{"operation":"document","citation":"CPF 220116001M","title":"NORFOLK SOUTHERN RAILWAY-BROSNAN YARD PIPELINE — Notice of Amendment","source_type":"enforcement","agency":"Pipeline and Hazardous Materials Safety Administration","status":"historical","official":true,"published_on":"2011-01-05","effective_on":null,"summary":"CLOSED notice of amendment citing 195.120(a), 195.402(c)(10), 195.402(c)(13), 195.402(c)(14), 195.402(c)(4), 195.406, 195.422, 195.428(a), 195.442(a), 195.52, 195.54, 195.55, 195.555, 195.557, 195.559, 195.56, 195.561, 195.563(a), 195.567, 195.569, 195.571, 195.573(a)(2), 195.575, 195.579(c), 195.581, 195.583, 195.585, 195.587, 195.589.","machine_formats":{"json":"https://regulus.evalyn.ai/document/phmsa-enforcement-220116001m.json","markdown":"https://regulus.evalyn.ai/document/phmsa-enforcement-220116001m.md"},"app_url":"https://regulus.evalyn.ai/document/phmsa-enforcement-220116001m","source_url":"https://primis.phmsa.dot.gov/enforcement-data/case/220116001M","body":"Notice of Amendment involving NORFOLK SOUTHERN RAILWAY-BROSNAN YARD PIPELINE. PHMSA's enforcement data identifies the cited regulations as 195.120(a),  195.402(c)(10),  195.402(c)(13),  195.402(c)(14),  195.402(c)(4),  195.406,  195.422,  195.428(a),  195.442(a),  195.52,  195.54,  195.55,  195.555,  195.557,  195.559,  195.56,  195.561,  195.563(a),  195.567,  195.569,  195.571,  195.573(a)(2),  195.575,  195.579(c),  195.581,  195.583,  195.585,  195.587,  195.589. The case was opened on 2011-01-05 and is reported as closed as of 2011-09-07. Open the official case record for notices, responses, orders, and the latest status.\n\nOfficial case documents:\n\n220116001M_closure letter_09072011.pdf: https://primis.phmsa.dot.gov/enforcement-documents/220116001M/220116001M_closure%20letter_09072011.pdf\n\n220116001M_closure letter_09072011_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/220116001M/220116001M_closure%20letter_09072011_text.pdf\n\n220116001M_notice of amendment_01052011.pdf: https://primis.phmsa.dot.gov/enforcement-documents/220116001M/220116001M_notice%20of%20amendment_01052011.pdf\n\n220116001M_notice of amendment_01052011_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/220116001M/220116001M_notice%20of%20amendment_01052011_text.pdf\n\n220116001M_Operator response and Request for Time Extension_01312011.pdf: https://primis.phmsa.dot.gov/enforcement-documents/220116001M/220116001M_Operator%20response%20and%20Request%20for%20Time%20Extension_01312011.pdf\n\n220116001M_Operator response_04072011.pdf: https://primis.phmsa.dot.gov/enforcement-documents/220116001M/220116001M_Operator%20response_04072011.pdf\n\n220116001M_notice of amendment_01052011_text.pdf\n\nNOTICE OF AMENDMENT\nCERTIFIED MAIL - RETURN RECEIPT REQUESTED\nJanuary 5, 2011\nMr. Tim Heilig\nVice President of Mechanical Operations\nNorfolk Southern Corporation\n1200 Peachtree Street NE (Box 184)\nAtlanta, GA 30309\nCPF 2-2011-6001M\nDear Mr. Heilig:\nOn December 13 and 14, 2010, a representative of the Pipeline and Hazardous Materials\nSafety Administration (PHMSA) inspected the Norfolk Southern Corporation (NSC)\nprocedural manual for operations, maintenance, and emergencies at your pipeline facility in\nMacon, Georgia, pursuant to Chapter 601 of 49 United States Code.\nOn the basis of the inspection, PHMSA has identified apparent inadequacies found within\nNSC’s procedures as described below:\n1. §195.52 Telephonic notice of certain accidents.\n(a) At the earliest practicable moment following discovery of a release of the\nhazardous liquid or carbon dioxide transported resulting in an event described in\n§195.50, the operator of the system shall give notice, in accordance with paragraph\n(b) of this section, of any failure that:\n(1) Caused a death or a personal injury requiring hospitalization;\n(2) Resulted in either a fire or explosion not intentionally set by the operator;\n(3) Caused estimated property damage, including cost of cleanup and recovery, value\nof lost product, and damage to the property of the operator or others, or both,\nexceeding $50,000;\n(4) Resulted in pollution of any stream, river, lake, reservoir, or other similar body\nof water that violated applicable water quality standards, caused a discoloration of\nthe surface of the water or adjoining shoreline, or deposited a sludge or emulsion\nbeneath the surface of the water or upon adjoining shorelines; or\n(5) In the judgment of the operator was significant even though it did not meet the\ncriteria of any other paragraph of this section.\n\n\n\n(b) Reports made under paragraph (a) of this section are made by telephone to 800-\n424-8802 (in Washington, DC 20590-0001 (202) 372-2428) and must include the\nfollowing information:\n(1) Name and address of the operator.\n(2) Name and telephone number of the reporter.\n(3) The location of the failure.\n(4) The time of the failure.\n(5) The fatalities and personal injuries, if any.\n(6) All other significant facts known by the operator that are relevant to the cause of\nthe failure or extent of the damages.\nWhile NSC's procedures required the telephonic reporting of certain events to the National\nResponse Center (NRC), the procedures were inadequate because they did not identify all\nthe events requiring a telephonic report to the NRC. NSC's procedures did not require the\nreporting of events that NSC determined to be significant that do not meet other criteria of\n§195.52; and/or, events resulting in the pollution of any stream, lake, reservoir, or other\nsimilar body of water that violated applicable water quality standards, caused a\ndiscoloration of the surface of the water or adjoining shoreline, or deposited a sludge or\nemulsion beneath the surface of the water or upon adjoining shorelines.\nMoreover, NSC's procedures were inadequate because they did not identify the\ninformation to be included in the telephonic reports to the NRC.\n2. §195.54 Accident reports.\n(a) Each operator that experiences an accident that is required to be reported under\n§195.50 shall as soon as practicable, but not later than 30 days after discovery of the\naccident, prepare and file an accident report on DOT Form 7000-1, or a facsimile.\n(b) Whenever an operator receives any changes in the information reported or\nadditions to the original report on DOT Form 7000-1, it shall file a supplemental\nreport within 30 days.\nWhile NSC's procedures required that an accident report be filed, the procedures were\ninadequate because they did not require that an accident report be submitted not later than\n30 days after discovery of an accident or that a supplemental report be filed when NSC\nreceives any changes in the information reported or any additional information not\nincluded in the original report.\n3. §195.55 Reporting safety-related conditions.\n(a) Except as provided in paragraph (b) of this section, each operator shall report in\naccordance with §195.56 the existence of any of the following safety-related\nconditions involving pipelines in service:\n(1) General corrosion that has reduced the wall thickness to less than that required\nfor the maximum operating pressure, and localized corrosion pitting to a degree\nwhere leakage might result.\n(2) Unintended movement or abnormal loading of a pipeline by environmental\ncauses, such as an earthquake, landslide, or flood, that impairs its serviceability.\n(3) Any material defect or physical damage that impairs the serviceability of a\npipeline.\n2\n\n\n\n(4) Any malfunction or operating error that causes the pressure of a pipeline to rise\nabove 110 percent of its maximum operating pressure.\n(5) A leak in a pipeline that constitutes an emergency.\n(6) Any safety-related condition that could lead to an imminent hazard and causes\n(either directly or indirectly by remedial action of the operator), for purposes other\nthan abandonment, a 20 percent or more reduction in operating pressure or\nshutdown of operation of a pipeline.\n(b) A report is not required for any safety-related condition that–\n(1) Exists on a pipeline that is more than 220 yards (200 meters) from any building\nintended for human occupancy or outdoor place of assembly, except that reports are\nrequired for conditions within the right-of-way of an active railroad, paved road,\nstreet, or highway, or that occur offshore or at onshore locations where a loss of\nhazardous liquid could reasonably be expected to pollute any stream, river, lake,\nreservoir, or other body of water;\n(2) Is an accident that is required to be reported under §195.50 or results in such an\naccident before the deadline for filing the safety-related condition report; or\n(3) Is corrected by repair or replacement in accordance with applicable safety\nstandards before the deadline for filing the safety-related condition report, except\nthat reports are required for all conditions under paragraph (a)(1) of this section\nother than localized corrosion pitting on an effectively coated and cathodically\nprotected pipeline.\nNSC's procedures were inadequate because they did not require NSC personnel to observe\nand report safety-related conditions (SRC) nor did they properly define what is an SRC\nand which SRCs are required to be reported.\nNSC's procedures require that \"Norfolk Southern's maintenance contractors have the\nresponsibility for identifying, reporting and correcting, as directed, any safety-related\nconditions as defined by Sec. 195.55, including wall corrosion, movement or abnormal\nloading, and physical damage.\" NSC's procedures, however, did not require that NSC\npersonnel identify and report SRCs nor did they specifically identify conditions which are\nSRCs and those which are required to be reported.\n4. §195.56 Filing safety-related condition reports.\n(a) Each report of a safety-related condition under §195.55(a) must be filed (received\nby the Administrator) in writing within 5 working days (not including Saturdays,\nSundays, or Federal holidays) after the day a representative of the operator first\ndetermines that the condition exists, but not later than 10 working days after the day\na representative of the operator discovers the condition. Separate conditions may be\ndescribed in a single report if they are closely related. To file a report by facsimile\n(fax), dial (202) 366-7128.\n(b) The report must be headed \"Safety-Related Condition Report\" and provide the\nfollowing information:\n(1) Name and principal address of operator.\n(2) Date of report.\n(3) Name, job title, and business telephone number of person submitting the report.\n(4) Name, job title, and business telephone number of person who determined that\nthe condition exists.\n3\n\n\n\n(5) Date condition was discovered and date condition was first determined to exist.\n(6) Location of condition, with reference to the State (and town, city, or county) or\noffshore site, and as appropriate nearest street address, offshore platform, survey\nstation number, milepost, landmark, or name of pipeline.\n(7) Description of the condition, including circumstances leading to its discovery, any\nsignificant effects of the condition on safety, and the name of the commodity\ntransported or stored.\n(8) The corrective action taken (including reduction of pressure or shutdown) before\nthe report is submitted and the planned follow-up or future corrective action,\nincluding the anticipated schedule for starting and concluding such action.\nWhile NSC's procedures required reporting SRCs, the procedures were inadequate\nbecause they did not address the time limits for reporting, the method to report SRCs, and\nthe information to be reported on SRCs.\n5. §195.120 Passage of internal inspection devices.\n(a) Except as provided in paragraphs (b) and (c) of this section, each new pipeline\nand each line section of a pipeline where the line pipe, valve, fitting or other line\ncomponent is replaced; must be designed and constructed to accommodate the\npassage of instrumented internal inspection devices\nNSC's procedures were inadequate because they did not contain any requirements that\nnewly constructed pipelines, and pipeline sections where line pipe, valves, fittings, or\nother line components are replaced, be designed and constructed to accommodate the\npassage of internal inspection devices.\n6. §195.402 Procedural manual for operations, maintenance, and emergencies.\n…. (c) Maintenance and normal operations. The manual required by paragraph (a)\nof this section must include procedures for the following to provide safety during\nmaintenance and normal operations:\n…. (4) Determining which pipeline facilities are located in areas that would require\nan immediate response by the operator to prevent hazards to the public if the\nfacilities failed or malfunctioned.\nWhile NSC's procedures called for NSC to identify pipeline facilities that require an\nimmediate response to prevent hazards to the public if the facilities failed or\nmalfunctioned, the procedures were inadequate because they did not identify how NSC\ndetermined these facilities. In addition, NSC's procedures identified where High\nConsequence Areas (HCAs) and environmentally sensitive areas were defined in its\nmanuals and procedures, but NSC's procedures did not explain that these are the areas on\nthe pipeline that would require an immediate response nor did the procedures identify\nother areas that would require an immediate response.\n7. §195.402 Procedural manual for operations, maintenance, and emergencies.\n…. (c) Maintenance and normal operations. The manual required by paragraph (a)\nof this section must include procedures for the following to provide safety during\nmaintenance and normal operations:\n…. (10) Abandoning pipeline facilities, including safe disconnection from an\noperating pipeline system, purging of combustibles, and sealing abandoned facilities\n4\n\n\n\nleft in place to minimize safety and environmental hazards. For each abandoned\noffshore pipeline facility or each abandoned onshore pipeline facility that crosses\nover, under or through commercially navigable waterways the last operator of that\nfacility must file a report upon abandonment of that facility in accordance with\n§195.59 of this part.\nWhile NSC procedures required that all proper procedures be followed when abandoning\na pipeline, the procedures were inadequate because they did not include procedures to\nfollow for purging, disconnecting, and sealing pipeline facilities to be abandoned.\nThat is, NSC's procedures state, \" … all proper procedures will be followed, including the\nsafe disconnection from an operating pipeline system, purging of combustibles, and\nsealing abandoned facilities left in place ….\" but NSC does not have procedures nor\nguidance for performing these actions.\n8. §195.402 Procedural manual for operations, maintenance, and emergencies.\n…. (c) Maintenance and normal operations. The manual required by paragraph (a)\nof this section must include procedures for the following to provide safety during\nmaintenance and normal operations:\n…. (13) Periodically reviewing the work done by operator personnel to determine the\neffectiveness of the procedures used in normal operation and maintenance and\ntaking corrective action where deficiencies are found.\nNSC's procedures were inadequate because they did not include procedures covering the\nperiodic review of work done by NSC or contractor personnel to determine the\neffectiveness of procedures used in maintenance and operations, and for taking corrective\naction when deficiencies are found.\n9. §195.402 Procedural manual for operations, maintenance, and emergencies.\n(c) Maintenance and normal operations. The manual required by paragraph (a) of\nthis section must include procedures for the following to provide safety during\nmaintenance and normal operations:\n(14) Taking adequate precautions in excavated trenches to protect personnel from\nthe hazards of unsafe accumulations of vapor or gas, and making available when\nneeded at the excavation, emergency rescue equipment, including a breathing\napparatus and, a rescue harness and line.\nNSC's procedures were inadequate because NSC's procedure for trench safety did not\naddress protecting personnel in excavated trenches from unsafe accumulations or vapor or\ngas, nor making available emergency rescue equipment.\nNSC's procedures for Trench Safety (195.402(c)(14) state \"… when performing\noperations which require excavation and trenching, NSR will require workers to take\nadequate precautions in excavated trenches as required by OSHA.\" While NSC's\nprocedures included a general statement to follow OSHA requirements for trench safety,\nthey did not specifically address the requirements for how personnel will be protected\nfrom the unsafe accumulation of vapor or gas, nor the provision of emergency rescue\nequipment as required by PHMSA pipeline safety regulations.\n5\n\n\n\n10. §195.406 Maximum operating pressure.\n(a) Except for surge pressures and other variations from normal operations, no\noperator may operate a pipeline at a pressure that exceeds any of the following:\n(1) The internal design pressure of the pipe determined in accordance with §195.106.\nHowever, for steel pipe in pipelines being converted under §195.5, if one or more\nfactors of the design formula (§195.106) are unknown, one of the following pressures\nis to be used as design pressure:\n(i) Eighty percent of the first test pressure that produces yield under section N5.0 of\nappendix N of ASME B31.8, reduced by the appropriate factors in §§195.106(a) and\n(e); or\n(ii) If the pipe is 12¾ in (324 mm) or less outside diameter and is not tested to yield\nunder this paragraph, 200 p.s.i. (1379 kPa) gage.\n(2) The design pressure of any other component of the pipeline.\n(3) Eighty percent of the test pressure for any part of the pipeline which has been\npressure tested under Subpart E of this part.\n(4) Eighty percent of the factory test pressure or of the prototype test pressure for\nany individually installed component which is excepted from testing under §195.305.\n(5) For pipelines under §§195.302 (b)(1) and (b)(2)(i) that have not been pressure\ntested under subpart E of this part, 80 percent of the test pressure or highest\noperating pressure to which the pipeline was subjected for 4 or more continuous\nhours that can be demonstrated by recording charts or logs made at the time the test\nor operations were conducted.\n(b) No operator may permit the pressure in a pipeline during surges or other\nvariations from normal operations to exceed 110 percent of the operating pressure\nlimit established under paragraph (a) of this section. Each operator must provide\nadequate controls and protective equipment to control the pressure within this limit.\nNSC's procedures were inadequate because NSC identified the normal operating pressure\nand maximum operating pressure (MOP) of its pipeline, but did not identify how the MOP\nwas determined. Moreover, the procedures did not cover how NSC would provide\nadequate controls to prevent the pressure from exceeding 110% of the MOP during surges\nand other variations from normal operations.\nNSC's procedure for Maximum Operating Pressure (195.406) stated \"The normal\noperating pressure for the Brosnan Yard pipeline is 265 psi and the maximum operating\npressure is 450 psi.\" The procedure, however, did not address how NSC determined the\nMOP nor did the procedure address how NSC will protect the pipeline from exceeding\n110% of the MOP during surges and other variations from normal operations.\n11. §195.422 Pipeline repairs.\n(a) Each operator shall, in repairing its pipeline systems, insure that the repairs are\nmade in a safe manner and are made so as to prevent damage to persons or\nproperty.\n(b) No operator may use any pipe, valve, or fitting, for replacement in repairing\npipeline facilities, unless it is designed and constructed as required by this part.\n6\n\n\n\nWhile NSC's procedures required that repairs to its pipeline system be made in a safe\nmanner and that any replacement parts, valves and fittings be designed and constructed\nappropriately, the procedures were inadequate because they did not address how repairs\nwould actually be made or how the regulatory requirements of Part 195, Subpart D for\nconstruction, inspection, welding, welder qualification, and nondestructive examination or\nSubpart E for pressure testing when making repairs would be met. That is, NSC's\nprocedures did not address repair methods, repair requirements, welding, nondestructive\nexamination, pressure testing, construction methods, and inspections associated with\nrepair activities.\n12. §195.428 Overpressure safety devices and overfill protection systems.\n(a) Except as provided in paragraph (b) of this section, each operator shall, at\nintervals not exceeding 15 months, but at least once each calendar year, or in the\ncase of pipelines used to carry highly volatile liquids, at intervals not to exceed 7½\nmonths, but at least twice each calendar year, inspect and test each pressure limiting\ndevice, relief valve, pressure regulator, or other item of pressure control equipment\nto determine that it is functioning properly, is in good mechanical condition, and is\nadequate from the standpoint of capacity and reliability of operation for the service\nin which it is used.\nNSC's procedures were inadequate because the procedures did not address the testing of\noverpressure safety devices. NSC relies on NuStar Terminals Operating Partnership\n(NuStar) for the overpressure pressure protection on its pipeline. That is, NuStar provides\nthe NSC pipeline with pressure switches. NSC's procedures, however, did not address the\nrequirement that the pressure switches used to protect NSC's pipeline be tested.\n13. §195.442 Damage prevention program.\n(a) Except as provided in paragraph (d) of this section, each operator of a buried\npipeline shall carry out, in accordance with this section, a written program to\nprevent damage to that pipeline from excavation activities. For the purpose of this\nsection, the term “excavation activities” includes excavation, blasting, boring,\ntunneling, backfilling, the removal of aboveground structures by either explosive or\nmechanical means, and other earth moving operations.\nNSC's procedures were inadequate because NSC has not developed a damage prevention\nprogram.\nNSC's procedure Damage Prevention Program (195.442) stated \"A damage prevention\nprogram will be developed and included in this plan upon its completion. The damage\nprevention plan will include a written program to prevent damage to that pipeline form\nexcavation activities. The term \"excavation activities\" includes excavation, blasting,\nboring, tunneling, backfilling, the removal of aboveground structures by either explosive\nor mechanical means, and other earthmoving operations.\" The referenced damage\nprevention to be developed and included in the plan had not been developed or included in\nthe plan.\n7\n\n\n\n14. §195.555 What are the qualifications for supervisors?\nYou must require and verify that supervisors maintain a thorough knowledge of that\nportion of the corrosion control procedures established under §195.402(c)(3) for\nwhich they are responsible for insuring compliance.\nNSC's procedures were inadequate because NSC did not address having supervisors\nmaintain a thorough knowledge of the corrosion control procedures for which they are\nresponsible for insuring compliance.\n15. §195.557 Which pipelines must have coating for external corrosion control?\nExcept bottoms of aboveground breakout tanks, each buried or submerged pipeline\nmust have an external coating for external corrosion control if the pipeline is –\n(a) Constructed, relocated, replaced, or otherwise changed after the applicable date\nin §195.401(c), not including the movement of pipe covered by §195.424; or\n(b) Converted under §195.5 and –\n(1) Has an external coating that substantially meets §195.559 before the pipeline is\nplaced in service; or\n(2) Is a segment that is relocated, replaced, or substantially altered.\nNSC's procedures were inadequate because NSC did not have procedures addressing the\nrequirement to coat pipelines for the external corrosion control.\n16. §195.559 What coating material may I use for external corrosion control?\nCoating material for external corrosion control under §195.557 must –\n(a) Be designed to mitigate corrosion of the buried or submerged pipeline;\n(b) Have sufficient adhesion to the metal surface to prevent under film migration of\nmoisture;\n(c) Be sufficiently ductile to resist cracking;\n(d) Have enough strength to resist damage due to handling and soil stress;\n(e) Support any supplemental cathodic protection; and\n(f) If the coating is an insulating type, have low moisture absorption and provide\nhigh electrical resistance.\nNSC's procedures were inadequate because NSC did not have procedures addressing the\nrequirements for pipeline coating materials.\n17. §195.561 When must I inspect pipe coating used for external corrosion control?\n(a) You must inspect all external pipe coating required by §195.557 just prior to\nlowering the pipe into the ditch or submerging the pipe.\n(b) You must repair any coating damage discovered.\nNSC's procedures were inadequate because NSC did not have procedures addressing the\nrequirements to inspect external pipeline coatings before lowering a pipe in a ditch and to\nrepair any coating damage found.\n18. §195.563 Which pipelines must have cathodic protection?\n(a) Each buried or submerged pipeline that is constructed, relocated, replaced, or\notherwise changed after the applicable date in §195.401(c) must have cathodic\nprotection. The cathodic protection must be in operation not later than 1 year after\n8\n\n\n\nthe pipeline is constructed, relocated, replaced, or otherwise changed, as applicable.\nNSC's procedures were inadequate because they did not address the requirements to have\na cathodic protection system to protect the pipeline.\n19. §195.567 Which pipelines must have test leads and what must I do to install and\nmaintain the leads?\n(a) General. Except for offshore pipelines, each buried or submerged pipeline or\nsegment of pipeline under cathodic protection required by this subpart must have\nelectrical test leads for external corrosion control. However, this requirement does\nnot apply until December 27, 2004 to pipelines or pipeline segments on which test\nleads were not required by regulations in effect before January 28, 2002.\n(b) Installation. You must install test leads as follows:\n(1) Locate the leads at intervals frequent enough to obtain electrical measurements\nindicating the adequacy of cathodic protection.\n(2) Provide enough looping or slack so backfilling will not unduly stress or break the\nlead and the lead will otherwise remain mechanically secure and electrically\nconductive.\n(3) Prevent lead attachments from causing stress concentrations on pipe.\n(4) For leads installed in conduits, suitably insulate the lead from the conduit.\n(5) At the connection to the pipeline, coat each bared test lead wire and bared\nmetallic area with an electrical insulating material compatible with the pipe coating\nand the insulation on the wire.\n(c) Maintenance. You must maintain the test lead wires in a condition that enables\nyou to obtain electrical measurements to determine whether cathodic protection\ncomplies with §195.571.\nNSC's procedures were inadequate because NSC procedures did not address the\ninstallation and maintenance of test leads.\n20. §195.569 Do I have to examine exposed portions of buried pipelines?\nWhenever you have knowledge that any portion of a buried pipeline is exposed, you\nmust examine the exposed portion for evidence of external corrosion if the pipe is\nbare, or if the coating is deteriorated. If you find external corrosion requiring\ncorrective action under §195.585, you must investigate circumferentially and\nlongitudinally beyond the exposed portion (by visual examination, indirect method,\nor both) to determine whether additional corrosion requiring remedial action exists\nin the vicinity of the exposed portion.\nWhile NSC's procedures required that exposed pipe be examined for corrosion, the\nprocedures were inadequate because they did not require that the pipeline be examined\ncircumferentially and longitudinally beyond the exposed portion whenever external\ncorrosion is found requiring corrective action under §195.585.\n21. §195.571 What criteria must I use to determine the adequacy of cathodic protection?\nCathodic protection required by this Subpart must comply with one or more of the\napplicable criteria and other considerations for cathodic protection contained in\nparagraphs 6.2 and 6.3 of NACE SP 0169 (incorporated by reference, see § 195.3).\n9\n\n\n\nNSC's procedures were inadequate because NSC procedures did not address the criteria\nused to determine that cathodic protection on the pipeline is adequate.\n22. §195.573 What must I do to monitor external corrosion control?\n(a) Protected pipelines. You must do the following to determine whether cathodic\nprotection required by this subpart complies with §195.571:\n…. (2) Identify not more than 2 years after cathodic protection is installed, the\ncircumstances in which a close-interval survey or comparable technology is\npracticable and necessary to accomplish the objectives of paragraph 10.1.1.3 of\nNACE SP 0169 (incorporated by reference, see § 195.3).\nNSC's procedures were inadequate because they did not address the circumstances when\nNSC would determine that a close-interval survey or comparable technology is practicable\nand necessary to accomplish the objectives of paragraph 10.1.1.3 of NACE SP 0169\n(incorporated by reference, see § 195.3).\n23. §195.575 Which facilities must I electrically isolate and what inspections, tests, and\nsafeguards are required?\n(a) You must electrically isolate each buried or submerged pipeline from other\nmetallic structures, unless you electrically interconnect and cathodically protect the\npipeline and the other structures as a single unit.\n(b) You must install one or more insulating devices where electrical isolation of a\nportion of a pipeline is necessary to facilitate the application of corrosion control.\n(c) You must inspect and electrically test each electrical isolation to assure the\nisolation is adequate.\n(d) If you install an insulating device in an area where a combustible atmosphere is\nreasonable to foresee, you must take precautions to prevent arcing.\n(e) If a pipeline is in close proximity to electrical transmission tower footings, ground\ncables, or counterpoise, or in other areas where it is reasonable to foresee fault\ncurrents or an unusual risk of lightning, you must protect the pipeline against\ndamage from fault currents or lightning and take protective measures at insulating\ndevices.\nNSC's procedures were inadequate because they did not address electrically isolating the\npipeline and what inspections and tests, and safeguards are required.\n24. §195.579 What must I do to mitigate internal corrosion?\n…. (c) Removing pipe. Whenever you remove pipe from a pipeline, you must inspect\nthe internal surface of the pipe for evidence of corrosion. If you find internal\ncorrosion requiring corrective action under §195.585, you must investigate\ncircumferentially and longitudinally beyond the removed pipe (by visual\nexamination, indirect method, or both) to determine whether additional corrosion\nrequiring remedial action exists in the vicinity of the removed pipe.\nNSC's procedures were inadequate because NSC procedures did not require investigating\nbeyond the removed pipe for internal corrosion when localized corrosion pitting is found.\n10\n\n\n\nNSC's procedure Internal Corrosion (195.418) requires that adjacent pipe be investigated\nfor internal corrosion whenever the internal surface of removed \"\n…pipe is generally\ncorroded such that the remaining wall thickness is less than the minimum required ….\"\nThe procedure, however, did not address investigating adjacent pipe for internal corrosion\nwhenever localized corrosion pitting is found that could result in leakage.\n25. §195.581 Which pipelines must I protect against atmospheric corrosion and what\ncoating material may I use?\n(a) You must clean and coat each pipeline or portion of pipeline that is exposed to the\natmosphere, except pipelines under paragraph (c) of this section.\n(b) Coating material must be suitable for the prevention of atmospheric corrosion.\n(c) Except portions of pipelines in offshore splash zones or soil-to-air interfaces, you\nneed not protect against atmospheric corrosion any pipeline for which you\ndemonstrate by test, investigation, or experience appropriate to the environment of\nthe pipeline that corrosion will –\n(1) Only be a light surface oxide; or\n(2) Not affect the safe operation of the pipeline before the next scheduled inspection.\nNSC's procedures were inadequate because they did not include an atmospheric corrosion\ncontrol program identifying which pipelines must be protected against atmospheric\ncorrosion and what coating materials must be used.\n26. §195.583 What must I do to monitor atmospheric corrosion control?\n(a) You must inspect each pipeline or portion of pipeline that is exposed to the\natmosphere for evidence of atmospheric corrosion, as follows:\nIf the pipeline is\nlocated: Then the frequency of inspection is:\nOnshore At least once every 3 calendar years, but with intervals\nnot exceeding 39 months.\nOffshore At least once each calendar year, but with intervals not\nexceeding 15 months.\n(b) During inspections you must give particular attention to pipe at soil-to-air\ninterfaces, under thermal insulation, under disbonded coatings, at pipe supports, in\nsplash zones, at deck penetrations, and in spans over water.\n(c) If you find atmospheric corrosion during an inspection, you must provide\nprotection against the corrosion as required by §195.581.\nNSC's procedures were inadequate because they did not include an atmospheric corrosion\ncontrol program identifying inspections for atmospheric corrosion, their frequency, and\nactions to be taken if atmospheric corrosion is found.\n27. §195.585 What must I do to correct corroded pipe?\n(a) General corrosion. If you find pipe so generally corroded that the remaining wall\nthickness is less than that required for the maximum operating pressure of the\npipeline, you must replace the pipe. However, you need not replace the pipe if you –\n(1) Reduce the maximum operating pressure commensurate with the strength of the\n11\n\n\n\npipe needed for serviceability based on actual remaining wall thickness; or\n(2) Repair the pipe by a method that reliable engineering tests and analyses show can\npermanently restore the serviceability of the pipe.\n(b) Localized corrosion pitting. If you find pipe that has localized corrosion pitting to\na degree that leakage might result, you must replace or repair the pipe, unless you\nreduce the maximum operating pressure commensurate with the strength of the pipe\nbased on actual remaining wall thickness in the pits.\nNSC's procedures were inadequate because NSC procedures did not address actions to\ntake if corroded pipe is found.\n28. §195.587 What methods are available to determine the strength of corroded pipe?\nUnder §195.585, you may use the procedure in ASME B31G, “Manual for\nDetermining the Remaining Strength of Corroded Pipelines,” or the procedure\ndeveloped by AGA/Battelle, “A Modified Criterion for Evaluating the Remaining\nStrength of Corroded Pipe (with RSTRENG disk),” to determine the strength of\ncorroded pipe based on actual remaining wall thickness. These procedures apply to\ncorroded regions that do not penetrate the pipe wall, subject to the limitations set out\nin the respective procedures.\nNSC's procedures were inadequate because they did not include methods used to\ndetermine the strength of corroded pipe.\n29. §195.589 What corrosion control information do I have to maintain?\n(a) You must maintain current records or maps to show the location of –\n(1) Cathodically protected pipelines;\n(2) Cathodic protection facilities, including galvanic anodes, installed after January\n29, 2002; and\n(3) Neighboring structures bonded to cathodic protection systems.\n(b) Records or maps showing a stated number of anodes, installed in a stated manner\nor spacing, need not show specific distances to each buried anode.\n(c) You must maintain a record of each analysis, check, demonstration, examination,\ninspection, investigation, review, survey, and test required by this subpart in\nsufficient detail to demonstrate the adequacy of corrosion control measures or that\ncorrosion requiring control measures does not exist. You must retain these records\nfor at least 5 years, except that records related to §§195.569, 195.573(a) and (b), and\n195.579(b)(3) and (c) must be retained for as long as the pipeline remains in service.\nNSC's procedures were inadequate because they did not identify the corrosion control\nrecords to be maintained.\nResponse to this Notice\nThis Notice is provided pursuant to 49 U.S.C. § 60108(a) and 49 C.F.R. § 190.237.\nEnclosed as part of this Notice is a document entitled Response Options for Pipeline\nOperators in Compliance Proceedings. Please refer to this document and note the\nresponse options. Be advised that all material you submit in response to this enforcement\naction is subject to being made publicly available. If you believe that any portion of your\nresponsive material qualifies for confidential treatment under 5 U.S.C. 552(b), along with\n12\n\n\n\nthe complete original document you must provide a second copy of the document with the\nportions you believe qualify for confidential treatment redacted and an explanation of why\nyou believe the redacted information qualifies for confidential treatment under 5 U.S.C.\n552(b). If you do not respond within 30 days of receipt of this Notice, this constitutes a\nwaiver of your right to contest the allegations in this Notice and authorizes the Associate\nAdministrator for Pipeline Safety to find facts as alleged in this Notice without further\nnotice to you and to issue a Final Order.\nIf, after opportunity for a hearing, your plans or procedures are found inadequate as alleged\nin this Notice, you may be ordered to amend your plans or procedures to correct the\ninadequacies (49 C.F.R. § 190.237). If you are not contesting this Notice, we propose that\nyou submit your amended procedures to my office within 60 days of receipt of this Notice.\nThis period may be extended by written request for good cause. Once the inadequacies\nidentified herein have been addressed in your amended procedures, this enforcement action\nwill be closed.\nIn correspondence concerning this matter, please refer to CPF 2-2011-6001M and, for\neach document you submit, please provide a copy in electronic format whenever possible.\nSincerely,\nWayne T. Lemoi\nDirector, PHMSA Southern Region\nOffice of Pipeline Safety\nEnclosure: Response Options for Pipeline Operators in Compliance Proceedings\n13\n\n220116001M_closure letter_09072011_text.pdf\n\nCERTIFIED MAIL - RETURN RECEIPT REQUESTED\nSeptember 7, 2011\nMr. Tim Heilig\nVice President of Mechanical Operations\nNorfolk Southern Corporation\n1200 Peachtree Street NE (Box 184)\nAtlanta, GA 30309\nCPF 2-2011-6001M\nDear Mr. Heilig:\nOn December 13 and 14, 2010, a representative of the Pipeline and Hazardous Materials\nSafety Administration (PHMSA) inspected the Norfolk Southern Corporation (NSC)\nprocedural manual for operations, maintenance, and emergencies at your pipeline facility in\nMacon, Georgia, pursuant to Chapter 601 of 49 United States Code. As a result of the\ninspection, PHMSA issued a Notice of Amendment (NOA) on January 5, 2011.\nIn late August 2011, PHMSA received letters from both NSC and Buckeye Development &\nLogistics, LLC (Buckeye) confirming that as of July 1, 2011, Buckeye is the operator of the\nMacon pipeline and that Buckeye employees now operate the pipeline and perform all\noperations and maintenance (O&M) tasks on the pipeline using Buckeye’s O&M manual.\nThe NOA referenced above required NSC to amend certain written procedures in its written\nO&M manual. Since NSC is no longer the operator of the pipeline and because the pipeline is\nnow being operated using Buckeye’s O&M manual, such amendments are now moot.\nTherefore, no further action is necessary with regards to the NOA and this case is now closed.\nPlease be advised that this letter refers only to the NOA (CPF 2-2011-6001M) and not to any\nother PHMSA pending cases. Also be advised that nothing herein states or implies that the\nabove described Buckeye O&M manual meets the requirements of the federal pipeline safety\nregulations or that the Buckeye O&M manual is approved. The pipeline system and\nBuckeye’s written O&M manual remain subject to inspection by PHMSA.\nSincerely,\nWayne T. Lemoi\nDirector, Office of Pipeline Safety\nPHMSA Southern Region","truncated":false,"body_characters":39698}