVIV\ I[ KIV happen in a deadleg pipe, the water and solids may accumulate on the bottom of the pipe and further increase the likelihood of corrosion. Although accumulated water can initiate internal pipeline corrosion, the corrosion rate—how fast the pipe will deteriorate— depends on the water chemistry and the [XMKQÅK KWZZW[QWV UMKPIVQ[U \PI\ Q[ XZM[- ent. Moghissi notes that the most common internal corrosion mechanism in crude oil XQXMTQVM[ Q[ UQKZWJQWTWOQKITTa QVÆ]MVKML corrosion (MIC), corrosion brought about by the presence and/or activities of micro- WZOIVQ[U[ QV I JQWÅTU _PQKP KWV[]UM \PM pipe metal as they grow. Another form of internal pipeline corrosion is carbon dioxide (CO2 an oil or gas stream is dissolved in water and forms carbonic acid (H2 ) corrosion that occurs when CO2 CO3 in ), which corrodes carbon or low-alloy steel. CO2 corrosion can be mitigated with chemical corrosion inhibitors injected into the pipe- line. Internal corrosion can also be caused by the presence of oxygen, which will react with and corrode elements such as iron. Because of this, pipeline operators work to exclude oxygen. The presence of internal corrosion in a pipeline can be detected using various inspection technologies such as inline in- spection (ILI) smart pigs, which are widely used in the United States to examine crude oil transmission pipelines. When a corro- [QWV UMKPIVQ[U PI[ JMMV QLMV\QÅML I[ I threat, a mitigation strategy is developed and implemented using industry-recognized procedures for controlling internal corro- sion, which could include a combination of NACE International, Vol. 51, No. 11 corrosion inhibitors, biocides, cleaning by pigs, and other methods. NACE Standard SP0106-20063 (which is currently being re- vised) provides recommended practices for internal corrosion control in steel pipelines and piping systems used to gather, trans- port, and distribute crude oil, petroleum products, and gas. To determine if the cor- rosion mitigation program is effective and the corrosion threat has been alleviated, a pipeline monitoring program is set up using methodologies such as coupons, probes, and sampling. Moghissi emphasizes that internal cor- rosion of crude oil transmission pipelines is an issue that is aggressively managed by industry, and many corrosion engineering tools are available and utilized for mitigat- ing corrosion of conventional crude oil pipelines as well as pipelines that transport dilbit. Although corrosion-induced failures do occur, the data show that the leading failure mechanism of an operating crude oil pipeline is mechanical impact damage caused by a third party. Crude Oil Pipeline Failures In its presentation to the NAS commit- PHMSA reported that 22.1 pipeline tee,4 incidents/failures per year (0.42 failures per 1,000 pipeline miles/year [1,609 pipeline km/year]) were caused by internal corro- sion and 9.8 pipeline incidents/failures per year (0.19 failures per 1,000 pipeline miles/ year) were caused by external corrosion out of a total of 89.3 pipeline incidents/failures per year (1.7 failures per 1,000 pipeline miles/year) between 2002 and 2010. These ÅO]ZM[ IZM JI[ML WV UQTM[ WN KZ]LM oil pipelines in the United States as of 2009, _Q\P QVKQLMV\[ LMÅVML I[ ZMTMI[M[ WN JJT ! 4 WZ UWZM 805;) IT[W ZMXWZ\ML a total of nine pipeline incidents (0.16 in- cidents per 1,000 pipeline miles/year) for both internal and external corrosion out of a total of 128 incidents (2.29 incidents per 1,000 pipeline miles/year) between IVL NWZ UQTM[ WN KZ]LM WQT pipeline from the bituminous sands region to the United States. The Canadian Energy Resources Con- [MZ^I\QWV *WIZL -:+* QLMV\QÅML \PZMM [XQTT[ JM\_MMV !! IVL ZM[]T\QVO NZWU internal corrosion in pipelines shipping bitu- men and blends of bitumen, with a resulting average failure frequency of 0.03 per 1,000 SU aMIZ# IVL MQOP\ [XQTT[ JM\_MMV ! 2010 for this group of crude oil pipelines. IVL "When you consider the number of miles of pipe, the incidence of corrosion-related failures is low," Moghissi stresses. "It is also generally accepted that pipelines are the saf- est and most reliable mode of transporting crude oil over large distances." Corrosivity of crude oil and pipeline cor- rosion are technically complex issues that are always being studied and evaluated through- out the industry. "As a leading provider of standards and education for corrosion con- trol and mitigation in the oil and gas industry, NACE is continually delivering opportunities for corrosion professionals and others to discuss corrosivity of dilbit and conventional crude oils as well as other corrosion-related topics that affect the oil and gas industry," says NACE Executive Director Bob Chalker. As part of this effort, NACE sponsors several technical committees that focus on pipeline corrosion, which provide a forum for indus- try experts from around the world to meet and form a consensus on the best techniques and practices for controlling corrosion of liquid petroleum and gas pipelines. Recently NACE Task Group (TG) 447 was formed to LM^MTWX I [\I\M WN \PM IZ\ ZMXWZ\ WV ÆW_ IVL corrosion modeling referred to in existing internal corrosion direct assessment (ICDA) documents, which will provide guidelines for selecting models for various conditions. Also, in October, the NACE Northern Area hosted its three-day Eastern conference in Toronto, Ontario, Canada, where profes- sionals met and discussed the corrosivity of crude oils under pipeline transportation conditions and the pros and cons of various management methods to control it. The proceedings of this conference are available through NACE. Editor's Note: A version of this article was previ- ously published in the World Pipelines 2012 Coatings & Corrosion issue. References 1 A. Swift, et al., "Tar Sands Pipelines Safety Risks," Joint Report by Natural Resources Defense Council, National Wildlife Federation, Pipeline Safety Trust, and Sierra Club, February 2011. 2 NACE Standard SP0208-2008, "Internal Corrosion Direct Assessment Methodology for Liquid Petroleum Pipelines" (Houston, Texas: NACE International, 2008). 3 NACE Standard SP0106-2006, "Control of Internal Corrosion in Steel Pipelines and Piping Systems" (Houston, Texas: NACE International, 2006). 4 L. Daugherty, et al., "National Academy of Sciences, Transportation Research Board, Study of Pipeline Transportation of Diluted Bitumen, Pipeline and 0IbIZLW][ 5I\MZQIT[ ;INM\a )LUQVQ[\ZI\QWV *ZQMÅVO º July 23, 2012. -VMZOa :M[W]ZKM[ +WV[MZ^I\QWV *WIZL ¹-:+* Addresses Statements in Natural Resources Defense Council Pipeline Safety Report," News Release, Febru- ary 16, 2011 November 2012 MATERIALS PERFORMANCE 29