{"operation":"document","citation":"DCA15MP002","title":"Colonial Pipeline Company Petroleum Product Leak","source_type":"incident","agency":"National Transportation Safety Board","status":"current","official":true,"published_on":"2017-06-05","effective_on":"2015-09-21","summary":"Accident. in Centreville, VA, USA. on 2015-09-21. Colonial Pipeline. Leak","machine_formats":{"json":"https://regulus.evalyn.ai/document/ntsb-case-dca15mp002.json","markdown":"https://regulus.evalyn.ai/document/ntsb-case-dca15mp002.md"},"app_url":"https://regulus.evalyn.ai/document/ntsb-case-dca15mp002","source_url":"https://www.ntsb.gov/investigations/Pages/DCA15MP002.aspx","body":"NTSB investigation DCA15MP002.\n\nEvent Type: Accident\n\nEvent Date: 2015-09-21\n\nEvent City: Centreville\n\nEvent State Or Region: VA\n\nEvent Country: USA\n\nPipeline Operator: Colonial Pipeline\n\nPipeline Type: Hazardous Liquid - Regulated\n\nAccident Type: Leak\n\nCompletion Status: Completed\n\nReport Number: PAB1701\n\nReport Date: 2017-06-05\n\nProbable cause: The National Transportation Safety Board determines that the probable cause of the release of gasoline and other refined petroleum liquids from the Colonial pipeline was a through-wall corrosion fatigue crack that developed at a dent in the pipeline due to residual and operational stress and exposure to the underground environment. Contributing to the accident were vague Pipeline and Hazardous Materials Safety Administration regulations that allowed the dent to remain in the pipeline. Also, contributing to the delay in recognizing the release were the limitations of pipeline Supervisory Control and Data Acquisition systems to detect small pipeline leaks.\n\nTier1Name: System operating\n\nTier2Name: Pressure/flow control malf/failure\n\nTier1Name: System shutdown\n\nTier2Name: Maintenance event\n\nTier1Name: Post-release\n\nTier2Name: Emergency response\n\nTier1Name: System operating\n\nTier2Name: Product leak/release\n\nTier1Name: Pigging\n\nTier2Name: System warning/signal\n\nTier1Name: System operating\n\nTier2Name: Inspection event\n\nFinding Tier1Name: Organizational\n\nFinding Tier2Name: Support/oversight/monitoring\n\nFinding Tier3Name: Safety programs\n\nFinding Modifier Name: Federal agency\n\nFinding Report Text: Organizational - Support/oversight/monitoring - Safety programs - Federal agency\n\nFinding Tier1Name: Environment/Infrastructure\n\nFinding Tier2Name: Operating environment/control system\n\nFinding Tier3Name: SCADA system\n\nFinding Modifier Name: Awareness of condition\n\nFinding Report Text: Environment/Infrastructure - Operating environment/control system - SCADA system - Awareness of condition\n\nFinding Tier1Name: Pipeline\n\nFinding Tier2Name: Pipeline structure\n\nFinding Tier3Name: Pipe\n\nFinding Modifier Name: Fatigue/wear/corrosion\n\nFinding Report Text: Pipeline - Pipeline structure - Pipe - Fatigue/wear/corrosion\n\nOfficial NTSB investigation data. NTSB findings determine probable cause and make safety recommendations; they do not adjudicate civil liability or regulatory violations.\n\nWhat Happened\nOn September 21, 2015, at 12:03 p.m., an employee of Bonefish Grill in Centreville, Virginia, called the Fairfax County 911 Center to report a gasoline odor. The Fairfax County Fire and Rescue Department (FCFRD) immediately dispatched units to the restaurant in the Centre Ridge Marketplace shopping center. After arriving at the scene, firefighters confirmed everyone had left the restaurant; they established an incident command center, and they began the investigation. They did not detect the presence of flammable vapor inside Bonefish Grill and ruled out a natural gas leak; however, they noted a gasoline odor coming from the storm drains at the shopping center. Firefighters detected the presence of flammable vapor in most of the storm drains behind Bonefish Grill and Chipotle. Flammable vapor in some storm drains in front of Bonefish Grill was as high as 100 percent of the lower explosive limit (LEL); however, no liquid was visible in the storm drains.\nAfter establishing that the gasoline did not come from the gas station that was located about 400 feet west of Bonefish Grill and that gasoline was not illegally dumped into a storm drain, firefighters considered that the odor could be coming from a leak in a nearby, buried Colonial Pipeline Company pipeline. Colonial confirmed the pipeline leak 2 days later.\n\nWhat We Found\nWe determined that the probable cause of the release of gasoline and other refined petroleum liquids from the Colonial pipeline was a through-wall corrosion fatigue crack that developed at a dent in the pipeline due to residual and operational stress and exposure to the underground environment. Contributing to the accident were vague Pipeline and Hazardous Materials Safety Administration regulations that allowed the dent to remain in the pipeline. Also, contributing to the delay in recognizing the release were the limitations of pipeline Supervisory Control and Data Acquisition systems to detect small pipeline leaks.\n\nWhat We Recommended\nWe made recommendations to the Pipeline and Hazardous Materials Safety Administration, the Colonial Pipeline Company, and the Association of Oil Pipe Lines and the American Petroleum Institute.\n\nPAB-17-01\n<<<PAGE 1>>>\n\nNational Transportation Safety Board\nPipeline Accident Brief\nColonial Pipeline Company Petroleum Product Leak\nCentreville, Virginia\nThe Accident\nOn September 21, 2015, at 12:03 p.m., an employee of Bonefish Grill in\nCentreville, Virginia, called the Fairfax County 911 Center to report a gasoline odor.\n1\nThe Fairfax County Fire and Rescue Department (FCFRD) immediately dispatched units to the\nrestaurant in the Centre Ridge Marketplace shopping center. (See figure 1.) After arriving at the\nscene, firefighters confirmed everyone had left the restaurant; they established an incident\ncommand center, and they began the investigation. They did not detect the presence of flammable\nvapor inside Bonefish Grill and ruled out a natural gas leak; however, they noted a gasoline odor\ncoming from the storm drains at the shopping center. Firefighters detected the presence of\nflammable vapor in most of the storm drains behind Bonefish Grill and Chipotle. Flammable vapor\nin some storm drains in front of Bonefish Grill was as high as 100 percent of the lower explosive\nlimit (LEL); however, no liquid was visible in the storm drains.2\nAfter establishing that the gasoline did not come from the gas station that was located about\n400 feet west of Bonefish Grill and that gasoline was not illegally dumped into a storm drain,\nfirefighters considered that the odor could be coming from a leak in a nearby, buried Colonial\nPipeline Company pipeline. Colonial confirmed the pipeline leak 2 days later.\n1 All times in this document are eastern daylight time.\n2 LEL refers to the lowest concentration of gas in the air that is capable of igniting. For natural gas, the LEL is\nabout 5 percent; 100 percent of the LEL means that the vapor concentration in the air is 5 percent. For gasoline, the\nLEL is about 1.4 percent.\n56301 NTSB/PAB-17/01\n\n<<<PAGE 2>>>\n\nColonial Pipeline Company Petroleum Product Leak\nFigure 1. Aerial view of the accident site; dotted lines show the locations of Colonial pipelines.\nLocating Leak and Initial Response\nAbout 1:37 p.m., the Fairfax County fire marshal’s office asked Colonial—which operates\nunderground 36- and 32-inch-diameter pipelines (lines 3 and 4, respectively) that transport\ngasoline and other refined petroleum liquids—to determine if the company’s pipelines could be\nthe source of the gasoline odor. Two Colonial right-of-way inspectors contacted the Colonial\nControl Center to determine if there were abnormalities in the pressures in lines 3 and 4.\nThe Control Center told them the line pressures were normal. The inspectors examined the\nColonial right-of-way and told the fire department incident commander there was no evidence of\na leak—including an odor, dead vegetation, or gasoline on any pavement or in nearby water\nretention ponds; the inspectors left the area about 3:30 p.m.\nWith the source of the odor still unknown, the FCFRD hazardous materials (hazmat) team\ncontinued checking the storm drain system and reviewed the storm drain drawings provided by the\nFairfax County Department of Public Works to locate the outflow points. After discovering the\noutflow culvert near Sweetwater Tavern was blocked, the hazmat team cleared the vegetation and\ndebris from the outlet of a 60-inch-diameter storm drain that ran under Bonefish Grill’s front\nparking lot. Almost immediately, the collection weir (barrier) filled with water covered with a\nblack petroleum product. The hazmat team assigned the name “recovery site 1” to the location and\nbegan pumping the black petroleum product into a 95-gallon, poly-overpack drum with a small\nportable pump. The crew also placed absorbent pillows and containment booms around the weir2\n\n<<<PAGE 3>>>\n\nColonial Pipeline Company Petroleum Product Leak\nto contain the liquid. A fire marshal investigator then notified Colonial that the hazmat team had\ndiscovered some unknown petroleum product in the storm drain.\nWithin about 5 hours of the initial odor complaint, the hazmat unit had collected about\n90 gallons of product (a combination of liquid hydrocarbon and water). Because some product\nremained in the storm drain, the Fairfax County fire marshal’s office requested assistance from a\nhazmat contractor to continue the cleanup operation. The contractor dispatched a vacuum truck\ncrew to the scene and continued to collect product along with water from the rain that began to fall\nshortly after they discovered the spill. At that point, the FCFRD believed the gasoline was likely\nfrom an illegal dumping operation, and the incident was contained. By 7:30 p.m., the cleanup\ncrews had collected more than 3,000 gallons of water-petroleum product mixture in the vacuum\ntruck. Crews also deployed absorbent booms and collected a similar mixture in a vacuum truck at\nthe storm water retention pond northwest of Sweetwater Tavern.\nBecause spill estimates continued to increase during that evening, investigators had to\nreconsider their conclusion that the source was illegal dumping; they again suspected there was an\nactive leak. The fire marshal’s office contacted the Colonial Control Center at 8:53 p.m. and\nrequested assistance. After discussing the situation with the right-of-way inspector, the Colonial\ncontroller started shutting down lines 3 and 4 as a precaution and dispatched inspectors to the site.\nColonial shut down the line 3 and 4 pumps and the main-line block valves at the Chantilly and\nRemington stations in Virginia by 9:17 p.m. (See figure 2.)\nColonial inspectors arrived about 10:00 p.m. About 2 1/2 hours later, Colonial’s lead\noperator contacted the company’s district environmental coordinator and the director of northeast\noperations to report he still did not know if the Colonial pipeline might be the source of the product\nin the storm water drain system.\nOver the next 3 hours, Colonial engineers analyzed computer operating data, but they were\nunable to determine whether either pipeline might be leaking. Colonial crews at the scene\nconducted bar hole testing in the pipeline right-of-way to try to identify a leak location; however,\nthe rocky soil made it difficult to insert the probes deep enough to obtain meaningful data. Colonial\ncrews also continued working with responders to determine where the product might be entering\nthe storm water system.\n3\n\n<<<PAGE 4>>>\n\nColonial Pipeline Company Petroleum Product Leak\nFigure 2. Valves for lines 3 and 4 (clouded areas) used to isolate leak on line 4 (identified by arrow).\nOn September 22, 2015, about 1:00 a.m., Colonial initiated a district-level response to\naddress a potential leak; they elevated it to a companywide response about 8 1/2 hours later.\nAbout 10:00 a.m., Colonial performed a static pressure analysis between two block valves of lines\n3 and 4 to determine whether a leak existed. The analysis suggested a possible leak in line 3 but\nnot in line 4.3\nJust before noon, Colonial employees and contract personnel arrived and began marking\ndig locations along the right-of-way to search for product and the leak location. Colonial then\nbegan excavating at possible leak locations around lines 3 and 4 on the south side of Route 28 and\nsouth of New Braddock Road, which the Colonial Integrity Management senior engineer\nidentified and prioritized using information about appurtenances, prior repairs, and recent inline\ninspections. The company selected and excavated six dig sites throughout the afternoon. About\n7:00 p.m., excavation began above a dent in line 4 that had been documented in an inline\ninspection. Product-contaminated soil was exposed near the centerline of the buried pipe. Further\nexcavation continued throughout the night until the entire pipe diameter was exposed. This allowed\naccess to the existing dent at the 6 o’clock position where, the following morning, the workers\ndiscovered a crack in the pipe and saw product dripping and accumulating in the trench.\n(See figure 3.)\n3 Valve leakage and changes in temperature can result in false indications when using this leak detection technique.\n4\n\n<<<PAGE 5>>>\n\nColonial Pipeline Company Petroleum Product Leak\nFigure 3. Leak discovered at the bottom of line 4 (arrow points to leak).\nColonial captured and removed the product and installed a sleeve around the pipe to stop\nthe leak. (See figure 4.) The company prepared a restart plan and submitted it to the Pipeline and\nHazardous Materials Safety Administration (PHMSA) for approval. Following satisfactory\ninstallation of a repair sleeve on September 25, 2015, PHMSA approved the temporary restart for\nline 4, which included a 20 percent reduction in operating pressure.\n5\n\n<<<PAGE 6>>>\n\nColonial Pipeline Company Petroleum Product Leak\nFigure 4. Two NTSB investigators examine red repair sleeve on line 4.\nThe line 4 leak occurred in a high consequence area.\n4 No fatalities or injuries resulted from\nthis accident. Colonial estimated that 4,000 gallons of product were released from the pipe.\nColonial estimated the cost of accident-related expenses at $16.5 million, including initial\nemergency response, environmental cleanup and remediation, pipe replacement, and inline\ninspection.\nColonial Pipeline Company\nColonial is an interstate pipeline company that delivers refined petroleum products\n(gasoline, kerosene, home heating oil, and jet fuel) to cities, airports, and military bases throughout\nthe southeastern, mid-Atlantic, and northeastern regions of the United States. The Colonial\npipeline system begins in Houston, Texas, and ends in Linden, New Jersey. It crosses 13 states,\n4 A high consequence area is defined in 49 Code of Federal Regulations [CFR] 195.450 as (1) a commercially\nnavigable waterway, which means a waterway where a substantial likelihood of commercial navigation exists;\n(2) a high population area, which means an urbanized area, as defined and delineated by the Census Bureau, that\ncontains 50,000 or more people and has a population density of at least 1,000 people per square mile; (3) an other\npopulated area, which means a place, as defined and delineated by the Census Bureau, that contains a concentrated\npopulation, such as an incorporated or unincorporated city, town, village, or other designated residential or commercial\narea; or (4) an unusually sensitive area as defined in §195.6.\n6\n\n<<<PAGE 7>>>\n\nColonial Pipeline Company Petroleum Product Leak\nspans more than 5,500 miles, and connects 29 refineries on the US Gulf Coast to 270 marketing\nterminals.\nThe Colonial pipeline system consists of four, large-diameter (30 inches or more) main\ntransmission pipelines and numerous small-diameter pipelines (stub lines) that serve local markets.\nAll four main lines (lines 1–4) and most stub lines are continuously monitored and controlled using\na Supervisory Control and Data Acquisition (SCADA) system in the Alpharetta, Georgia, control\ncenter. Some of the stub lines and delivery lines are controlled locally. The pipeline system is\ndivided into three operational districts: northeast, southeast, and Gulf Coast. Lines 1 and 2 run\nfrom Houston, Texas, to Greensboro, North Carolina. Line 3 runs from Greensboro to Linden; line\n4 runs from Greensboro to Dorsey, Maryland.\nLines 3 and 4 transport gasoline, kerosene, and fuel oil and are in the same right-of-way at\nthe leak location. The maximum operating pressure for line 3 ranges from 663 to 695 pounds per\nsquare inch, gauge; the maximum operating pressure for line 4 ranges from 657 to 682 pounds per\nsquare inch, gauge. 5\nThe pipe for line 4 has a 32-inch nominal pipe diameter with a 0.281-inch-thick wall and\ndouble submerged arc-welded longitudinal seam; the pipe is coated with asphalt enamel. It is\n288 miles long and began operating in 1964. The depth of cover on line 4 in the vicinity of the\nleak was between 5 1/2 and 6 1/2 feet. Corrosion protection for the pipeline in the area of the leak\nwas provided by an impressed current cathodic protection system.\nField Investigation\nColonial was not aware of a possible leak in either line 3 or line 4 until the fire department\nnotified the company on September 21, 2015, that firefighters were responding to an odor\ncomplaint in the vicinity of the pipeline right-of-way. Control room operators closely examined\nthe SCADA operating records for the two pipelines, but they were unable to identify evidence of\na possible leak. Additionally, Colonial inspectors did not see soil discoloration, distinct areas of\ndead vegetation, or a colorful sheen on water, nor did they detect an odor of petroleum products in\nthe pipeline right-of-way that would confirm a leak.\nBut after the fire department personnel discovered product in a storm water retention pond\nlocated hundreds of feet from the pipeline right-of-way, Colonial investigated further. On\nSeptember 21, 2015, about 9:00 p.m., the company shut down both pipelines as a precaution and\ndispatched field inspectors to Centreville to again search for the source of the odor. As a part of\nthe investigation, Colonial excavated down to the buried pipes at numerous locations along the\nright-of-way until—almost 2 days after the first odor report—they discovered the line 4 leak from\na crack at a previously documented dent.\n5 Colonial officials said the company does not set a single maximum operating pressure for the entire line because\npressures in their refined petroleum pipeline can fluctuate due to temperature, surges, transient conditions, flow rates,\nand the type of batch being delivered.\n7\n\n<<<PAGE 8>>>\n\nColonial Pipeline Company Petroleum Product Leak\nAs an added precaution, Colonial excavated around line 4 at a second previously\ndocumented dent location that was 70 feet upstream from the leak location. The pipe coating was\nintact, and magnetic particle inspection showed no evidence of cracks in the dent.\nA few weeks after the temporary sleeve was installed at the leak location, the two dented\npipe sections were removed. Colonial installed new pipe and returned the pipeline to service as\npermitted by the PHMSA Corrective Action Order (CPF No. 1-2015-5018H), which was issued\non September 29, 2015, and amended on October 22, 2015. Two 4-foot-long pipe segments\ncontaining dents were shipped to the NTSB materials laboratory for further evaluation. In the pipe\nsection containing the leak, a through-wall crack is visible on both the outside surface and the\ninside surface in the area of the dent. (See figures 5 and 6.)\nFigure 5. Magnetic particle inspection shows multiple longitudinal cracks on pipe outer wall (inside oval).\n8\n\n<<<PAGE 9>>>\n\nColonial Pipeline Company Petroleum Product Leak\nFigure 6. View of the dent and crack from inside the pipe.\n.\nInline Inspection\nColonial records show that line 4 was excavated and examined around the two dents, the\none that resulted in the 2015 leak and the other about 70 feet upstream, in 1994 and 2002\nrespectively. Magnetic particle inspection of the dents during the earlier excavations did not\nidentify any cracks. Because the dents did not exceed the limits that would have required repairs,\nColonial removed any large rocks that might have caused the dents, repaired the pipeline coating,\nand backfilled the excavations.\nInline inspections conducted by Colonial from 1998 to 2014 showed no evidence of\ncorrosion or cracking on line 4 along the Centreville right-of-way near the leak. The month\nfollowing the accident, Colonial conducted an inline inspection using an ultrasonic crack-detection\ntool before cutting out the dented and cracked segment. This inspection detected the crack in the\ndent.\nPipe Coating Examination\nCompromised coatings could expose the pipe to underground water, which could corrode\nthese unprotected areas of the pipeline due to shielding from the cathodic protection current even\nwhen the overall cathodic protection potentials are adequate.6 NTSB investigators observed\n6 The loss of the bond (adhesion) between a pipeline and its protective coating is commonly called disbondment.\nThis could allow moisture to penetrate the gap between the surface of the pipe and the coating, creating an environment\nthat may be corrosive. Under some circumstances, the pipeline’s cathodic protection current is prevented from\nreaching the exposed pipe surface under the disbonded coating (a phenomenon known as shielding); corrosion can\noccur on this unprotected pipe surface.\n9\n\n<<<PAGE 10>>>\n\nColonial Pipeline Company Petroleum Product Leak\ndisbonded coating in the dented area of the leak, but they could not determine if the extent of the\ncoating damage occurred before the leak or as a result of the leaking product.\nEnvironmental Impact\nColonial estimated that 4,000 gallons of hydrocarbon product were released in this\naccident.\n7 Cleanup crews used a vacuum truck to recover about 1,285 gallons of light non-aqueous\nphase liquid (LNAPL) product from the storm water outfall, and about 700 more gallons of\nLNAPL products were recovered in the week after the release.\n8 Cleanup crews excavated\ncontaminated soil containing an estimated 350 additional gallons of product.\nAn environmental contractor installed dual-phase extraction systems in the excavated areas\nalong the storm water drain system. An analysis of groundwater samples collected from various\nshallow monitoring points indicated that the extraction systems were reducing hydrocarbon\ncontamination along the storm drain system.\nColonial Pipeline Emergency Response\nThe Colonial Emergency Response Plan requires an investigation of all reports of a product\nodor. Accordingly, on September 21, 2015, about 2:00 p.m., two Colonial inspectors responded to\nthe report that the fire marshal’s office was investigating a gasoline odor near the pipeline\nright-of-way. The inspectors examined the right-of-way and found no soil discoloration, distinct\nareas of dead vegetation, colorful sheen on water, or odor of petroleum products. In addition, the\nColonial Control Center told the inspectors that the pressures in lines 3 and 4 were normal, so the\ninspectors concluded that lines 3 and 4 were not leaking. They did not use any flammable-gas\ndetection equipment during their inspections. The inspectors performed limited bar hole testing\nbecause the dry, hard soil and rock prevented them from effectively probing down to the buried\npipelines.\nOn September 21, 2015, Colonial received a second request for assistance at 8:53 p.m. after\nthe fire marshal investigator reported that refined petroleum product was found in a nearby storm\nwater retention pond. At 9:09 p.m., Colonial sent inspectors again, and this time Colonial shut\ndown lines 3 and 4 as a precaution. About 10:00 p.m., two Colonial inspectors, a lead operator,\nand a senior operator arrived at the incident scene to assist the FCFRD. Colonial inspectors\ncontinued to inspect the pipeline right-of-way and attempted additional bar hole testing. They did\nnot see or smell any product on their probe bars, but they continued to have difficultly probing\ndeep enough to get close to the buried pipelines because of the rocky soil. The technicians did not\nuse flammable vapor detectors to search for evidence of a hydrocarbon liquid leak in the bar holes;\nColonial procedures did not require it. However, the FCFRD battalion chief showed the Colonial\nlead operator the drum containing the hydrocarbon product that had been collected earlier in the\nday from recovery site 1. The lead operator then notified Colonial management that product had\nbeen discovered.\n7 The leaking pipeline transported several liquids. Although most of the product released was likely gasoline,\nother liquids transported through the pipeline might have escaped through the crack.\n8 LNAPL is a liquid petroleum product that contains almost no water.\n10\n\n<<<PAGE 11>>>\n\nColonial Pipeline Company Petroleum Product Leak\nColonial activated the Northeast District Response Team on September 22, 2015, about\n1:00 a.m. Colonial staff in the Alpharetta control center reviewed alignment sheets, inline\ninspection data, static pressure analysis, and SCADA data to determine possible leak locations. A\ndig plan and priorities were being developed as Colonial response resources were arriving at the\naccident site that morning. This included the hazardous liquids cleanup contractor that took over\ncleanup efforts at the weir wall—a barrier at the storm water outfall pond (recovery site 1).\nColonial employees told NTSB investigators that the company would not positively\nconfirm its pipeline was the source of a hydrocarbon product leak until they could see liquid\nescaping from one of the two transmission pipelines. On September 23, 2015, at 9:30 a.m.,\nColonial employees saw liquid dripping from line 4, nearly 24 hours after the companywide\nresponse team was activated and about 2 days after the initial odor report. Colonial then assumed\nresponsibility for the spill and began aggressive clean-up activities.\nLiquid Pipeline Small Leak Detection\nColonial informed the NTSB that four additional pipeline leaks had occurred in their\npipeline system that were undetectable on the SCADA system. One leak occurred about 5 months\nbefore the Centerville accident, and the other three occurred in less than 6 months after the\nCenterville accident. These leaks were discovered by the landowner, aerial patrol contractors, or\ninspectors. On April 2, 2016, TransCanada reported a similar liquid pipeline failure involving a\nsmall leak near Freeman, South Dakota, that went undetected on its SCADA system.\nDetecting small leaks in large hazardous liquid pipelines in a reliable, timely, and\ncost-effective manner has been a challenge for hazardous liquid pipeline operators and regulators.9\nThe PHMSA party representative on the Centreville accident investigation said:\nPHMSA is not aware of widely used industry technologies to detect small leaks\nsimilar to the one that occurred on Colonial’s line 4 in Centreville. However,\nPHMSA is taking a number of approaches through rulemaking, R&D [research and\ndevelopment], and taking part in standard development related to enhancing leak\ndetection on hazardous liquid and natural gas pipelines.\nHe further stated that he was not aware of any automated systems that are capable of detecting\nsmall leaks in large diameter, long-distance pipelines.\nTypically, SCADA systems use computer programs to calculate losses based on\nmismatches in liquid transfer quantities between process equipment. Considering all the process\nvariables, typically, the SCADA system is not capable of accurately detecting actual leak rates\nbelow about 2 percent of the flow volume in a liquid pipeline.\n9 Hazardous Liquid Leak Detection Techniques and Processes, Report No. DTRS56-02-D-70037-01,\nDr. Jim C. P. Liou, PE; Robert J. Hall, PE; Mona C. McMahon, PE; General Physics Corporation—Elkridge,\nMaryland, 21075; Prepared for US Department of Transportation, Washington, DC; April 2003.11\n\n<<<PAGE 12>>>\n\nColonial Pipeline Company Petroleum Product Leak\nColonial told the NTSB that the average flow volume in line 4 is about 15.6 million gallons\nper day, or about 10,800 gallons per minute. Considering a 2 percent detection limit, the smallest\nleak that the SCADA system could detect is about 216 gallons per minute. Assuming the recovered\nliquid volume is doubled to 8,000 gallons to account for unrecoverable product and a leak duration\nof 2 weeks based on when witnesses said they first smelled gasoline, the estimated leak rate would\nbe 571 gallons per day, or 0.4 gallons per minute. This estimated leak rate, based on our outlined\nassumptions, represents only 0.004 percent of the average flow, which is about 550 times lower\nthan the SCADA leak detection performance limit.\nTechnology and computer models are available to detect small hydrocarbon leaks. In 2015,\nthe Environmental Protection Agency published new standards for underground storage tanks to\nhelp prevent and detect leaks. The new regulation requires facilities (such as gas stations and\nairport fuel supply systems) to have leak detection systems capable of detecting small leaks.10\nPHMSA has conducted research on leak detection methods that can be practically applied\nto hazardous liquid transmission pipelines. In 2012, PHMSA completed a study of leak detection\nsystems that was required by the Pipeline Safety, Regulatory Certainty, and Job Creation Act of\n2011.\n11 The same year, PHMSA held a pipeline research forum to identify technological gaps and\nissues, including the advancement of leak detection methodologies. In April 2016, PHMSA\npublished a notice of proposed rulemaking on leak detection that considered these studies and\nother available research.\n12 Until the technology is improved so that these small-flow-rate leaks in\na long transmission pipeline can be detected in a cost-effective manner, the liquid pipeline industry\nwill continue to rely on visual observation as evidence of a leak. By the time a small leak is detected\nin a buried pipeline, days or months may have passed since the leak began, resulting in the\nlikelihood of significant environmental damage as occurred in the September 2013 crude oil\npipeline leak in Tioga, North Dakota.13\nAlternatively, leak detection devices could be installed along a pipeline at specific locations\nwhere inline inspection data confirm the pipe has been damaged, such as at a dent.14 The leak\ndetection device could provide an early warning that a through-wall crack or corrosion damage in\nthe pipeline has begun to leak. The operator could then take immediate corrective action to repair\nthe damaged pipe before a large, environmentally damaging spill results. Therefore, the NTSB\nrecommends that Colonial Pipeline Company revise the dent excavation evaluation procedure to\nrequire either (a) the repair of all excavated dent defects, or (b) the installation of a local leak\n10 Title 40 CFR 280.41, Requirements for Petroleum UST Systems.\n11 US Department of Transportation, Leak Detection Study – DTPH56-11-D -000001, Final Report no. 12-173 ,\nDecem ber 10, 2012.\n12 Safety of Gas Transmission and Gathering Pipelines Notice of Proposed Rulemaking (NPRM), Volume 81, No. 68,\nFederal Register, 20722, April 8, 2016.\n13 A farmer discovered oil in his 7.3-ac re wheat field. Investigators found that a 6-inch nominal pipe diameter crude oil\npipeline leak had released more than 20,000 barrels of oil. State health officials estimated the cleanup could take up to 4\nyears, http://fuelfix.com/blog/2015/05/25/cleanup-of-oil-spill-at-nd-farm-to-take-2-more -ye ars/ (accessed August 2016).\n14 US Department of Transportation, Leak Detection Study – DTPH56-11-D -000001, Final Report no. 12-173 ,\nDecem ber 10, 2012.\n12\n\n<<<PAGE 13>>>\n\nColonial Pipeline Company Petroleum Product Leak\ndetection system at each location where a dent is not repaired, continuous monitoring for\nhydrocarbons, and prompt corrective action to stop a detected leak.\nLaboratory Investigation\nPipe Material Testing\nTesting at a third-party laboratory revealed that the chemical composition and mechanical\nproperties were consistent with the original specifications (American Pipeline Institute 5L X52\nsteel) when the pipeline was installed.15\nCrack Examination\nThe outside surfaces of both dents, one that contained the leak and another that was located\n70 feet upstream from the leak location, were examined using the magnetic particle inspection.\nFor the pipe segment with the upstream dent that was removed as a precaution, no crack defects\nwere identified in the dent or around its perimeter. Magnetic particle inspection of the dent in the\ndownstream pipe segment that contained the leak revealed a network of short longitudinal crack\nindications within the dent parallel to the main crack. No crack indications were observed around\nthe perimeter of the dent.\nThe dent containing the crack was cut from the pipe segment for further evaluation.\nAfter removal, the main crack was opened to expose the fracture surfaces. Laboratory examination\nof the pipe fracture surfaces revealed the crack was 5.97 inches long at the outside diameter and\n4.52 inches long on the inside diameter. The pipe thickness adjacent to the crack was between\n0.266 and 0.270 inches; the nominal pipe wall thickness was 0.281 inches. The fracture faces\nexhibited features consistent with corrosion fatigue crack propagation, including ratchet marks,\ncrack arrest marks, and intergranular facets. These features are consistent with inward crack\npropagation from multiple crack initiation sites on the outside of the pipe.16 (See figure 7.)\n15 API Specification 5L, Specification for Line Pipe, 41st edition. American Petroleum Institute, Washington, DC,\n(1995).\n16 Corrosion fatigue is the process in which metal fractures prematurely under the conditions of simultaneous\ncorrosion and repeated cyclic loading at either lower stress levels or fewer cycles than would be required in the absence\nof the corrosive environment.\nRatchet marks are the lines or the markings on a fatigue fracture surface that result from the intersection and\nconnection of separate fatigue cracks propagating from multiple origins. Ratchet marks are parallel to the overall\ndirection of crack propagation and are visible to either the unaided eye or at low magnification.\nCrack arrest marks are macroscopic progression marks on a fatigue fracture or a stress-corrosion cracking\nsurface that indicate successive positions of the advancing crack front, typically appearing as either irregular elliptical\nor semielliptical rings, radiating outward from one or more origins. Crack arrest marks are also known as \"beach\nmarks.\" These marks are usually found on service fractures where the part is: (1) loaded randomly, (2) loaded\nintermittently, or (3) subjected to periodic variations in either the mean stress or the alternating stress.\nIntergranular facets are fracture features showing separated microscopic grains. These facets are also called\n\"rock-candy,\" and these features are indicative of intergranular fracture in a polycrystalline metals or alloys.\n13\n\n<<<PAGE 14>>>\n\nColonial Pipeline Company Petroleum Product Leak\nFigure 7. Close-up of the fracture. Arrows show crack arrest marks, ratchet mark, and initiation sites.\nCracks on the fracture surface were observed propagating from exterior surface corrosion\npits. Both the pits and the fracture surfaces contained corrosion products/deposits; and the\nelemental analysis of the material was consistent with an iron corrosion product. These cracks\nshowed no significant branching. (See figure 8.)\n14\n\n<<<PAGE 15>>>\n\nColonial Pipeline Company Petroleum Product Leak\nFigure 8. Photomicrograph of fracture shows straight crack originating from corrosion pit (circled).\nAn examination of the fracture surface with a scanning electron microscope revealed\nfatigue striations consistent with fatigue crack propagation. The fracture surfaces showed a mix of\nfracture features (faceted morphology and striations) that are consistent with corrosion fatigue\ncracks emanating from corrosion pits.\nDent Evaluation\nThe dent at the leak location was likely caused by a rock impinging on the underside of the\npipeline. A detailed study of the dent showed its depth to be about 1.6 percent of the outer pipe\ndiameter. The dent shape was documented by laser scanning and the shape data were incorporated\ninto a finite element model to determine the stresses in the dent region. Based on the finite element\nmodel, the peak stress values after the dent was created exceeded the measured yield strength for\nthe pipe, resulting in areas within the dent with high residual tensile stresses. These residual\nstresses made the pipeline more susceptible to externally initiated cracking, such as stress\ncorrosion and corrosion fatigue. In addition, the change in geometry in the dent area created stress\nconcentrations sufficient to enable fatigue cracking under cyclic loading conditions caused by\npressure variations in the pipeline.\n15\n\n<<<PAGE 16>>>\n\nColonial Pipeline Company Petroleum Product Leak\nPipeline Dent Acceptance Criteria\nAfter the accident, the inline inspection data from before and after the accident were\nreviewed and compared by a consultant hired by Colonial.\n17 The detailed study showed the depth\nof the dent at the leak location was about 1.6 percent of the outer pipe diameter and the upstream\ndent was 1.57 percent of the outer pipe diameter. Colonial did not repair either dent because they\ndid not meet PHMSA’s repair criteria. PHMSA pipeline regulations do not specifically require\ndents having depths less than 6 percent of the pipeline diameter to be repaired unless there is an\nindication of metal loss, cracking, or a stress riser, or unless the dent affects pipe curvature at a\ngirth weld or a longitudinal seam weld.18 The American Society of Mechanical Engineers (ASME)\nB31.4 piping design code is similar to the PHMSA requirements, including the threshold limits.\n19\nIn addition to the Centreville accident, Colonial reported to the NTSB that pipelines in\nPelham, Alabama; Felixville, Louisiana; and Simpsonville, South Carolina (Hunter Road) also\ndeveloped through-wall cracks in dented pipe. The depths of these dents were less than 2 percent\nof the pipe outer diameter and were located away from seam and girth welds. Colonial data indicate\nthat through-wall cracks can develop in dents shallower than the current acceptable criteria of 6\npercent of the pipe diameter. The Colonial pipeline failure data indicate that PHMSA’s criteria\nallowing dents with depths up to 6 percent of the pipe diameter to remain in the pipe is not a\nconservative approach from the safety view point.\nThe curvature of the dent may be more important than dent depth because of stress\nconcentrations, local plasticity, and local surface corrosion effects. Degraded or damaged coating\nat a dent may contribute to external pipe wall corrosion. Pipeline dents caused by a rock\nimpingement with the rock present (a constrained condition) can have a different stress magnitude\nand distribution than dents where the rock is later removed (unconstrained conditions), due to\nsystem constraint. Unconstrained dents have been shown to fail faster because of higher local hoop\nstresses.20 Furthermore, the coating material used and the quality of the installation after the\nremoval of an impinging rock can change the dent’s susceptibility to stress corrosion cracking.\n21\nAccording to the NTSB’s finite element study of the dent at the leak location, the highest\nstress values were not found at the point of maximum dent depth, but in areas within the dent and\nnear the dent edges having smaller radii of curvature due to the non-smooth nature of the dent. An\nexperimental fatigue study (also including stress analysis through finite element modeling) was\n17 L. Barkdull, M. Lewis. “Detailed Integrating ILI [Inline Inspection] Raw Data Review Corrective Action No. 6”\nQuest Integrity, L.L.C., Stafford, Texas. (January 20, 2016).\n18 Title 49 CFR 195.452, Pipeline Integrity Management in High Consequence Areas.\n19 ASME B31.4-2012. “Pipeline Transportation Systems for Liquid and Slurries.” American Society of\nMechanical Engineers, New York, New Y ork. (November 20, 2012).\n20 S. Tiku, V. Semiga, A. Dinovitzer, G. Vignal. “Full Scale Cyclic Fatigue Testing of Dented Pipelines and\nDevelopment of a Validated Dented Pipe Finite Element Model.” Proceedings of the 2012 9th International Pipeline\nConference. Calgary, Alberta, Canada. ASME (2012).\n21 J. Bratton, T. Alexander, T. Bubenik, S. Finneran, H.O. Heggen. “An Approach fo","truncated":true,"body_characters":50048}