1996 Colonial Pipeline Task Force January 10, 1997 C U.S. Department of Transportation Research and Special Programs Administration Office of Pipeline Safety

Department of Transportation Research and Special Programs Administration Office of Pipeline Safety 1996 Colonial Pipeline Task Force Final Report January 10, 1997Richard Felder, Associate Administrator for Pipeline SafetyFrederick Joyner, Co-ChairmanWilliam Gute, Co-ChairmanJames Thomas, PE, Co-ChairmanRodrick Seeley, Task Force LeaderByron Coy, PE, Task Forcq MemberRichard Lopez, PE, Task Force Member /7 J~_~ -u'~26, IJrW~1 `~ &L 1ir~.. 7hom&~.~ ~

O January 10, 1997 OPS Task Force Report Colonial Pipeline Company Table of Contents Executive Summary.................................................1.0 Introduction........................................................12.0 Colonial Pipeline Company 2.1 Introduction.................................................2 2.2 A Brief History..............................................2 2.3 Organizational Structure.....................................43.0 Compliance Report 3.1 Introduction.................................................5 3.2 Standard Inspection Compliance Actions.......................5 3.3 Accident Compliance Actions..................................6 3.3.1 Colonial's Accident History..................................7 3.3.2 1990 Task Force Investigation................................10 3.3.3 Open Compliance Actions......................................11 3.3.3.1 Consent Order: CPF 14501-H..................................11 3.3.3.2 Hazardous Facility Order: CPF 26503-H.......................12 3.3.3.3 Proposed Compliance Order: CPF 26506........................144.0 Operations Report 4.1 Introduction.................................................15 4.2 Organization.................................................15 4.3 Control Systems Overview 4.3.1 Separation of Control........................................16 4.3.2 Design Parameters............................................17 4.3.3 Pipeline Controllers.........................................18 4.4 Recording of Line Pressure 4.4.1 Pressure DataArchiving.......................................18 4.4.2 South Baltimore, MD..........................................19 4.4.3 Roanoke, VA..................................................19 4.5 Operations Analysis 4.5.1 Controller Reports...........................................20 4.5.2 Unscheduled Shutdowns........................................21 4.5.3 Volume Balance...............................................23 4.6 Pressure Safety Systems and Pressure Alarms 4.6.1 Pressure Control and Monitoring Equipment....................23 4.6.2 MitchÈll-Roanoke Pressure Control............................25 4.6.3 SCADA Alarms.................................................26 4.7 Tank Level Alarms............................................27 4.8 SCADA and Operations Support Systems 4.8.1 SCADA System.................................................27 4.8.2 Controller Display Screens....................................29 4.9 Revision and Change Control for Line Pressure 4.9.1 Maximum Operating Pressure...................................30 4.9.2 Set Point Change Process.....................................30 4.10 Reedy River Accident near Simpsonville, SC...................32 4.11 Murfreesboro, TN Accident....................................32

O January 10, 1997 OPS Task Force Report Colonial Pipeline Company5.0 Maintenance Report 5.1 Introduction 5.2 Organization........... 5.2.1 Staffing............... 5.2.2 Expenditures........... 5.3 Maintenance Program 5.3.1 Corrosion Control...... 5.3.1.1 Cathodic Protection 5.3.1.2 Internal............. 5.3.1.3 Atmospheric.......... 5.3.2 Pipeline............... 5.3.3 Valves and Operators... 5.3.4 Breakout Tanks......... 5.4 Valve Spacing.......... 5.5 Maps and Records....... 5.6 Priorities............. 5.7 Emergency Response............ 5.8 In Line Inspection Program 5.8.1 Introduction..................................... 5.8.2 Hydrostatic Testing and In Line Inspection....... 5.8.3 Initiation of Colonial's ILl Program............. 5.8.4 Application of ILl Technology.................... 5.8.5 Rehabilitation Analysis and Timeliness of Repairs 5.8.6 Longitudinal Seam Crack ILl...................... 5.8.7 ILl Program Management...........................6.0 Training Report 6.1 Introduction................... 6.2 Organization................. 6.3 Employee Training Program6.3.1 Operations..................... 6.3.2 Controllers.................... 6.3.3 Pipeline MaintenancelTechnic,ans6.3.4 Continuing Training Programs 6.3.4.1 Field Employees............... 6.3.4.2 Controllers................... 6.3.4.3 Pipeline Maintenance/Technicians6.4 Advancement/Career Development 6.5 Program Enhancements 6.5.1 Coordination Teams........... 6.5.2 Recent Proposals............. 7.0 Recommendations and Findings 7.1 Recommendations.............. 7.2 Findings....................... 7.2.1 General........................ 7.2.2 Operations..................... 7.2.3 Maintenance.................... 7.2.4 Training........43........43........44........45........47........50........51.......................53.......................53.......................54.......................55.......................56.......................57.......................57.......................57.......................58 58 .....60 .....61 .....61 .....61 .....63 6434343435353737393939394041424242

O January 10, 1997 OPS Task Force Report Colonial Pipeline CompanyList of Tables 4.1 Pipeline Operations Personnel..........................................16 4.2 Unscheduled Shutdown with Possible Over-Pressure.......................22 4.3 Pressure Control and Monitoring Equipment..............................25 4.4 MitcheIl-Lynchburg-Roanoke Pressure Settings...........................25 4.5 Tank Alarm Operations..................................................27 4.6 Review of Pressure Set-Point Changes Prior Reedy River Accident........32 5.1 Staffing...............................................................35 5.2 Pipeline Maintenance unaudited Expenditures..........................35 5.3 SIPM Budget Allocation.................................................42 5.4 Piggable Hazardous Liquid Pipelines in US..............................44 5.5 Hydrostatic Testing and ILl as of Nov. 1996............................45 5.6 Selected Colonial ILl Run Reviews......................................48 5.7 Lines I and 2 Anomaly Comparison.......................................49 5.8 Colonial's Targeted TSI Analysis.......................................50 5.9 Summary of Excavation Results..........................................51List of Figures 4.1 Typical Pump Station...................................................17 4.2 South Baltimore, MD, Line 31, Meter Pressure...........................19 4.3 Roanoke, VA, Line 25- Instrument Chart.................................20 4.4 Roanoke, VA, Line 25- Instrument Chart. - Retouched....................20 4.5 Standard Valve Design..................................................32 4.6 Murfreesboro Valve Configuration.......................................33Appendix A Table A-I Colonial OrganizationAppendix B Table B-i HLP uMajor ~Spills Table 8-2 Colonial Standard Inspection Compliance Actions Table B-3 Colonial Accident Compliance Actions Table B-4 Colonial Reportable Accidents: 1968-1996 Table B-5 LargeSt HLP Reported Spills Table B-6 HLP Accident Rate Comparison: 1987-i 996 Table B-7 HLP Accident Cause Comparison: 1968-i 996Appendix C Table C-i Colonial Unscheduled Shutdown Summary Table C-2 Colonial Protective Devices and other Information - Simpsonville, SC Table C-3 Colonial Relief Valve Settings Figure C-4 Controller's Strip Chart Display Typical Figure C-5 Controller's Real Time Nomograph RTN Screen TypicalAppendix D 0-1 Colonial's Maintenance Procedures: Table of Contents D-2 Colonial's DOT Reference Guide Index Table 0-3 Caliper Deformation Projects Table D-4 MFL ILl Projects Table D-5 Selected Pig Run Details

January 10. 1997 OPS Task Force Report Colonsal Pipeline Company Appendix E Table E-1 Colonial Training Summary: 1990-1996 E-2 Operator Training Program E-3 Associate Controller Training Program Appendix F Table F-I Colonial Leaks 1,000 bbl. or more: 1968-1996 F-2 Colonial Pipeline Leak Map Appendix G Current OPS ProgramsProposed Rule makings Study of Pipeline Infrastructure: NJIT Applied Research to PipelinesLeakBefore Rupture: Texas Transportation Institute Dent Crack Acceptability: Texas Transportation Institute In-Line Inspection Technology: Battelle Appendix H H-i Glossary of Terms H-2 Reference Material

O January 10, 1997 OPS Task For~ Report Colonial Pipeline Company EXECUTIVE SUMMARYColonial Pipeline Company is the largest refined petroleum products pipeline company in theUnited States. The pipeline system consists of approximately 5,317 miles of pipeline whichdelivers refined products from Pasadena, TX to the New York Harbor area. On June 26, 1996,Colonial experienced an accident on their 36-inch diameter mainline near Simpsonville, SC.That accident resulted in 22,800 barrels of fuel oil being spilled into the Reedy River. Followingthat accident, the Administrator of the Research and Special Programs Administration directedthe Associate Administrator for Pipeline Safety to form an Office of Pipeline Safety OPS Multi-Regional Task Force to examine Colonial's operations, maintenance and training programs toidentify any trends or deficiencies to help prevent future accidents.The Task Force conducted a comprehensive examination of Colonial over a three monthperiod, including a review of Co'onial's compliance and accident history. The investigationindicates that Colonial has one of the highest accident rates in the hazardous liquid pipelineindustry, having reported 194 accidents to the OPS since 1968. The June 26 ~ accident is thelargest spill experienced by Colonial in their 33 year history and was among the largesthazardous liquid pipeline spills ever reported to the OPS.Over the years, OPS has devoted considerable resources to inspecting and overseeingColonial using a traditional regulatory compliance approach. Following inspections of Colonialfacilities, and in response to accidents on its pipeline, OPS took specific compliance actionsagainst Colonial resulting in pressure restrictions, studies, inspections, tests and other actions.More recently, OPS has developed broader regional or systemwide strategies for preventingaccidents, and has progressively required pressure restrictions, hydrostatic testing and the useof the latest in-line inspection technology to assure the integrity of Colonial's pipeline system.In response to OPS compliance re~quirements, Colonial has become an industry leader in thedevelopment and use of sophisticated in-line inspection technology on their pipeline systeth.Given the number of Colonial accidents, including a high profile spill in Reston, VA, caused byexcavation damage by third parties, OPS and Colonial have been proactive in the prevention ofexcavation damage to pipelines. Colonial has been a strong supporter and participant in onecall systems.OPS has embarked on a multi-year effort to change its compliance program from scheduledstandard inspections and accident investigations to using more focused inspections andinvestigations targeting areas perceived to pose the greatest risk to pipeline safety and theenvironment. Following the spill near Simpsonville~ SC, OPS required Colonial to go wellbeyond simply repairing its line. OPS ordered Colonial to address all corrosion spots in thearea, of the spill, evaluate pressure control switches and the pressure flow model, and, mostimportantly, to conduct an internal inspection of vulnerable segments throughout its systemusing a new tool that is capable of detecting certain types of cracks that i~ave caused accidentsin the past. OPS intends to continue to improve the oversight of Colonial and other pipeline

O January 10, 1997 OPS Task Force Report Colonial Pipeline Companyoperators using comprehensive risk based approaches and increase the use of multi-regionalinspection teams.The Task Force believes that safe operation of Colonial pipeline must be pursued on acomprehensive basis by Colonial and OPS. Piecemeal actions addressing code violations andparticular accidents will not always lead to sufficient protection for high risk or environmentallysensitive areas. Based on the large number of accidents experienced by Colonial, the TaskForce recommends that Colonial perform an Operational Reliability Assessment on the entirepipeline system to assure pipeline system integrity. An Operational Reliability Assessment hasbeen performed by Colonial on portions of the 32-inch mainline, Line 4, in Iirginia.Colonial needs to develop a comprehensive management approach to the operations andmaintenance of their pipeline system. Following the reorganization in 1994, field staff has beenmaintained at historic levels but headquarters staff, especially in engineering, has beenreduced. Colonial must ensure that its new structure is capable of generating and processingthe information Colonial requires to operate its pipeline safely. Colonial needs to improvecommunications between the field locations and headquarters and to develop ways to assurethat good ideas and lessons learned are shared throughout the company. Colonial shouldupdate Operations and Maintenance manuals and procedures to eliminate conflicts and takesteps to see that manuals are followed uniformly throughout the company. The trainingprogram should incorporate feedback to determine the effectiveness of the training.Colonial has the technology it needs to monitor its pipeline. Colonial needs to make moreefficient use of the technology available to them from their Supervisory Control and DataAcquisition SCADA system. Colonial is now in the process of upgrading their SCADA systemand should consider incorporating some changes to operate their SCADA system with fewermanual interventions and allow Controllers to use standardized colors on the. SCADA screensto reduce operator error. Although Colonial has a sophisticated SCADA system, many criticaltasks are still performed manually. In addition, there are flaws in their pressure recordingtechniques and operating pressure change-control processes.Colonial needs a comprehensive approach to operating practices and needs to develop ameans to see that practices are updated, communicated, and followed system-wide. Colonialneeds to assure that consistent operational data is generated throughout the company andused for analytical review.A detailed list of recommendations and findings is located in Section 7 of the report. II

O January 10, 1997 OPS Task Force Report Colonial Pipeline Company 10 Introduction The Department of Transportation DOT Research and Special Programs AdministrationRSPA Administrator formed an Office of Pipeline Safety OPS Multi-regional Task Force Task Force to examine Colonial Pipeline Company's Colonial operation, maintenance, and training programs to expose any trends or deficiencies to help prevent future accidents. Additionally, the Task Force conducted a review of Colonial's accident and compliance history. This action was taken following Colonial's June 26, 1996, accident. Colonial's 36-inch pipelinecrossing at the Reedy River near Simpsonville, SC had been identified as having corrosion and was scheduled for replacement. However, the section of pipe ruptured as a result of the corrosion and operator error prior to construction. The accident released approximately 22,800bbl. of fuel oil into the Reedy River. The June 26th accident is Colonial's largest single spill in their 33 year history. Colonial has had five major pipeline spills since 1990. This accident rateexceeds the industry average no other liquid pipeline operator reported more than two major spills in the years 1990- 1996. Less than five months later, Colonial's 8-inch pipeline nearMurlreesboro, TN also failed as a result of an operator error. This accident released approximately 1,500 bbl. of fuel oil.The Task Force was formed with representatives from the three OPS regions which Colonial traverses. The Regional Directors Frederick Joyner - Southern, William Gute - Eastern and James Thomas'- Southwest Co-Chair the Task Force. The three primary members of the TaskForce are Rodnck Seeley - Southern Task Force Leader, Byron Coy - Eastern and Richard Lopez - Southwest Region. Other inspectors from each region served support roles to assist in the investigations. In addition, General Physics an engineering consultant firm located in Columbia, MD was contracted to perform an independent review of Colonial's Supervisory Control and Data Acquisition SCADA system. The primary goals were established and the Task Force began its activities in early August 1996. This Report will focus on issues of primary concern. The topic areas are: * Colonial's Compliance History * Colonial's Accident History * Colonial's Operational Methods * Colonial's Maintenance' Program * Colonial's Training Program Note: This report contains material and terminology of a technical nature which may not be familiar to the general public. Therefore, a glossary of terms has been included in Appendix H, to assist the reader. 1

O January 10, 1997 OPS Task Force Report Colonial Pipeline Company 2.0 Colonial Pipeline Company 2.1 Introduction Colonial is the largest refined petroleum products pipeline company in the United States. Their pipeline system consists of approximately 5,317 miles of pipeline which deliver refined productfrom Pasadena, TX to the New York Harbor area. There are approximately 2,887 miles of mainline and approximately 2,244 miles of stub lines. Colonial has approximately 307 breakout tanks located at 14 tank farms to provide temporary storage which assist in the transportation of the product. 2.2 A Brief History `In the early 1940's, the need for a refined petroleum products pipeline to link the refineries of the Gulf Coast with markets on the Eastern Seaboard became apparent. At the time, ocean-going tankers were the sole line of supply between the largest refinery complex in the nation, located on the Gulf shores of Texas, Louisiana and Mississippi and vital industries manufacturing war materials located in the Northeast. Private enterprise responded to the emergency by constructing a 684 mile 12 and 10-inch pipeline system from Baton Rouge, LA, to Greensboro,NC, and the Southeastern Pipe Line, an 8-inch line from Port St. Joe, FL, to Lookout Mountain, TN. Following the war, marine transport returned to prominence as the primary mode for transporting growing volumes of petroleum products from the Gulf Coast to the Eastern Seaboard. Several oil companies considered plans for construction of a pipeline to compete with existingpipelines in the late 1940's and early 1950's. lt.was not until 1956 that representatives of Sinclair, Texaco and Gulf began seriously discussing the feasibility of constructing a petroleum products pipeline from the Gulf to the Eastern Seaboard. During the next five years, American,$ Pure, Phillips Petroleum, Cities Service and Continental joined the talks. The eight companies involved in the discussions preferred transporting product by pipeline and were shippers on the same pipeline. This pipeline was operating close to capacity and frequently was required to prorate the volumes. in June 1961, the eight shippers announced plans to construct Suwannee Pipe Line. Suwannee was onginally planned as a 22-inch pipeline from the refineries of the Gulf Coast to$ Baltimore, MD with the capacity to transport 300.000 barrels per day. At the end of the summer of 1961, Socony Mobil now Mobil indicated its interest in joining the project and Suwannee was scuttled in favor of a more ambitious project from the Gulf coast to the New York Harbor. On March 6, 1962, the nine oil companies incorporated Colonial Pipeline Company in Delaware and construction of the large diameter pipeline system was initiated. According to plan, a 36-inch mainline from Houston, Texas to Greensboro, N.C. was completed first. In September, 1963, linefill began at Houston. Colonial officially began service from Houston to Greensboro and points between in November 1963. The first dehvery to shipper tankage on the mainline system was made at Oxford, AL on November 17, 1963. Other deliveries were made in rapidsuccession. Construction of stub lines branching from the mainline system was coordinated with 2

O January 10. 1997 OPS Task Force Report Colonial Pipeline Company the mainline construction from Houston to Greensboro. Deliveries on stub lines began at about the same time as deliveries to terminals on the Colonial mainline system. The last of the initial stub lines were activated when deliveries were made at Apex and Fayetteville, NC in March 1964; and to shipper tankage at South Macon, GA in March 1964. Construction of a mainline 32-inches in diameter from Greensboro, NC to Colonial's DorseyJunction, near Baltimore, MD, and one 30-inches in diameter from Colonial's Dorsey Junction to the planned mainline terminus near Linden, NJ, was already well underway when the mainline from Houston, TX to Greensboro, NC was placed in service. Linefill from Greensboro to Lindenbegan on April 7, 1964. The first product reached Colonial breakout t·nkage at Linden, NJ on December 1, 1964, signaling completion of the entire Colonial mainline system less than 18 months after construction had begun. * For the most part, shipper terminals on the mainline from Greensboro to Linden were to beserved by a complex system of stub lines originating at Colonial junction locations. The first of these stub lines was placed in service shortly after the start of linefill of the mainline from NorthCarolina to New York. The first northern stub line delivery to shipper tankage was made at Roanoke, VA, on April 28, 1964. Activation of other stub lines making up the northern stub line system continued to February 2, 1965. Colonial was incorporated as an interstate common carrier subject to regulation by the Interstate Commerce Commission and obligated to provide the same service to all shippers. Almost assoon as Colonial began service, shippers other than owner companies began utilizing the system at the same rates charged to the owner companies. In addition, soon after the original system was completed, it became apparent that petroleum demand and population growth had been underestimated in Colonial's market area. Between 1971- 1980 Colonial added 1,293 miles of mainline pipe to loop the existing mainline system from Baton Rouge, LA, to Dorsey Junction, MD. Approximately 842 miles of stub lineswere constructed. New mainline and stub line pump stations were built and others, modified to bring the total system throughput capacity to 2,200,000 barrels per day. During much of the 1970's, up to the completion of mainline looping in November 1980, portions of the Colonialsystem, particularly in the Central Atlantic states, had been subject to proration. For all practical purposes, mainline proratiOn ceased at the end of 1980.From the late 1980'S to the present Colonial's expansion slowed. In that time, Colonial constructed approximately 167 miles of stub lines. Colonial expanded their technology commitments and in 1985, initiated their "Smart Pigging" program to identify areas of corrosionontheir pipelines. In 1989, Colonial joined an API program to promote Breakout Tank Safety. In 1992, in order to test and develop technology to find longitudinal seam cracks a systematic problem for pipe manufactured by National Tube in their original mainline, Colonial participated in the development of an internal inspection tool to detect seam cracks in liquid pipelines.Colonial successfully applied this new technology in 1995 and 1996. 3

O JanuarylO,1997 OPS Task Force Report Colonial Pipeline Company 2.3 Organizational Structure In 1994, Colonial reevaluated its organizational structure with the objective of making both itsadministrative and operational functions more efficient. Management formed an eight member team to evaluate and update all work processes and to recommend an organizational structure which would support the new processes. As briefly. detailed in Appendix A, Colonialdecentralized the technical expertise and relocated the project staff to field locations closer to the work. At the same time, Colonial centralized the operations of the pipeline by moving more control to the Atlanta Control Center. Stub line control, previously managed by local operating systems, were moved into the new Atlanta Control Center. The re-engineering resulted in a net reduction 6% of the authorized complement.Headquarters support was reduced by 19% while field staffing was increased by 1%. Engineering was reduced by approximately 32%, through the transfer of several staff personnel to field project positions. Also, substantial changes were made in procurement and right-of-way procedures. One of the many work processes changed by re-engineering was the job selection process. Currently, all job vacancies are posted internally providing all employees the opportunity toexpress interest. All interested employees are considered by a selection team rather than management alone. This new process provides an opportunity for good candidates to be considered regardless of their formal education level. In fact, several project managers do not hold an engineering degree. The Task Force will address the specific È~fects of the re-engineering as it relates to operations, maintenance and training in the appropriate sections of this report. 4

O January 10, 1997 OPS Task Force Report Colonial Pipeline Company 3.0 Compliance Report 3.1 Introduction Hazardous Liquid Pipeline HLP operators came under Federal Pipeline Safety Regulations, enforceable through the OPS, in 1968. The OPS was charged with inspecting HLP operators toensure compliance with these regulations. Additionally, the OPS often investigates accidents to * determine the cause and to determine if and when a pipeline can be returned to service, including approving remediations, to assure pipeline integrity. The inspections andinvestigations determine if violations of the pipeline safety code have occurred. The Task Force identified and reviewed 27 compliance related actions issued by the OPS to Colonial. These have been divided into two groups: Compliance actions resulting from standard inspections and compliance actions resulting from accident investigations. The following sections discuss the results of this review. 3.2 Standard Inspection Compliance Actions The OPS has issued 17 compliance actions as a result of standard inspections against o Colonial1. Some actions include multiple violations of the federal regulations 49 CFR Part 1959The Task Force reviewed these actions in an attempt to identify any trends or relationship to accidents Colonial has experienced. This section will briefly discus the results of that review and the compliance actions taken as a result of OPS standard inspections of Colonial. On ten occasions, Colonial has been cited for non-compliance with the corrosion control regulations. In the 1980's, the OPS cited Colonial three times one involving a civil penalty fornot maintaining adequate cathodic protection levels. Colonial took prompt remedial actions and since 1988, no actions have been issued for inadequate cathodic protection levels. There have been two citations issued against Colonial for incomplete corrosion control procedures.Recently, Colonial was cited for not considering IR drop in their monitoring program. Colonial has been continually updating their corrosion control program as a result of OPS inspections and their own discoveries. Even so, corrosion was identified as a contributing cause for the Reedy River accident, therefore, Colonial's corrosion control program is one of the majorfocuses of the maintenance section of this report. On four separate occasions, Colonial was cited one involving a civil penalty for exceedinginspection intervals on required river crossing inspections. These inspections serve as a major source of data for an operator to evaluate the condition of their pipelines in a highly sensitive area. As discussed in Section 5 of this Report, Colonial began an extensive internal inspectionprogram in 1985 using instrumented in-line inspection ILl devices, commonly referred to as smart pigs. Some ILl tools are able to estimate pipe wall loss before it reaches the point where a pipe would leak or rupture. This can be a very useful tool in evaluating the effectiveness of thecorrosion control practices on the pipeline. These tools also provide detailed information of the pipelines physical condition particularly in environmentally sensitive areas like river crossings. In *` See Appendix B; Table B-2 5

O January 10, 1997 OPS Task Force Report Colonial Pipeline Companyfact, Colonial has already replaced several pipeline sections in river crossings as a result of data obtained through ILl tool runs2. At times, Colonial elected to replace these crossings with an advance replacement technique commonly known as directional drilling. Directionally drillingoften results in a greater expense to the operator than a conventional crossing replacement. Also, the pipeline crossing at the Reedy River near Simpsonville, SC was scheduled for replacement due to corrosion detected during an earlier March 1996 ILl run but the ruptureoccurred before construction commenced. The Task Force believes Colonial has adequately addressed the concerns resulting from the previous violations of the pipeline safety code relating to river crossing inspections. There have been seven actions issued for inadequate procedures in Colonial's Operations and Maintenance Manuals. Colonial took immediate steps, with one exception, to update theirmanuals. In a 1995 Warning letter, Colonial received notification that their cathodic protection procedures were inadequate by not considering IR drop. Colonial, at this time, has not modified their manuals to include IR drop considerations in their corrosion control program. With the noted exception, the Task Force feels Colonial has taken adequate steps to alleviate any concern resulting from these procedural deficiencies. The compliance actions written in 1996 include missed inspections on tanks and valves.Colonial did not dispute these violations and it is anticipated that the actions wilt be closed shortly.The Task Force reviewed the standard inspection compliance actions issued to Colonial, but no discernable trends could be identified. Additionally, no clear relationship could be determined between these standard inspection compliance actions and the accidents Colonial hasexperienced with one possible exception. Colonial has been cited several times on corrosion control related issues. Although Colonial's accident rate for corrosion is less than the HLP industry, Colonial has experienced several accidents due to corrosion. Most recently, the accident near Simpsonville, SC was due to corrosion. 3.3 Accident Compliance ActionsThe OPS has issued ten compliance actions against Colonial3 as a result of accident investigations. Briefly, three compliance actions against Colonial have been for over pressuring the pipeline. Pressure monitoring and protection is a major focus in the Operations Report,Section 4, of this report. There have been three instances where limited segments of Colonial's system have been declared a hazardous facility by the OPS. There have been seven instances where the OPS has issued an order or entered into an agreement requiring Colonial to perform additional inspections to ensure pipeline integrity. 2 Pipeline crossings at Turtle Bayou, Thompson Creek, Atchafalaya, Delaware. Coosa and the Arthur Kill Rivers have been replaced. ~ See Appendix B: Table B-3. 6

January 10. 1997 OPS Task For~ Report Colonial Pipeline Companyfrom the weight of the pipe and cyclic stresses occumng during transportation are higher if notproperly loaded on the rail car. The rail transportation loading problem was addressed in APIRP 5L1, Recommended Practice for Railroad Transportation of Line Pipe published in 1965.As of this date, Colonial and Lakehead Pipelines are the only pipeline operators in the UnitedStates that have had in service longitudinal seam crack failures attributed to rail transportation.Both operators have pipelines constructed with high D/t ratio pipe before the API RP 5L1Standard. Both of these pipeline operators have programs, as directed by OPS, to internallyinspect or hydrostatically test portions of their pipelines to locate longitudinal seam cracks. Pipewith high D/t ratios having dents and/or stress risers are more susceptible to fatigue cracking.Also, thin walled pipe can be more susceptible to corrosion leakage because there is less pipewall to corrode. The OPS has recognized the need for further study of these issues and otherassociated issues. The OPS has contracted studies currently underway on a number of theseissues. A brief discussion is included in Appendix G.It's worth noting, that the operator with the highest accident rate did not have a high D/t ratio.This notwithstanding, a future study involving the impact of a high D/t ratio within the pipelineindustry may be warranted.The Task Force reviewed the reported causes of HLP accidents. Three areas of primaryconcern which helped form a major part of the framework for this Report are operator error,corrosion and mechanical Third Party damage.Colonial has experienced a greater accident rate of operator error than the industry average.Operator error accounts for approximately 19%' of all of Colonial's accidents reported to OPS.Of the 37 accidents reported by Colonial with operator error listed as the cause, 12 32%resulted in spills of 1,000 bbl. or more10. In fact, the volume of product released from operator.error accidents account for nearly 23% 52,028 bbl. out of 224,311 bbl. total of all productreleased by Colonial. This has caused concern within the OPS and prompted the Task Force toreview Colonial's training program, Section 6.Operator error has been linked to the most recent Colonial accidents11. Often, as was the casein these accidents, over-pressure of the pipeline occurs, creating further concern andemphasizing the need to evaluate Colonial's operating logistics and over-pressure protectiondevices, see Operations Report, Section 4.In contrast, Colonial has experienced a lower accident rate for accidents caused from corrosion,and outside force damage than the industry'2. Of the 24 reported accidents with corrosion listed See Appendix B: Table B-7. `°See Appendix B; Table B-4. Il Accident 6/26/96, Reedy River. SC; and 11/5/96, Murfreesboro, TN. 12 CorTosion: Colonial=12%. lndustry3O%; Outside Force: Colonial24%. lndustry=27%.

January 10, 1997 OPS Task For~ Report Colonial Pipeline Companyas the cause, eight 33% resulted in spills of 1,000 bbl. or more'3. The volume of productreleased from corrosion accidents account for nearly 19% 42,997 bbi of all product releasedby Colonial. As discussed in the report, the reduced number of accidents may be a result of theattention given to Colonial's cathodic protect~on program resulting from OPS inspections andColonial's aggressive pigging program. Although Colonial has experienced fewer accidents dueto corrosion, the volumes associated with them are great. Colonial's largest product release14and the continued occurrence of corrosion accidents has prompted the Task Force to look intoColonial's corrosion control program, see Maintenance Report, Section 5.3.1.Of the 34 reported accidents with Third Party damage listed as the cause, seven 21% resultedin spills of 1,000 bbl. or more15. The volume of product released from Third Party damageaccidents account for nearly 18% 40,158 bbl. of all product released by Colonial. OPS hasbeen concerned with the number of HLP accidents resulting from third party damage and feelsthat this cause is controllable. This attitude has prompted rulemakings requiring operators tohave an underground utility damage prevention program and to participate in a one-call system,see Appendix G.To Colonials credit, they have been a strong supporter and participant in one call systems in thestates in which they operate. In states that lacked a one call program, Colonial has promotedthe establishment of these programs. In recent years, the OPS has provided funds to states toimprove the state underground utility damage prevention programs. The OPS has sponsorednational symposiums on determining the most effective methods on preventing third partydamage to pipeline. The OPS is currently co-sponsoring a joint industry/federal/state! insurancecompany team to develop a effective national educational program to prevent third partydamage to underground utilities. The Task Force recognizes that the reduction of third partydamage to pipelines will be achieved only if industry, state and local government, excavators,and the public continue to work in partnership to achieve this common goal.Equipment failure accidents resulted in 11,962 bbl. 5% of product released. There are anumber of reason for equipment failures. A significant number of accidents were failuresrelating to valves and flange gasket materials, particularly gate valve stem and check valve shaftpacking. An aggressive maintenance program can help to alleviate such occurrences withfrequent replacement and maintenance of parts and sealing materials. Colonial has addressedthis issue throughout their history as the nature of their products change. In 1992, Colonialbegan a program to detect and contain stem and shaft seal leaks at all main line pump stations.In 1993, Colonial incorporated new specifications for stem seals compatible with oxygenatedfuels'6. These programs reduced the number of seal leaks; in 1992 Colonial reported six stem `3See Appendix B; Table 8-4. ~ June 26. 1996 accident near Simpsonville, Sc reported a spill volume of 22,800 bbl. `~ See Appendix B; Table 8-4. 16 Colonial Engineering Bulletin 91-B. 9

O January 10. 1997 OPS Task Force Repoit Colonial Pipeline Company seal leaks and none were reported in 1995 and 1996. See Section 5 for a discussion of Colonial's maintenance program. Colonial has had a number of accidents with similarities which prompted the OPS to initiate other actions. For example, in 1990 the OPS formed a Task Force to investigate the longitudinal seam failure problem Colonial has experienced. Additionally, Third Party damage related accidents have been addressed through compliance actions which require Colonial to run ILl tools to identify and repair noted anomalies17. 3.3.2 1990 Task Force Investigation The Task Force reviewed the 1990 OPS Task Force Report: ColOnial Pipeline Fatigue Failures, dated September 14, 1990, some important issues are discussed below. For a complete background, please refer to the 1990 OPS Task Force Report. Colonial has experienced six accidents with longitudinal seam failures on its original largediameter double submerged arc welded DSAW pipeline. The most recent accident was on December 18, 1989. As a result of the similar nature and characteristics of the six accidents, the OPS formed a task force in 1990 to examine the history of Colonial's original pipeline. This. task force investigated these accidents and concluded: * The six failures were the result of fatigue cracking probably initiated during rail shipment; the original hydrostatic testing did not remove all of the cracks; and that the remaining cracks will continue to grow and possibly result in other pipeline failures. * The longitudinal seam cracks appear to be limited to Colonial's original mainline system constructed between 1962 and 1964. * There was no practical and conclusive nondestructive testings system available to detect cracks in or at the longitudinal weld in DSAW pipe. * Improved pipeline safety can best be obtained by hydroÈtatic testing of the original pipeline to pressures capable of causing the remaining cracks to fail. The 1990 Task Force recommended that an Operational Reliability Analysis ORA be performed on the mainline Line 4 located in Virginia. This ORA concludes18: * The failures were identified as having been caused by rail-shipment-fatigue cracking which failed due to the action of service pressure cycles. `~ CPF's 13503-H. 14501-H, 26503-H ~ Taken from Operational Reliability Assessment of Colonial Pipeline Company's 32-inch Line 4, Keifner & Assodates. August 19. 1991. 10

O January 10, 1997 OPS Task Force Report Colonial Pipeline Company * The failures could be controlled by reducing the number and size of pressure cycles, but this was impractical. * An ILl tool offers the best hope in controlling the phenomenon. While no device exists, it is recommended that the development of such an instrument be pursued. * Hydrostatic testing can be used to control crack growth failures, but the testing interval would be impractical. If, however, an ILl tool is not developed hydrostatic testing repeated at intervals of several years should be performed.As noted by the 1990 Task Force, non-destructive inspection methods for identifying crackswithin pipelines were not available for commercial use, thus, the recommendation for hydrostatictesting of the pipeline. Their investigation also revealed that five of the six failures occurred inpipe manufactured by National Tub&9. Since their report, Colonial has joined with British Gas,Lakehead and lnterprovincial Pipeline Canada in developing an ILl tool capable of identifyinglongitudinal seam cracks in liquid pipelines. This would eventually lead the OPS to requireColonial to run this crack detecting pig in all of their thin wall pipelines manufactured by NationalTube and Republic Steel installed during the original construction20. In fact, this tool has beenused extensively by Colonial in Mississippi, Alabama, South Carolina,North Carolina, Virginiaand Maryland. The British Gas crack tool has detected longitudinal seam cracks smaller thanwould be discovered by a hydrostatic test21 and the hydrostatic testing recommendation hasbeen waived in lieu of this latest technology.3.3.3 Open Compliance ActionsThere remain five open compliance actions against Colonial resulting from accidents. Aviolation and civil penalty case resulting from an over-pressure in Baton Rouge, LA is not beingdisputed by Colonial and it is anticipated that this case will be closed shortly. A violation and civilpenalty case involving reporting violations resulting from an accident in Macon, GA is not beingdisputed by Colonial and it is anticipated that this case will be closed shortly. While progresscontinues, the following will briefly summarize three remaining open actions.3.3.3.1 Consent Order: CPF 14501-HCPF 14501-H is a. Consent Order which incorporated all of Colonial's ILl requirements fromGreensboro, NC to Dorsey Junction, MD in one consolidated order. The following is a briefdescription of the events leading to this order. ~ other failure occurred in pipe manufacturer by Republic Steet; the only known case by thismanufacturer. 20CPF 10504a later induded within CPF 14501-H. and CPF 26503-H ~lnvestigation of Pig Indicated Anomalies in Selected Specimens of Line 4-Louisa to Remington, Keifner &Associates. 8/7/96 - 11

January 10. 1997 OPS Task Force Report Colonial Pipeline CompanyFollowing the December 1989 accident in Orange County, VA, the OPS entered into a Section211 Agreement CPF 1 0504A which required Colonial to test the National Tube pipe in thevicinity of the accident. Colonial hydrostatically tested approximately 140 miles of pipeline inVirginia and Maryland. The agreement also required Colonial to restrict their operating pressureand perform an ORA. As discussed earlier, this ORA recommended that the National Tube pipeshould be re-hydrostatically tested or smart pigged with a device capable of detecting longitudinalseam cracks by 1995. Colonial ran the newly developed British Gas crack tool in 1995.On March 28, 1993, Colonial's 36-inch pipeline which runs from Greensboro, NC to DorseyJunction, MD ruptured near Reston, VA spilling approximately 9,708 bbl. of fuel oil. This productwould eventually reach the Potomac River which would cause great public concern. Following aninvestigation by the OPS and the National Transportation Safety Board NTSB, it wasdetermined that the pipeline rupture resulted from previous mechanical damage typicallyassociated with third party damage~.Subsequently, the OPS issued a Hazardous Facility Order HFO CPF 13503-H declaring aportion of Colonial's system hazardous. The HFO required Colonial to perform metallurgicaltests on the failed pipe and expose the top half of the pipeline to examine for third party damagein the vicinity of the accident and submit an ILl plan from Chantilly. VA to Dorsey Junction, MDfor the 36-inch mainline.In 1995, OPS and Colonial entered into a Consent Order CO CPF 14501-H whichincorporated issues from the previous proposed orders. The CO requires Colonial to run varioustypes of smart pigs through their 36-inch and 32-inch pipelines between Greensboro, NC andDorsey Junction, MD. Colonial continues to work toward completing all remaining issues of theOrder; the required ILl are scheduled to be completed by the year 2000. This is furtherdiscussed in Section 5.8 of this report.3.3.3.2 Hazardous Facility Order: CPF 26503-HPreliminary investigation revealed that on June 26, 1996, Colonial was operating Line 2 undernormal conditions: they were stripping into tankage at Atlanta Junction, GA; Charlotte Delivery,NC; and Greensboro Junction; NC. The scheduled delivery to Atlanta was completed whichresulted in increased volumes going north; additional horsepower was added along the pipelinesystem by starting additional pump units to maintain the desired flow rate into Greensboro, NC.In the process of adding horsepower to the system, a large pump unit was signaled to activate atGastonia Station, NC and a smaller pump unit was taken off-line. The larger unit failed to comeon-line. The resulting lack of pump head sent a pressure wave upstream. As this wave traveledupstream, Gaffney and Simpsonvifle pump stations shutdown, thus creating separate butcumulative waves. The pressure waves eventually arrived at the Reedy River near Simpsonville, ~ NTSB Report PB96-91 7002. Accident Brief DCA93MPOO7 12

January 10, 1997 OPS Task Force Report Colonial Pipeline CompanySC, where a section of pipeline had been weakened by corrosion~. The resultant pressureruptured the pipeline within the corroded section. The pipeline rupture released approximately22,800 bbl.24 of fuel oil into the Reedy River.Following the June 26,1996 accident near Simpsonville, SC and subsequent investigation, theOPS issued a HFQ CPF 26503-H. During an evaluation of the available ILl data25, it wassuspected that two other areas26 exhibiting signs of corrosion existed on the pipeline and shouldbe evaluated on an "orderly and reasonable basis"27. It was suspected that substantial wallthinning may have existed at these locations. Subsequently, this order restricted the operatingpressure at these locations. Also, the HFO required excavation, examination and, if necessary,repairing of the two sections. Colonial replaced the two identified pipeline sections with heavierwall pipe. The construction was inspected by OPS Southern Region staff. No additionalconcerns remain relating to these two sections and the pressure restrictions were lifted~.Additionally, and from the preliminary investigation, it was suspected that the pressure switchesused by Colonial did not conform to manufacturing specifications. The HFO required anevaluation of Colonial's pressure switches in use on the original pipeline. Colonial performedthe evaluation of the pressure switches~. They determined that of the 97 existing switches, 21were of a different design. Colonial elected to replace these 21 switches, making all of theswitches in use of the same design. The OPS has followed up on this issue requestingadditional information on Colonial's pressure switches. At the time of this Report3° this issueremains under investigation. Additionally, Colonial's hydraulic transient flow model has beenmodified to incorporate the switch design. Colonial is currently re-evaluating the operationalsettings. of their pipeline system and, if necessary, makingset-point changes.As noted earlier, En 1995, Colonial began using the modified British Gas ILl crack tool, asrequired by the Section 211 Agreement CPF 10504A and CO CPF 14501-H, and has hadsuccess finding longitudinal seam cracks in their pipelines. Because of this success and thesystemic fatigue crack problems with National Tube and possibly Republic Steel pipe installed ~ A Safety Related Condition Report 96-01 was filed by Colonial indicating they reduced operatingpressure due to corrosion discovered by an internal in-line inspection, March 1996. ~` From DOT form 7001 filed with OPS. ~ A smast pig was run through this section in March 1996. 26Reedy Cree' and Broad River areas. 21Evaluatior, of Electionic Pigging Surveys. H. N. Duckworth Report, 7114/96. ~ OPS letter dated October 23. 1996. 29 Colonial letter dated October 29, 1996. 3° OPS letter dated November 12. 1996. 13

O January 10, 1997 OPS Task Force Report Colonial Pipeline Company during the original construction, OPS amended this CO requiring Colonial to perform hydrostatictesting of the original pipeline or run the British Gas elastic wave inspection tool31. Colonial haselected to comply with the ILl option in the. amendment. Colonial is developing an inspectionplan to accomplish this task within 5 years. A detailed analysis of Colonial's ILl program isdiscussed Section 5.8 of this report.3.3.3.3 Proposed Compliance Order: CPF 26506On November 5, 1996 Colonial's 8-inch pipeline near Murfreesboro, TN failed. Preliminaryinvestigations revealed that prior to a planned nitrogen displacement, Colonial restarted their 8-inch pipeline which runs from Atlanta, GA to Nashville, TN: The pipeline was making a deliveryinto Colonial's Lookout Mountain Delivery Station, upstream of Murfreesboro, TN. Product flowwas directed north to Nashville, TN. Pump units were started at Signal Mountain and CoalmontStations, booster stations directly upstream of Murfreesboro Station. The block valve was stillclosed at Murfreesboro, TN from the earlier shutdown. When the Controller attempted to openthe valve, it failed to open. This line blockage caused the pipeline to experience an over-pressure condition and the pipeline ruptured. The resultant spill released an estimated 1,500bbl. of fuel oil.By having the valve closed, the Controller was unable to see pressure variations at Murfreesborostation. The closed valve effectively prevented the over-pressure protection devices fromactivating. The investigation also revealed that some display screens did not accurately reflectthe actual configuration of the pipeline. .Subsequent to the preliminary investigation, OPS issued a proposed Compliance Order CPF26506 requiring Colonial to examine their SCADA system for inaccuracies in their displays.Also, Colonial has been requested to evaluate, system-wide, their pipeline system for designanomalies similar to those involved in this accident: where a block valve isolates the station'sprotection devices. Also, the investigation revealed that the upstream over-pressure protectionequipment was set such that the pipeline downstream experienced an over-pressure conditionbefore the upstream devices activated. Colonial has been requested to evaluate their systemand correct any similar design anomalies. As of this report, no response has been received fromCOlonial on these issues.Note: At the time of this report, Final Orders 26503-H and 26506 have not been published. Complete details of theabove accidents can be obtained through the Accident Investigation Reports. ~ Pipelines manufactured by US Steel National Tube and Republic Steel installed during originalconstruction. 14

O January 10. 1997 OPS Task Force Report Colonial Pipeline Company 4.0 Operations Report 4.1 Introduction The recent accidents at the Reedy River near Simpsonville, SC and in Murfreesboro, TN have focused the Task Force operations review to pipeline control and pressure. In line with this focus, a significant ingredient of this work included the review of recent unscheduled shutdowns that did not necessarily involve serious accidents. Personnel, procedures, logistics, control and documentation each have a direct influence on Colonial's control systems and pipeline pressures. Each of these parameters will be addressed throughout this section. Aspects of the Reedy River accident havebeen added at appropriate points within the analysis. The Murfreesboro, TN accident occurred latein the Task Force review. Related aspects of that accident have been added as a topic area. Toensure that all critical elements are reviewed, the following topic areas have been established. * Organization * Control Systems Overview * Recording of Line Pressure * Operations Analysis * Pressure Safety Systems and Pressure Alarms * Tank Level Alarms * SCADA and Operations Support Systems * Revision and Change Control for Line Pressures * Murfreesboro, TN Accident4.2 OrganizationControllers operate the four mainlines Lines 1, 2, 3, 4 and the stub lines from a centralized controlcenter in Atlanta, GA. Field Operators, a labor classification, are positioned at hub points and keydelivery facilities to coordinate and control product cuts and deliveries to shipper terminals. Thesemi-manual operation of delivery facilities has been designed to lessen the impact of disruptiveevents by providing the opportunity for local personnel to foresee problems and recover from upsetconditions more quickly than could be expected from a distant, centralized control center. TheTask Force review of unscheduled shutdowns' indicated that delivery facilities are more prone toupset conditions than are pump stations or pipe segments.The two parts of the organization that most directly affect pipeline operations are Controllers andfield Operations. Engineering has a supportive role. Controllers and several Relief Controllersreport to one of four Controller Shift Supervisors, who in turn report to the Operations Team Leader.Field Operators report to Operations Managers in each district. Headquarters engineers report tothe Engineering Services Team Leader. Only a portion of the Engineering group are directlyapplied to pipeline operations. All of these groups are featured in Table 4.1 that depicts the staffinglevels before and after the re-organization. Details found in Section 4.5 of this report. 15

January 10, 1997 OPS Task Force Report Colonial Pipeline Company Table 4.1: Pipeline Operations Personnel Task Groups do not necessarily agree with Organization TablesTask Groups,Prior to Re-Organization, 1994Staff Priorto Re-Org.Task Groups,After Re-Organization, 1995Staff AfterRe-Org.PercentChangeHdqrs Operations Planning.Operations Control,& Process Computing61Hdqrs TransportationServices Central Team64+5%Greensboro Area,Greensboro-Selma-ApexOperators34Greensboro Location,Greensboro-Selma-ApexOperator230* 12%Hdqrs Engineering46Hdqrs EngineeringServices Team25- 45% A review of the changes in the organization shows a shift from centralized to distributed project implementation teams. This change places permanent engineering and project staff talents nearer to work sites and eliminates the former field Maintenance Supervisor positions. Colonial's headquarters engineering staff has been reduced by 45%. The large percentage change to Project Managers appears inflated due to the small number of individuals. From an operations perspective, there was only a modest change to staff. While keeping the operations staff relatively flat, additional locations have been converted to automated remote control and added to the SCADA system. Converting locations to automated remote control transfers operations from the field Operators to the Atlanta Controllers. Opelousas, LA and Oxford, AL were converted in 1996. According to Colonial, there is an on-going study to add automated remote control locations, each of which must satisfy both economic and safety considerations. Adjustments to the number and location of personnel is a part Of these studies which are usually driven by changing market conditions and applicable technology. 4.3 Control Systems Overview 4.3.1 Separation of Control Colonial's mainlines are terminated at Greensboro, NC to provide buffering between the north andI. south mainline segments. All product arriving from the south Lines 1 & 2 is directed into tankage. All product traveling further north Lines 3 & 4 is drawn from tankage. Generally, Colonial draws product from tanks that have been filled earlier. According to Colonial, this provides a latitude inlogistical control that lessens the chance of upset conditions, inhibits the propagation of pressure disturbances, and allows them to assemble and maintain large batches for shipment further north. The stub lines and delivery lines are fed by a combination of tank-source and stripping operations. Because all of Colonial's tanks are used for temporary pipeline breakout storage,they are under the jurisdiction of the OPS, and subject to 49 CFR Part 195. The manual control of individual stations implemented in the 1960's has now been reformed toinclude a separation of duties between the Atlanta Controllers and strategically placed field Operators. Colonial essentially controls the pipeline system in two operating domains. The mainlines and major stub lines are remotely controlled from Atlanta. Six pipeline controllers on each shift monitor and control the movement of products via a SCADA system from injection points Greensboro-Selma-Apex Operators are representative of the impa~ on the overall field organization. 16

O January 10, 1997 OPS Task Force Report Colonial Pipeline Companythrough intermediate booster stations, and convey control to numerous field operations personnelnear delivery facilities. Master schedules are generated in Atlanta using a graphical schedulingtechnique that is based on the railroad line graph method3. Controllers track the movement ofbatches by using these railroad charts. In addition to automatic gravitometers and flash monitorsconnected to centralized SCADA, field operators conduct manual product tests to identify batchends, which subsequently provide information for tank and line switches. The control center inAtlanta performs heart cuts based on volume, but all interface cuts are performed by fieldoperators. Field operators also perform heart cuts. From Colonial's perspective, equipment hasbeen installed to automate only the facilities that have been economically justified and that do notcompromise operational safety. Colonial's operating principles still require manual intervention fortank switches and product interface cuts.4.3.2 Design ParametersColonial maintains a system design hierarchy that provides ______________________________a two tier system of control. Elaborate computer systems inAtlanta provide centralized control for most pump stationsand long pipeline segments, with regional field operatorscontrolling the hub points and delivery facilities. Thefunction of the centralized SCADA system is to providestation monitoring and control functions for the Controllersin Atlanta, through which individual pumps and valves maybe remotely operated. A typical pump station has multipleunits ranging in size from 1,000 to 5,000 horsepower seeFigure 4.1. A set of valves either bypass the station ordirect flow around a serial pump loop. A combination ofpumps can be used to satisfy operational requirements.Local station control logic panels or Remote Terminal UnitsRTU are applied at each station to protect the station and Typical Pump Stationdownstream piping from critical pressures. All safety Figure 4.1actions, including pump trip and relief valve operations areperformed locally and independent of the Atlanta Control Center. When communications are losteither with Atlanta, or the associated hub point, stations remain.in the commanded stateimmediately prior to the outage, or until station safety equipment trips one or several of theoperating pumps. This important feature in the design of the overall control system makes eachpump station self-sufficient4. This is a common design practice in hazardous liquid pipelines and issometimes called station interlock design. The industry in general, including Colonial, considersthe use of preconditioning logic to allow critical operations to be made without being affected bytemporary communications oUtages5. Those facilities in the domain of field operators also havestation interlock controls.Although key data elements from each major station are electronically conveyed to Atlanta, Colonialdoes not use system-wide data to inhibit pump station operations, a process called systeminterlocks. Hydraulic parameters with large line-pack variations would require a complex set ofsystem interlock controls and alarms. Line-pack variations also make it very difficult to perform linebalance calculations~ Custody transfer meters are placed at each receipt and delivery point and at 3A graphical method of portraying the position and movement of batches in a pipelin. `General Physics Report Section 2.1 5API Recommended Practice 111317

January 10, 1997 OPS Task Force Report Colonial Pipeline Company Greensboro, NC, but there are no other interim meters along the pipeline to aid in volume balance calculations. The need to perform manual volume balance and review system-wide data add to the work load of the Controllers. The design of Colonial's control system accounts for pressure limitation, but is based on flow rates. Flow rates are achieved by operating a combination of stations and pumps. Stations on the mainlines have control valves that are manually set and are not remotely controlled. These station control valves are principally used for over-pressure pressure above MOP protection and are designed to throttle at, or just above, the pressure limitations of the down-stream pipeline segment. As a result, there is. usually only a small pressure differential between the pump case and station discharge pressures at mainline stations. Constant pressure control is only applied at source and destination points. The selection of pumps at intermediate stations work in concert with pressure control at source and destination points. According to Colonial, the combination of intermediate pumps with source and destination pressure control affords a high power efficiency. 4.3.3 Pipeline Controllers Pipeline Controllers are usually promoted from operations personnel, and progress from operating stub lines to mainlines as their experience grows. Although there are a few Relief Controllers who can move between different areas, other Controllers are assigned to one area at a time. Because the pipeline is operating on a 24-hour basis, Controllers normally spend a few minutes together when a shift changes. In this manner, any unusual situations or abnormal conditions are discussed with the Controllers on the new shift. There is also communications with the Controller Shift Supervisor and the review of any printed information that may impact the operation. With respect to the Reedy River accident, the Line 2 Controller had initialed two memos eatiier that day related to corrosion at the Reedy River and the resulting pressure restrictions. However, during the General Physics interview, the Controller stated that on the day of the accident he thought that the situation at the Reedy River was not as serious as it actually was. There is no record of any specific conversation regarding the Reedy River situation during shift turnover that day. On March 29, 1996, shortly after the discovery of corrosion at the Reedy River, the Operations Team Leader issued a memo to restrict the suction pressure of Simpsonville 4.8 miles downstream of the Reedy River to 100 psig. Although the combination of upstream pumps and deliveries would impact the pressure gradient at the Reedy River, the memo explicitly limited the suction pressure to 100 psig. On the day of the everit, the Controller exceeded the 100 psig maximum suction pressure at Simpsonville Station for a total of 2.5 hours with pressures as high as 160 psig6. 4.4 Recording of Line Pressure 4.4.1 Pressure Data ArchivingCritical pressures and other key data elements are recorded on paper strip chart recorders at each station. Each data element represents one channel on a strip chart recorder. A transducer is required for each data element and provides the source reading for both the chart recorder and theAtlanta SCADA system. These station recorders are the official vehicle chosen by Colonial to comply with the records portion of the Federal Pipeline Safety Code, ß1 95.404a3. for recording and archiving line pressures. Colonial had previously used chart recorders with liquid color ink, which provided a way to distinguish between multiple data elements on the same chart. However, `General Physics Report Section 4.1.3 18

January 10, 1997 OPS Task Force Report Colonial Pipeline Companyliquid ink pens have a tendency to clog and sometimes require excessive maintenance. Many ofthese units have been replaced with new thermal-paper recorders. Thermal recorders have solvedthe maintenance problems with clogged ink wells. However, these recorders only print in black,making it sometimes impossible to distinguish the path of a~ individual data line among others onthe same recorder.Critical pressures are also conveyed to Atlanta through the SCADA system. Remote data iscollected every 5-8 seconds by the SCADA system. Under normal conditions, detailed data isretained for approximately 14 days, and then overwritten by new data as it occurs. Two examplesof pressure recording are described below. Only top-of-minute samples are archived for permanentrecord, which do not necessarily represent maximum value readings. When an upset conditionoccurs, either the Shift Supervisor or the Operations Team Leader initiates a special computer datafile to retain detailed data surrounding the event for subsequent analysis. The Controller ShiftSupervisor and/or the Operations Team Leader must make a judgement on the severity of theevent to decide whether or not to initiate the special data file. The decision must be made before.the data of interest is erased as noted above. Colonial's station chart recorders are intended tosatisfy the archiving requirements of federal regulations. This special data file is used for post-event analysis.4.4.2 South Baltimore, MDSouth Baltimore, MD, Line 31, has a thermal strip _______________________________chart recorder that indicated a meter pressure of -approximately 56 psig. Moments later, the chartindi‡ated a pressure spike7 to approximately 95. psig.A graphical depiction of the tabular SCADA data andthe Chart Recorder are shown in Figure 4.2.Although the SCADA System may have displayed theelevated pressure when it occurred, the spikeapparently did not occur at top-of-minute, thereby notretained in the SCADA archiving process. Theassociated SCADA pressure archived for that time ~ c~T~olw~period was 47 and 48 psig. This event was not a S. Battimore, MD, Une 31, Meter Pressurecritical situation, and did not prompt the generation of Figure 4.2a special data file for future analysis. Thisexamination confirms that the current SCADA datahandling process used by Colonial does not preserve actual pressure history. Colonial usesSCADA system pressures as an operational tool. Station chart recorders remain the formalpressure recording devices..4.4.3 Roanoke, VARoanoke, VA, Line 25, has a pressure transducer and a thermal chart recorder channel that are`scaled for 0-1,000 psig. The MOP of the segment at Roanoke is 1,305 psig. Even in considerationof the elevation profile8 of the segment, the 0-1,000 scaling does not permit the station to recordpressures that approach or exceed the segment's MOP. On one occasion, the line pressure was 7Chart Recorder from South Baltimore. MD. 03-29.96, 15:20. * The static elevation pressure head from Mitcflell to Roanoice is about 40 psig.19

O January 10. 1997 OPS Task Force Report Colonial Pipeline Companyholding at about 70 psig when a valve failed to open during a tar~k switch9. The line pressure rosesharply and went off the chart. The associated top-of-minute SCADA data indicated 1,024 psig.The South Baltimore example above discounts the accuracy of the recorded SCADA pressure atRoanoke. This event did not prompt the generation of a special data file for analysis.The thermal chart at Roanoke contains four ·hannels: temperature 1, gravity G, meter pressureM and line pressure L. Figure 4.3 is a reproduction of the actual chart paper. Figure 4.4 is aretouched image to highlight the line pressure. Circled letters have been added. The darkenedstripe at the bottom of the chart indicates the paper roll is near its end. At the time of the event thefour data trace lines crossed several times making it impossible to identify the channel going offscale. Task Force review of the SCADA data helped to corroborate that the line pressure is thetrace that went off scale, but the maximum pressure that actually occurred was not recorded and isunknown.:*:r~ :~: - -~ - ....±.. ~. py.. ~~ .Roanoke, VA, Line 25. Instrument Chart Figure 4.34.5 Operations Analysis4.5.1 Controller ReportsColonial's Controllers complete an assortment of reports based on a variety of conditions. Thosereports related to unscheduled shutdowns and/or over-pressurization are Dispatchers MalfunctionReports, Leak Reports, Unscheduled Line Shutdown Reports and Supervisor's Log. These reportsare a. subset of the total number of reports generated and/or reviewed by the Controllers. `Chart Recorder from Roarioke. VA. 07-12-96, 12:01.i s... -..-........... ;!: r~i;~-.. .....y1. ..-i.....-c.. S-a... -..~Roanoke, VA, Une 25, Instrument Chart, Retouched Figure 4.420

January 10, 1997 OPS Task Force Report * Colonial Pipeline Company Dispatchers Malfunction Failure Report includes... All equipment failures. Accidents or conditions which may have caused pressure to exceed design limits. Recording of any pressure above maximum allowable discharge pressure. Condition or failure that results in a loss of throughput. Unplanned unit starts. * Leak Report includes... Date and time of leaks. The name of the Controller on duty. Source and location of leak. Name and telephone number of person reporting the leak Batch number of product at leak site at time of notification. Chronological list of actions taken by Controller. * Unscheduled Line Shutdown Report includes... Location, date and time of shutdown. Controller and Operator on duty at the time of the event. Batch number and shipper information. Maximum pressure reached and relief valve status. Brief explanation of cause. * Supervisor's Informal Log includes... Any notable event the Shift Supervisor warrants recording. The date and time or shift of the event.4.5.2 Unscheduled ShutdownsInformation from these reports pertaining to unscheduled line shutdowns was tabulated for the sixmonth period ending August 23, 1996. This information created a representative sampling of upsetconditions. The fifty-six events that occurred during this period included: * Fifty-four unscheduled shutdowns. * One scheduling conflict that was resolved before a shutdown was necessary. * One mock drill conducted with public emergency services groups, without an actual shutdown.The Task Force determined that there were frequent coordination problems and valve failureswhich caused upset conditions, but no other common factors were identified. Table C-i inAppendix C lists all event details. The Task Force considers these events to be typical of theproblems encountered by the industry, and reflect that a majority of problems arise fromcomplications with product cuts and deliveries rather than pump stations and line segments. Faulttype has been broken into three categories: LK Leak or Possible Leak, ME Mechanical Problemor Equipment Failure, and LG Logistical Problem or Operational Adjustment. Although Colonialoperating procedures'° require the Controllers to file these reports, 26 of 90 were not completed.Those missing reports represent 28% of the total and are identified as n‡ne filed~ in Appendix C:Table C-i. The Dispatchers Malfunction Report and the Leak Report are specifically noted inColonial's control room procedures. The Unscheduled Line Shutdown Report and Supervisor'sInformal Log are not written in procedures. There is an inconsistency in the application of thesereports and it is unclear at this point, why some of the reports were not filed. to Colonial Operating Procedures Manual. Section 2.2. 21

January 10. 1997 OPS Task Force Report Colonial Pipeline CompanyThe Task Force identified eight events as those where over-pressure protection may have beeninitiated or where over-pressure may have occurred. Table 4.2, Unscheduled Shutdowns withPossible Over-Pressure, briefly describes each event, who discovered it and the fault category. Anexamination of these events provided a measure of the systems and procedures in place to protectagainst excessive pressures. Table 4.2: Unscheduled Shutdowns with Possible Over-PressureDayDateTime LineLocationDiscovered byFault TypeDeSCflPtiQnOver-Pies?ActualpsigMOP"psig Wed.02-21-96 13:52 Line 20Chattanooga. TNOperator ~MechanicalOver Pressure, Trap Leaking:Pump started against a closed valve. Trapcould not withstand elevated pressure andleaked8091440 Fri.03-29-96 17:48 Line 31S.Baltimore, MDStation Logic. Logistics ~High Tank Alarm:Delivery Tank went into maximum fill alarm,which automatically dosed delivery line valve383~ Wed.04-29-96 03:45Line 27Yorktown, VA .ControllerMechanicalValve Failure:Block valve failed to open when pressureincreased8251181 Sun.06-23-96 17:08Line 18Knoxville. TNStation LogicLogisticsTank Alarm:Shipper Tank went into max tank alarm,automaticallyclosedvalve375~ Wed.06-26-96 22:54 Line 2Reedy River, SCOperatorLeakRupture:Rupture on mainline from over preuunzationOver-Pies 412 374 Sat.06-29-96 22:24Line 27Yorktown, VAStation LogicMechanicalHigh Pressure Trip: .Hydraulic equipment failure, valve dosed9511181 Wed.07-10-96 20:03 Line 32Curtis Bay, MDStation LogicLogisticsMax Tank Alarm:High Tank alarm during delivery.automatically closed tank valve3751265 Fri.07-12-96 12:00Line 25Roanoke, VA ``OperatorLogisticsManifold Blockage:Manifold switch direoted flow to tank withclosed valveFootnote'2 1000+ 1440Although this table highlights those events that were likely to have elevated pressures, all 56 eventswere examinet. The Task Force extracted this information from the analysis: * The majority of unscheduled shutdowns occur on stubs or delivery lines because of equipment failures or mis-communications with delivery personnel or shippers. * Equipment problems account for about 48% of unscheduled shutdowns. * Logistics problems and coordination account for about 38% of unscheduled shutdowns. * Leaks or possible leaks account for about 12% of unscheduled shutdown& * There was only I occasion where a line was shut down on suspicion of a leak 2%. * Upset conditions occur on any day of the week, at any hour. MOP as stated in Colonial's System Operating Pressure Limits ManuaL `2According to Colonial, the pressure chart on the Lynchburg end of segment did not exceed MOP. The Lynthburg chartrecorder data was not available at the time the Task Force Report was written. 22

January 10, 1997 OPS Task Force Report______ Colonial Pipeline Company * The Controllers 59% are more likely to encounter upset conditions and initiate an unscheduled shutdown than the field Operators 21%. * Automatic safety equipment accounts for about 14% of unscheduled shutdowns. * Colonial can expect to have an upset Condition cause an unscheduled shutdown somewhere on the system, probably on stubs or delivery lines, on average every 3 or 4 days.Unscheduled shutdown reports provide important information regarding the safe operation of thepipelines. However, no one in the current Colonial organization has been assigned to reviewequipment malfunctions or unscheduled shutdowns to reveal systemic trends.4.5.3 Volume BalanceIn addition to a number of other routine chores, the Controllers also manually calculate line volumebalance. The Controllers tally metered volumes into and out of their portion of the system on anhourly basis. These volume measurements are at source and destination points only. Greensborois a source/termination point for the mainlines, but there are no other mid-stream meters to improvethe accuracy of these calculations. The Controllers review the figures, but there are no writtenguides or procedures to prejudge over and short values, or to determine the amount of deviationover time in which a leak may be suspected. Subsequent analysis of the figures is routinelyperformed by analysts as a maintenance and accounting task. The Controllers do not use theresults of their analysis as an operational tool.4.6 Pressure Safety.Systems and Pressure Alarms4.6.1 Pressure Control and Monitoring EquipmentColonial designs their pressure control systems to not exceed federally regulated MOP. If,however, upstream bottle-necking or moderated throughput requirements do not require full MOP, alower pressure is usually implemented. There are six mechanisms that directly relate to pressurecontrol and monitoring. Table 4.3 summarizes the six mechanisms, including their alarmcharacteristics. 1. Station Control Valves are mainly used for over-pressure protection and are designed to throttle at, or just below, pressure limitations. Control valves are manually set and are not remotely controlled. These valves will begin to throttle if they sense that station discharge pressure approaching the designed control point, which may be less than MOP. 2. High Line Shutdown Pressure Safety Switches are used to trip pumps when a station discharge pressure exceeds a threshold point. The pressure switches are calibrated to trip at 5% above the station discharge control point and are calibrated to the larger of either 1% of the set point or one psig. The manufacturers' data for 21 of these switches indicate that the pressure switches may have a dead-band as large as 67.5 psig. Dead-band refers to the difference between the trip and reset value of these switches. Review of calibration data records indicate a typical dead band ranges from 20 to 60 psig. The design of the control system in use at the pump stations will trip the pumps on high line pressure at three second intervals, beginning with the smallest pump on line. The purpose of the interval is to allow the pressure switch to reset, preventing additional pumps from also tripping on a high line pressure, should the first one or several pumps that have already tripped reduce the 23

January 10, 1997 OPS Task Force Report______ Colonial Pipeline Conipany pressure sufficiently13. A pressure wave will be generated when each pump is tripped. The reduction of unnecessary pump trips lessens the risk of pipeline failures. The development, compounding, and dissipation of pressure waves were critical to the Reedy River accident14. The investigation of the Reedy River accident has resulted in an OPS directed examination15 of the dead-bands in these switches, as noted in Section 3 of this Report. 3. Mainline Software Pressure Alarms are included in the SCADA System for use by the Atlanta Controller. These alarms are driven from the same field transducer that feed the station chart recorders. These alarms are usually the Controller's first indication of an impending or over-pressure situation. The Controller receives this alarm if a station goes on discharge control, as noted in the stationcontrol valves paragraph above, and again if high line shutdown pressure is exceeded. The threshold pressure setting for these alarms is the same as the high line shutdown pressure safety switches. However, since the mainline software pressure alarm is driven by the field pressure transducer, these two mechanisms may not necessarily alarm at exactly the same pressure. 4. Mainline Block Valve Byoass Fixtures are designed to transfer pressure around a station, towards a downstream location with a relief valve installation. These bypass valves are used to bypass pressure transients. The pressure sethngs are designed to insure segment pressures do not exceed 10% above MOP16. The fixtures directly impact segment MOP, but the actual bypass pressure settings are indirectly related to MOP~ They will generate an alarm to the Controller. - 5. Relief Valves are designed to open at 10% above MOP, or at a lower pressure just above operating requirements. Relief valves are rarely tripped open and are designed as a pressure safety device, not a pressure control tool. The valves protect the pipeline from transients. Relief valves are located at selected Colonial's facilities. Relief valve design parameters are incorporated in Colonial's transient model. Relief valve specifications are input to the model which determines if the.subject segment is protected from over-pressure. Segments achieve primary pressure protection from pump station controls as noted above. A relief valve serves to protect the segment from transients created by upset conditions. They relieve product into a breakout tank and will reset-when the associated pressure drops below the trigger point. 6. StnD Chart Recorders monitor system pressures and other critical data elements at stations and delivery facilities. These recorders do not trigger alarms, but are the permanent record of system pressures and other data. `3General Physics Report. Section 2.2.1 `4General Physics Report. Section 4.2.2 `~ Hazardous Facility Order 26503-H; July 31. 1996 - ` ß195.406b permits a pipeline to exceed MOP by 10% during surges or other variations. 24

O January10, 1997 OPS Task Force Report Colonial Pipeline Company Table 4.3: Pressure Control and Monitoring EquipmentDeviceActionPressure SettingAlarmControl Valve:Locally monitor the associatedpressure and will throttle pressureabove the set point `. `Throttle station dischargeMOP, or lower *No AlarmHigh Line Shutdown Switch:Locally monitor the stationdischarge pressure. They arelinked into the station controlpanels and will tflp a sequence ofpump units smallest first asnoted abovePump trip/s105% of MOP, or lower . .Pump Off Alarmto Controller ~Mainline Software Alarm:Created within the SCADA Systemby monitoring an associatedpressure transducer in the fieldAlert Controller105% of MOP, or lowerHigh Pressure Alarm &High Upstream PressureAlarm to ControllerMainline Block ValveBypass Fixture:Transfer pressure across a station,relieves pressure to downstreamsegment, towards a relief valveRelieves pressure acrossa station*Indirectly related to MOP,Protects segment to 110%of MOP, or lowerMLBV Bypass Alarmto ControllerRelief Valve:Locally monitor the associatedpressure and will relieve pressureabove the set pointRelieve pressure to tank110% of MOP, or lower ~Relief Valve Alarmto ControllerStrip Chart Recorders:Will locally record high pressuresPressure record OnlyNoneNo Alarm4.6.2 Mitchell-Roanoke Pressure ControlBy example in Table 4.4, Line 25 Mitchell to Roanoke, VA has an intermediate booster pumpstation at Lynchburg. The booster pump at Lynchburg breaks Line 25 into two segments. Thesegment between Mitchell and Lynchburg is controlled at MOP, with a shutdown at 5% above MOP.The segment between Lynchburg and Roanoke is controlled at about 10% below MOP, withshutdown at 5% below MOP. The current operating plan does not utilize full MOP in theLynchburg-Roanoke segment because the upstream Mitchell-Lynchburg segment creates abottleneck. If the operating pressure of an individual line segment does not require or cannotachieve full MOP, Colonial will restrict the operating pressure below MOP as a safety measure.Details of Colonial's pressure limitations are contained in Colonial's System Operating PressureLimits Manual Red Book. Examples of pages in the Red Book are Tables C-2 and C-3 ofAppendix C. Table 4.4: Mitchell-Lynchburg-Roanoke Pressure Settings psigStation ,MOPDischarge ControlHigh Line Shutdow~jMitchell - Lynchburg psig130513051370Lynchburg- Roanoke psig14401302136725

O January 10, 1997 OPS Task Force Report Colonial Pipeline Company4.6.3 SCADA AlarmsSCADA alarms are generated in the computer system to alert the Controllers of critical information.These alarms are~divided into three groups based on the severity of the condition they represent.Alarms from different groups are displayed in different colors in the alarm window and on the alarmsummary screen. They are announced by a ~different audio sound for each group17.The control logic at pump stations includes protective equipment to insure pumps and motors arebeing started and operated correctly. Vibration, motor bearing temperature and hydraulic fluidpressure are a few of the sensor points that impact control logic. This data is critical to stationmaintenance, but is not of individual interest to the Controllers in Atlanta. As a result, thisinformation is not individually conveyed to the Controllers by SCADA. Rather, this data is combinedas a single mechanical group alarm. When Controllers encounter problems with pump stationequipment, they contact maintenance personnel for their further examination.Although the SCADA system has the ability to generate high and low suction pressure alarms, thisfeature was not used at Colonial prior to the Reedy River accident~. Colonial had issued aninternal directive to limit the suction pressure at Simpsonville station to 100 psig so that the linepressure at the site of the Reedy River corrosion would be limited to 374 psig. A review of~heoperating pressure data showed that during the 15 day period preceding the event, Controllersroutinely violated the 100 psig directive at Simpsonville Station. Operation was conducted abovethe 100 psig limit for long periods of time, one of which was 10 hours, 38 minutes and at pressuresas high as 175 psig. Overall, the periods of operation above 100 psig account for morethan 10%of the 15 day interval'9. A high suction pressure SCADA alarm has now been established forSimpsonville Station, but there is no system-wide plan to adopt high suction pressure alarms.Colonial has incorporated the "dependent device" alarm feature of the SCADA System, where acommanded change will temporally inhibit a status change alarm. For example, if a pump iscommanded to start or stop, no alarm will be generated. However, if a pump starts or stops withoutbeing commanded to do so by a Controller, an alarm will be generated. This feature helps tomoderate the number of alarms generated. The SCADA system does not provide "conditionalalarming". Conditional alarming would dynamically adjust the set-point of an alarm value, or inhibitan alarm based on the condition of one or several other status points being monitored elsewhere bythe SCADA system.The SCADA system has not been configured to include alarms that have been specifically labeledas a safety action. The fact that a pump has gone off-line will be alarmed to the Controller, but thecause of the trip is not conveyed. If a relief valve alarm is reported, the Controller can deduce asafety action since relief valves are triggered exclusively by excessive line pressure. The SCADAsystem can be configured for multiple high and low alarms for any analog point, including suctionand discharge pressures. Colonial limits the number of configured alarm points so as not tooverwhelm the Controllers with non-critical information. In Spite of Colonial's efforts to limitController alarms, the Line 2 Controller encountered 79 alarms during the first ten minutes of theReedy River accident20. `~ General Physics Report, Section 21 "High Su~ion Alarm at Simpsonville Station. 100 psig. "General Physics Report. Section 2.5.~ 20ra Physics Report. Section 4.2.2 26

January 10, 1997 OPS Task Force Report Colonial Pipeline Company Although the SCADA System can be configured to provide rate of change ROC alarming, Coloniaj has chosen not to apply ROC alarms. ROC pressure alarms are used to detect sudden drops in pressure. Such a change within the authorized operating range would not generate a conventional high or low alarm. However, a dramatic change random example: 100 psig change in 3 seconds would generate a ROC alarm. Colonial belieyes the operating dynamics of their pipeline are too broad and that this would subject the Controflers to too many meaningless alarms. They have not performed a formal study to determine if the burden of addition alarms would be offset by the value of ROC alarms. 4.7 Tank Level Alarms Colonial has two related, but different, procedures for the handling of Tank Level Alarms. Only one of the procedures is applied at any one location. The application of the procedures follow the separation of Colonial's former East-West organization. Tank operations and level alarm settings are shown in Table 4.5. There is an operational inconsistency on the upper limit of fill. Those locations to the west of Greensboro, NC will terminate the delivery prior to maximum fill level alarm. Those locations to the east will terminate the delivery when maximum fill level alarm is achieved. In the reformed organization, there may be delivery locations within the same district that have different tank fill level alarm procedures. Table 4.5: Tank Alarm OperationsFeature vs. LocationsWest: Houston, 1X - Charlotte, NCEast Greensboro, NC - Unden, NJHigh level alarmAll tanks set to 44 feet5 mm. before max. fill, at mix flow rateFill operation between High & MaxOnly when tank is physically monitoredOnly when tank i physically monitoredUpper limit of fillTerminate before max. fill alarm occursTerminate when max. fill alarmMaximum fill alarmAll tanks set to 47 feet occursAll tanks set to 47 feetOperation above max. fillProhibitedProhibited4.8 SCADA and Operations Support Systems4.8.1 SCADA SystemColonial's centralized SCADA system is housed and operated in Atlanta. This system is made of acombination of computer equipment, related software, and telecommunications links to fieldlocations equipped with remote telemetry equipment. Six Controllers use this system to monitorand control the movement of products from injection points through booster stations. FieldOperators control most delivery facilities.Colonial instaHed a Valmet2' SCADA system employing Valmet software and mainly DigitalEquipment Corporation hardware. The system was installed in October 1991 and commissioned inJanuary 1992. It was the first of a new generation of SCADA systems produced by Valmet,featuring client-server open systems on a Unix-Risk architecture. At that time, the Canadian GasAuthority was the only other user of the product. Today, Colonial is in the top quarter of Valmet 21VaLmst. Inc. is a mtemational company that provides computsr~sd SCACA Systemab 27

O January 10. 1997 OPS Task Force Report Colonial Pipeline Company users, but is not the largest customer. Colonial is one of twelve companies, throughout the world,that continue to use the original 4.0 release of the software with numerous modifications. Most SCADA users stay with the commissioned version of the software for an extended time period, anddelay interim upgrades until the list of new features justifies the resources and logistics required toimplement the upgrade. Colonial declined to adopt any of the three major release/upgrades of theproduct. The most current version of the product is 5.22, released in January 1995. Version 6.0 will be released in the next few months. While the Valmet system used by Colonial Pipeline is not the latest software version available, the system is comparable to typical systems currently used in the industry. Colonial is now upgrading both the hardware and software of the Valmet system. This project was~ planned for implementation at the end of 1996. Colonial recognizes the limitations of its 1990 vintage computer hardware, and will be installing new equipment with eight times the processing power. In addition to new hardware platforms, the current project will include the implementation ofRelease 5.22 the most prevalent of Valmet's installed systems. Major components of this release include: Batch Tracking, Metering, Ticketing and Computational Pipeline Monitoring sub-systems. Colonial plans to adopt certain portions of these new features in the near future, but does not plan to add pump station pressure alarms on a system-wide basis. The current SCADA system provides each of the Controllers a 24.hour, continual view of key operational data from stations along the system. No data is collected between stations along thepipeline. Data is collected by sensors installed at each pump station and delivery facility. This data includes: * Pump Suction, Case, and Discharge Pressures * Line Pressure for facilities without pumps * Product Temperature * Product Analyzers gravity - flash * Pig Signals * Meters at injection and delivery points only * Pump, Valve and Equipment Status The data at each station is collected by an RTU which converts the data format for transmission. A contract telecommunications provider routes the data via satellite for delivery to Atlanta on highspeed telephone circuits. The Controllers are alerted by the SCADA system when primary communications with a station is disrupted. The system also includes dial-up modems to provide backup communication in the event that satellite communication is disrupted. According toColonial, they have intentionally designed this back-up to be~ manually enabled, to avoid connections that are not particularly critical to operations at that point in time. When necessary, the Controller must manually enable dial back-up on a site-by-site basis. Once the data is received in Atlanta, it is processed by a primary computer which functions as the data format and archive processor. There is also a second computer installed as a backup shouldthe primary computer fail or be off-line for maintenance. From the primary computer, the data is passed to the appropriate Controller work station. The system provides eight consoles in the control room. Currently, six consoles are used by Controllers to operate the various pipelinesegment, one is used by the Shift Supervisor and one is reserved for special operations. Each console has six computer monitors for display of system information. Each console is divided electronically into nght and left sides, each side having a processing unit. This architecture 28

January 10, 1997 OPS Task Force Report Colonial Pipeline Compa~yIn the following Sections, we will discuss Colonial's accident history and some of the actions OPS has taken as a result of there investigations. Three open compliance actions and an earlier OPS Task Force Report will be discussed in more detail. 3.3.1 Colonial's Accident HistorySince 1968, federal regulations required HLP operators to submit reports on accidents meeting certain minimum requirements. The reporting requirements in ß195.50 have changed since originally published4. The current regulations require HLP operators to submit written accident reports to the OPS meeting the following conditions5: a. Fire or explosion not intentionally set by the operator, b~ Loss of 50 bbl. or more, c. Escape of 5 barrels per day of HVL, d. Death, e. Bodily harm, or f. Property damage exceeding $ 50,000. This section will briefly discuss Colonial's accident history and reactions from the OPS as a result of some of these accidents. Colonial has reported 194 accidents to OPS since 19686. The recent accident at the ReedyRiver near Simpsonville, SC is the largest spill reported by Colonial in their 33 year history. It is also the eighth largest spill reported by HLP operators. In fact, Colonial has reported three of the twenty largest HLP spills7.Records show Colonial has experienced a failure accident rate greater than most other HLP operators in the United States. In a sampling of 17 HLP operators, Colonial's accident rate is among the top three. Of the 17 operators selected, four have a majority of pipe with a diametertowall thickness D/t ratio greater than 70; three are among the top eight in accident rates. It is important to note that large diameter, high D/t ratio and high yield strength pipe has been found to be susceptible to fatigue cracking due to faulty railroad shipment of pipe joints. Based on a 1962 study conducted by Battelle, it wasconcluded that susceptibility to fatigue cracking during rail shipment increases for pipe with large DIt ratios because both static stresses ~ Particularty Amdt. 195-45 56 FR 26925; June 12. 1991 and Amdt. 195-52 59 FR 33396; June 28, 1994. ~ ß195.50 paraphrased. 6 See Appendix B: Table 8-4. ~ See Appendix B; Table 8-5. ~ See Appendix B: Table B-6. 7

January 10. 1997 OPS Task Force Report Colon~aI Pipeline Company provides redundancy at each work station~. 4.8.2 SCADA Display Screens Valmet provided standard SCADA display screens that are oriented towards system set-up and maintenance. The most commonly used screens by the controllers are those developed to Colonial specifications. The controllers individually determine which SCADA screens are displayed during their shift. They can display any of approximately 100 different screens that can be used to monitor and control the pipeline. The system duplicates some of the control views and methodologies used by Colonial in former control systems23. The General Physics Report provides a detailed description of the screens typically used by the controllers. These screens include: 1. The StnD Chart screen graphically displays approximately 2 hours of pressure data for each station. It is designed to look similar to mechanical strip chart recorders installed at pump stations and former control locations. A sample display is in Appendix C: Figure C-4. 2. The Real Time Nomogram RTN graphically displays system pressures relative, to the elevation profile. Many liquid operators do not provide a nomograph to their controllers. Limited access to real-time field data and the sizeable load on computer systems is a technical limitation that many operators have not yet overcome. Colonial uses an interface from the SCADA data to drive the RTN, but even Colonial's system uses a fixed set of product characteristics rather than real-time batch characteristics. The model uses the suction and discharge pressures from each pump station, as well as the line pressures from delivery facilities. It calculates the pressure along the pipeline between the stations where the pressure is not monitored. All these factors limit the accuracy of the portrayed information. In addition, during the rare occasion that slack line occurs, the model becomes unstable. As a result, some Controllers do not use this screen even though it provides a clear indication of current pressure waves and system pressures nearly all the time. A sample display is in Appendix C: Figure C-5. 3. The Executive Summary screen displays key system parameters in a tabular format.. 4. The Button Box screen is used for operating remote station controls. The button box screen resembles an actual button box that was formerly used by Colonial to operate the pumps before the installation of the SCADA system. 5. The Alarm Window screen is used to display unacknowledged alarms. Alarms appear in the Alarm Window and the Alarm Summary. Once the alarm is acknowledged by the Controller; the alarm is automatically deleted from the Alarm Window. 6. The Alarm Summary screen displays all current alarms. The alarm is cleared from the Alarm Summary screen once the parameter is no longer in an alarmed status. Commonly used screens, such as those noted above, do indicate if communications to that stationis lost. However, those same screens do not indicate data that is in an alarmed condition nor if the individual data reading is stale24. Yellow and green represent pump status on several of these ~ General Physics Report. Section 2.1 ~ General Physics Report. Section 2.1 ~ A stale data reading is one that has not been updated. 29

O January 10, 1997 OPS Task Force Report Colonial Pipeline Company screens. These colors are very close in the color spectrum and can sometimes be difficult to differentiate. 4.9 Revision and Change Control for Line Pressures 4.9.1 Maximum Operating Pressure When the mechanical design of the original pipeline system was constructed in the field, a set of as-built drawings were created. These drawings included information regarding pipe specifications in association with mileage and elevation profiles. This same process was followed during the construction of the loop pipeline in the late 1970's and today as relocations and system expansions occur. During the engineering of the original pipeline segments, this base information was used for pipe strength~ calculations and now also incorporates ß195.106 to establish the internal design pressure of the pipe. The hydrostatic test record is then included in the process to establish theMOP for the given line segment. Any known c‡nstraints~ on the line segment may impose areduction in the original or current MOP. The combination of design pressure, elevation profile,hydrostatic test and known constraints result in the establishment, or revision, of the realized MOPacross a line segment.Colonial's hydraulic, design targets station suction pressures to be 30 psig. A calculation back overthe upstream portion of the line segment will identify the critical MOP point. Based on a number offactors, that point may be anywhere along the segment: lowest elevation, thinnest pipe or may be atthe discharge of the pump station. This process bounds the steady-state operating mode of thesegment, but does not address transient conditions. Colonial uses an in-house computer programto model a variety of conditions, such as line blockage, station power failure and combinations ofassociated events to identify any bounds that may further limit the operating pressures below thesteady-state level. According to Colonial, the number of possible outages and failures programmedin the computer is limited but targeted to the most critical scenarios. According to Colonial, theresults of these calculations provide data to determine the maximum line pressure at pump stationsand the necessary pressure set points for relief valves. In regard to the Reedy River accident, themodel did not include a scenario where two pumps tripped simultaneously at the same station; nordid it generally account for the large dead-band of the high line pressure safety switches. As aresult, the OPS issued HFO 26503-H on July 31, 1996, that ordered Colonial to modify the in-housetransient model to account for large dead-bands on a system-wide basis. Accounting for largedead-bands would also address nearly simultaneous pump trips.4.9.2 Set Point Change ProcessSince the transient model is impacted by design changes and pipe restrictions within eachsegment, the source data for each segment in the transient model must occasionally be adjusted.There is no audit or report function within the transient model to detail the segment parameters.The program operator must account for segment parameters through a manual process andmanually log the defining parameters to an archive file if deemed ne‡essary. The engineer thatcurrently conducts pressure and surge analysis has been in that position since 1985. As linesegments were subjected to change, a re-analysis has been performed. Since 1985, Colonial hasrecorded. segment parameters to file as each analysis was performed. Those segments that havenot been subjected to change since 1985 do not have segment parameters specifically recorded to ~ ASME B31.4 . ~` Severe corrosion, dents, gouges, cracks, or regulatory restriction. 30

O January 10, 1997 OPS Task Force Report Colonial Pipeline Company an active file. Over the period between 1985-1996, It is estimated that most mainline segments have been subjected to a re-analysis, thereby having an active file. Only a small number of the stub lines have been re-analyzed. Although there is no unified written guide or procedure detailing the steps to determine or re- establish maximum pressures, interviews with several Colonial personnel has resulted in this description. Colonial follows this sequence of actions when the operating pressure of a potentially weakened pipe needs to be determined. Starting at Step 4, Colonial uses this same sequence if changed operating requirements need to be implemented. 1. The discover,' of a subject condition triggers the process. 2. Physical measurement and assessment of the pipe. 3. A calculation or reference table is used to determine any rÛquired pressure reductions at that point. 4. Calculation to re-assess maximum station discharge pressures and relief valve settings. 5. Summarization of pressure settings are recommended. 6. Resulting station pressure and/or relief settings reviewed/authorized by senior management. 7. Approved figures are distributed by Operations Team Leader to Controllers and Field Operations. 8. Changes are implemented into field operations and SCADA System. 9. Field and computer support personnel notify Controllers when changes are complete. 10. Changes are incorporated into master System Operating Pressure Limits ManuaL 11. Manual update memo is distributed to all Red Book Manual holders.The System Operating Pressure Limits Manual Red Book includes a memo from the Vice President of Operations which outlines the requirements for the review and approval of set-points. The discovery of the corrosion on Line 2 at the Reedy River triggered the steps shown above, and` resulted in a temporary change to the Red Book restricting the suction pressure at the Simpsonville Station to 100 psig until the line could be repaired see Table 4.6. Colonial also ran several simulations using the transient flow model. The purpose of these simulations was to establish operating limits and set-points to ensure that a 374 psig limit at the Reedy River would not beI, exceeded. Based on the simulations, the following limits were recommended for the Simpsonville Station: 1 a 100 psig maximum suction pressure, 2 a maximum of 5,000 horsepower running, and 3 temporarily lower the mainline block valve pressure switch from 290 psig to 270 psig. On April 4,1996, a temporary change to the Red Book was issued to incorporate these changes. This temporary change alsorequested that a technician make this equipment adjustment as soon as possible and notify the. Shift Supervisor when it was accomplished. It also stated "Confrotlersshould pay special attention to this area of the pipeline and take immediate action to minimize pressure surges in this area.'27In response to a request from Colonial operations, additional simulations were run to determine if operation could be conducted at a flow rate of 34,000 bph. Based on these simulations, the following additional limits were recommended on April 9, 1996: 1 reset the mainline block valve pressure bypass switch at Gaffney Station to 350 psig, and 2 reset the mainline relief pressure atSpartanburg Station to 390 psig. According to Colonial, the desired impact on segment pressures will. not be achieved until all thesettings have been changed. They assert that although all required changes will not necessarily be executed simultaneously, the interim operating pressures will not exceed authorized MOP's. 27General Physics, Section 2.5 31

O January 10, 1997 OPS Task Force Report Colonial Pipeline Company 4.10 Reedy River Accident near Simpsonville, SC On May 7, 1996, the requirement to limit Simpsonville Station to no more than 5,000 horsepower was lined out of the temporary order by the Controller Shift Supervisor with a note that read "Disregard... 517196. Based on discussions with the engineer who ran the simulations and made the recommendations on the set-point limits,~operating Simpsonville station at more than 5,000 horsepower was not analyzed and was made without his knowledge. At the time of the Reedy River accident, Simpsonville Station was operating at 7,000 horsepower. At the time of the accident the highest suction pressure recorded at Simpsonville station was 325 psig. The calculated failure pressure at the Reedy River, due to the pressure gradient, was 422 psig28. A summary of the pressure settings pertaining to Colonial's reaction to the Reedy River corrosion and accident are shown in Table 4.6. Table 4.6: Review of Pressure Set-Point Changes pnor to Reedy River AccidentParameter I Date.*> refers to changeMarch 29Limits, afterdiscovery ofCorrosion April 4Reset Limits SecondAdjustment April 9Reset Limits ThirdAdjustment May 7Reset Limits FourthAdjustmentJune26Actuals,at time ofFailureSimpsonville Suction psig100 limit100 limit100 limit100 limit325Simpsonville MLVB Bypass psig290290 ~ 270270270270Simpsonville Horsepower hpNo restrict v 5000Restrict to 5000Restrict to 5000 ` NoRestriction7Æ~Reedy River Pressure psigno limit374 limit374 limit374 limit422~'Gaffney MLBV Bypass psig396396396 -~ 350350350Spartanburg Relief Valve psig420420420 ~ 390390 4.11 Murtreesboro, TN Accident Colonial uses a standard valve design for the majority of their pump stations. As Figure 4.5 shows, each standard pump station has three critical hydraulically H operated valves. The Controller usually operates the valve between the Suction and discharge of the station to ~ H H perform a mainline block. One of the station pressure 4 N1 M H . transmitters PT is located at the suction side of the M SUC H dlSCM station that can also be used to monitor the upstream line Standard Valve Design pressure. Manually M operated maintenance valves Figure 4.5 are located at the perimeter of the station which are normally !ocked in the open position and used for* maintenance activities. OPS inquiries into the accident revealed that Murfreesboro is one of about four stations that have an alternate design as shown in Figure 4.6. The significant difference is that a manual valve is ~ Estimate calculated by General Physics. Section 5.1. Based on pressure gradient analysis. 2 Estimate calculated by General Physics, Section 5.1. Based on pressure gradient analysis. 32

January 10:1997 OPS Task Force Report Colonial Pipeline Company`ocated between the suction and discharge of the station ____________________________pump equipment; and a hydraulically operated valve is atthe far end of the station inlet. This inconsistency mayhave been a contributing factor to the accident. Inaddition, Colonial has made changes to the SCADAdisplays for Murfreesboro to enhance the Cohtroller'sability to monitor the station.Over-pressure protection on the line segment did notrelieve excessive pressures. The pressure safetyequipment at Coalmont and Murfreesboro wereapparently not designed and/or calibrated properly. None of the mainline block valve relief settingsfor stub lines were included in the System Operating Pressure Limits Manual and are the onlycritical pressure settings not included in the manual.sucMurfreesboro Valve Configuration Figure 4.633

January 10. 1997 OPS Task Force Report Colonial Pipeline Company 5.0 Maintenance Report 5.1 Introduction A primary focus of the Task Force was to review, evaluate and determine the effectiveness of Colonial's maintenance program. The Task Force began its review by studying the Colonial Maintenance Manuals in Houston and interviewing headquarters HQ personnel in Atlanta. Then four district offices were visited, in addition to randomly selected pump and delivery stations. While in the field, district office and station personnel were interviewed, selected records were reviewed and a "walk through~ inspection of these facilities were conducted. Staffing levels and maintenance fund allocations were also assessed to determine if changes in these areas could have contributed to accidents. 5.2 Organization The Colonial system is divided into four operating districts:. Gulf Coast, Southeast, Mid-Atlantic and Northeast, which are led by District Leaders. Each district is further divided into two groups: Operations and Projects. Operations units are headed by Operations Managers OM. Each OM is responsible for the operations and maintenance of the pump stations, tank farms, delivery facilities arid mainline valves assigned to that unit. Maintenance is performed by personnel that fall into four classifications - Senior Operators, Operators, Utilitity Men and Technicians. Each Project Group is led by the District Project Leader and is staffed by Project Managers and Project.lnspectors. The Project Managers are responsible for the execution of the larger maintenance and capital projects at the pump stations and for all other projects on the pipelines. Typically, this work is contracted and overseen by the Project Managers and Inspectors. Pipeline maintenance work includes: right-of-way mowing, marker maintenance, external corrosion control cathodic protection surveys, facility maintenance, internal pipeline inspections and remediations. 5~2.1 Stffing Personnel from two key teams, Operations and Engineering Services Eng. Svcs., are the~ most involved in the operation and maintenance of the pipeline and its facilities. Operations teammembers are the actual hands-on" personnel that are assigned to the four districts. They operate and maintain the pipeline. Technical support for the operation and maintenance of the pipeline is provided by the Engineering Services Team at headquarters. Re-engineering affected the staffing levels of Engineering Services but not Operations. The authorized employees for the years 1994 and 1996 for these Teams are shown in Table 5.1.

January 10, 1997 OPS Task Force Report Colonial Pipeline Company Table 5.1: StafflngTeam19941996Operations487485Engineering Services6039Totals547524These staffing totals give an indication of how Colonial operates and maintains the pipelinetoday. Field personnel now have more responsibility and are more accountable for theoperations and maintenance of the facilities. The Task Force believes Engineering Services willprovide less direction than they did prior to re-engineering. At the reduced staffing level,Engineering Services is more specialized and can only provide critical, technical input toOperations and the Project Groups.5.2.2 ExpendituresAn unaudited summary of yeaily expenditures for 1986 through 1996 was provided by Colonial.The expenditures for a few selected years that reflect the growth of maintenance allocations areshown in Table 5.2. Table 5.2: Pipeline Maintenance unaudited Expenditures Not adjusted for inflation - thousand dollars19861988199019921994Contract Maintenance Pipeline$3,096$12,775$17,171$17,074$16,039Station & Delivery Facilities2,2993,1585,72510,29318,734Tanks3,4363,2346,41416,68014,613Maintenance Material3,4992,7114,0976,2644,373Total Expense$12,330$21,878$33,407$50,311$53,759As shown in Table 5.2, the expenditures have increased yearty and have leveled atdisbursements of approximately $50 million/year from 1992 to the present time.5.3 Maintenance ProgramMost of the required maintenance on pipeline facilities is identified in Colonial's D.O.T.Reference Guide Guide. Within this guide are forms that must be completed to certify that thework is being performed. One of the most important forms in the Guide is the Critical EquipmentMaintenance Schedule, Form 3308. 35

O January 10, 1997 OPS Tas1~ Force Report Colonial Pipeline CompanyForm 3308 lists the procedure numbers in the Preventive Maintenance PM Manual that shouldbe used to perform the maintenance on that particular equipment. It is important that the listing`in Form 3308 and the contents of the PM manual be identical but several items were not. Forexample, Form 3308 lists the maintenance procedure for the Pressure Switches as maintenanceProcedure Bulletin Number 16 while the PM Manual Table of Contents lists the procedure as MP14. Form 3308 is also used to schedule maintenance at the pump stations and is usuallyprominently displayed there where everyone can track the work as it progresses. However,those that were observed during our visits to several field locations were different from the formincluded in the Reference Guide. Copies of the Table of Contents from the PreventiveMaintenance Manual and the D.O.T. Reference Guide are included in Appendix D: D-1 and D-2.In addition to this Critical Equipment listing, the Reference Guide is also used to list themaintenance work mandated by the DOT, 49 CFR Part 195. Other maintenance required byColonial is identified in the Maintenance and the Tank Maintenance Manuals. The last twomanuals consist of standards, codes, etc. that Colonial considers mandatory.The review and revision of the maintenance procedures in the manuals are the responsibilitiesof the Coordination Teams for the specific equipment or discipline involved. A partial listing ofthe different teams are: Quality, Corrosion, Tank and Preventive Maintenance Teams. Typicallythe teams consist of members from the four districts, Engineering Services and any other teamthat is affected by procedures developed by the teams.As noted earlier, Form 3308 is probably the most important instrument regarding Colonial policyon. maintenance since it serves as Colonial's maintenance plan. Scheduling of maintenance isbased on whether, as determined by Colonial, the particular task must be performed once ayear, twice a year or quarterly. Having this information, the individual technician then schedulesand performs this work within the specified period. All of the critical equipment, such as, pumps,instrumentation, tanks, motors, speed controls, relief valves and valve operators are theresponsibility of the Operations Manager. Maintenance for the mainline valves on the right-of-way is also assigned to the Operations Manager.Before Colonial's reorganization in 1994, the completed PM forms were reviewed for actualperformance by Engineering Services in Atlanta. After the analysis was completed, it wastransmitted to senior management and eventually to the field. The analysis consisted ofidentifying the number of procedures completed or not completed by station. For example, in1992, Colonial's analysis showed that 2649 of 3177 maintenance, procedures on criticalequipment were completed.During the field interviews several Operations Managers were surprised to learn thatEngineering Services was not evaluating the forms since they are still `being sent to HQ. Theanalysis is no longer being performed by Engineering Services, although it is still required by theGuide~Most of the maintenance on the pipeline or on the pipeline right-of-ways is performed under thedirection of the Project Managers. The exceptions are the maintenance on the mainline valvesMLV's and relief valves located in fenced enclosures on the right-of-way. This work is 36 `

O January 10, 1997 OPS Task Force Report Colonial Pipebne Companyperformed by Operations. Pipeline right-of-way maintenance is contracted out and overseen byinspectors under the direct supervision of the Project Managers. Unlike the pump stations, thereis no formal plan or schedule for this work. since much of this work is seasonal and weatherdependent.5.3.1 Corrosion ControlCorrosion mitigation for Colonial's facilities is accomplished by three methods - a systemconsisting of an external coating and cathodic protection for buried or submerged piping,external protectivecoatings for above ground facilities and inhibitors for the internal surfaces ofthe pipe. Cleaning pigs used to rid the pipe of water and debris are also run periodically and willbe discussed in Section 5.8.2. These protective systems are discussed in the followingsections.5.3.1.1 Cathodic ProtectionCorrosion is one of the leading causes of accidents reported to the OPS', hence, the correctapplication of cathodic protection is of prime importance to pipeline operators and to the OPS.The 1990 OPS Task Force that investigated longitudinal seam fatigue cracking initiated duringrail car shipment noted that Colonial was subjected to four enforcement actions for notmeetingrequirements in cathodic protection procedures from 1980 through 19872. In the same report, itwas also noted that since 1987 Colonial had quadrupled its yearly cathodic protection budget.Today, Colonial's goal is to apply and maintain acceptable levels of cathodic protection to all theunderground pipelines and tank bottoms. To achieve this goal, Colonial's cathodic protectionrequirements for these structures are defined in the Guide.Two protective criteria are defined in the Guide: 1 a negative 850 mVwith the current applied. 2 a minimum of 100 mV polarization between the structure surface and a stable reference electrode contacting the electrolyte.The Guide references the National Association of Corrosion Engineers NACE standard RP0169-92, Standard Recommended Practice, Control of External Corrosion on Underground orSubmerged Metallic Ploing Systems and the only parts of the RP that is incorporated intoColonial's cathodic protection program are the two above criteria. It should also be noted thatNACE's RP 0169-92 states that the lR drop potentials other than those across the structure-to-electrolyte boundary must be considered for either criterion and also that the formation or decayof polarization can be measured to satisfy the second criterion. In practice, Colonial utilizes thefirst criterion to determine the levels of protection on the pipeline but it does not consider the IR l See Appendix B: Table B-7. 2 Colonial Pipeline Fatigue Failures. OPS Task Force Report, September 14. 1990 37

O January 10. 1997 OPS Task Force Report Colonial Pipeline Company drop. The importance of determining the IR drop can be illustrated in the following equation. P/S~= P/SIR + ~ Where, P/Se = Pipe-to-Soil Potential measured directly over the pipe P/SR= Potential drop in the soil IR Drop ~ Protective Potential on the pipe One of the NACE's cathodic protection criteria in RP 0169-92 requires a - 850 mV potential on the pipe electrolyte boundary P/S~~0~~. Thus, if the pipe-to-soil potential measured directly over the pipe P/Se is - 850 mV then the IR drop P/SIR has to be zero to meet the criterion. For our example, NACE's RP considers it necessary for operators to demonstrate that the lR drop is zero or insignificant otherwise the required level of protection is not achieved. The OPS cited Colonial in a 1995 Warning Letter for not considering the IR drop. Colonial has not, at this time, modified their manuals to include the lR drop in their cathodic protection program. Colonial's cathodic protection systems on the pipelines and at the stations primarily consist of impressed current systems. Rectifiers and groundbeds, that have been installed along the pipelines, are the source of the protective current. Typically, operating a cathodic protection system consists of conducting annual surveys, where the protective levels pipe-to-soil. potentials on the pipeline are checked, and also of monitoring the rectifiers outputs to ensure that they are operating properly. Colonial, like many operators, exceeds the federal requirements and monitors the rectifiers every month. This work is performed by Senior Operators from Operations. They can perform minor repairs if a rectifier is found inoperable otherwise they will call the District Corrosion Specialist and report the problems to him. Colonial uses cathodic protection specialist contractors to conduct the annual cathodic protection surveys. These companies are provided drawings that show the test station andbonding locations, where pipe-to-soil potentials have to be measured and recorded. The cathodic protection survey data is then given to the District Corrosion Manager who enters it into a computer data base manually or by downloading the data from diskettes. Computers, which are available at each district, can then be used to print a list of the pipe-to-soil potential readings or to plot them for evaluation. Depending on the severity of the problem, there are several ways that this data is used by Colonial. Plots are more useful than listings for the quick detection of anomalies. However, if after detecting an anomaly, it is necessary to perform a more detailedevaluation, it can be made in the office using the data from the listings or from new field tests. Plots of two or three annual potential surveys can also be used as a tool to clear problems or to discern trends.. The Task Force review indicated that Colonial's corrosion specialists do not fully utilize the data base. The Task Force was provided listings of the annual surveys for the years 1994 and 1995.It was noted that generally the levels of protection on the pipelines met or exceeded Colonial's criterion; however, a few anomalies were observed. The anomalies included: positive potentials, potentials that did not meet Colonial's criterion, unusually high potentials - greater than three volts. It was also noted that records of previous interference tests were not kept at the district 38

January 10, 1987 OPS Task Force Report Colonial Pipeline Company offices. Without these records, the corrosion managers were unable to answer questions aboutpotential interference on lines in their districts. Colonial did report that the records were archivedat headquarters in Atlanta.Colonial corrects low potentials that are found during the annual surveys by takingaction in the field, such as, adjusting the rectifier's output. This can be easily done by thecontractor performing the annual surveys. For those deficiencies that remain, the Guiderequires that a list be prepared that includes each deficiency, probable cause, proposed solutionand projected date of repair. The Task Force found that in some districts these lists were notbeing prepared. 5.3.1.2 InternalInternal corrosion control is provided by requiring the shipper of the product being transported toinject inhibiter with the product at the origin point. The injection rates, dosages, etc. is theresponsibility of Colonial's Quality Assurance unit that is part of the Transportation ServicesTeam. The effectiveness of the internal corrosion control program is corroborated by the resultsfrom in-line inspections which do not indicate problems onthe pipe due to internal corrosion.5.3.1.3 AtmosphericAtmospheric corrosion of above ground pipe and equipment is controlled through the applicationof protective coatings to the particular equipment. Generally, the procedure for checking thecondition of the coating at certain time intervals consists of a visual inspection for rust since thisis sufficient to determine if the coating is still effective. If corrosion products are preseAt then theequipment's surface is .cleaned, prepared for painting by sand or water blasting and a newcoating is applied.Colonial's Procedure 3354, Visual Inspection of Above Ground Piping, requires the districtcorrosion specialist to inspect for atmospheric corrosion. The OPS standard inspection resultsindicate that atmospheric corrosion is not a problem at Colonial's facilities.5.3.2 PipelineAnytime the pipeline is exposed, the Guide requires that Form 3305, Pipe Inspection Report, becompleted. This form is sent to the District Corrosion Specialist and to the Drafting/MappingFacilitator, who ensures that vital information is transferred to the alignment sheets. Whencompleted, the form shows the condition of the pipe including existing wall thickness. There isno reference in Procedure 3305 to Procedure 2546, Reporting Safety-Related Conditions, whichrequires that calculations be performed to determine if the pipe is safe or needs repairs orreplacement in case of localized corrosion.5.3.3 Valves and OperatorsTo ensure proper operation during emergencies, maintenance of the operators for both theMotor Valve Operators MOV and Hydraulic Gate Valve Operators are included in the 39

January 10. 1997 OPS Task Force Report Colonial Pipeline Company Preventative Maintenance Manual. As noted earlier in this report, the Operations Manager is. responsible for scheduling the required maintenance on the operators and valves located on the pipeline right-of-ways that are assigned to them. Maintenance for the electric operators is required to be performed on two year interva4s while hydraulic operator maintenance is scheduled on single year intervals. Personnel performing the work on the valve operators will also perform other routine maintenance at the fenced-in mainline valves. This may include replacing signs, locks, or any other work that may be required. 5.3.4 Breakout Tanks There are 307 breakout tanks subject to OPS jurIsdiction in Colonial's system. These tanks are included in Colonial's preventive maintenance program. Procedures for the inspection of the tanks are found in the Preventive Maintenance and Tank Maintenance Manuals. The Preventive Maintenance Manual requires two types of tank inspections. The first, primarily a visual inspection of the dike and tank condition, is conducted monthly while the second inspection, which is slightlymore thorough than the first, is conducted annually. In addition to these inspections, a comprehensive inspection is also scheduled once every ten years. They are called Out-of-Service Tank Inspections and they are performed by contractors. The Out-of-Service Tank Inspections include: visual, magnetic flux leakage, ultrasonic ormagnetic particle inspection of the plates and welds in the sump, bottom, shell and shell-to- bottom welds. They also check for shell penetrations on each tank, on roofs, gauge poles and roof drains. Leak testing is also performed on shell penetration reinforcement pads, sumpwelds, selected bottom and shell-to-bottom welds. The results of these tests are recorded in a formal report and repairs are then made as required. To date, 197 tanks have been inspected in this manner. Two serious problems have been identified by the tank inspections. In the early 1970's, a problem with floating roofs on. gasoline storage tanks became apparent to Colonial. They foundthat serious deteriorati‡n of the wall was being caused by wear and by the corrosive nature of the vapor that was entrapped at the sides of the roof. In 1978, a program was inaugurated to replace these roofs with geodesic-dome roofs and to also install an internal floating deck. This has solved the corrosion problem. To date, 139 of 176 tanks have been converted. Theconversion is slowed in some areas by operational constraints where only one tank per year can be made available for upgrading.The second problem is with the tanks at Linden, NJ which have suffered extensive external corrosion on the bottoms. No other location reported this problem. This problem is attributed to the manner in which the tanks were constructed and are operated. The difficulties caused bythe original construction is that equipment for measuring the level of cathodic protection at the center of the tank was not provided. With this type of, installation, Colonial is only able to measure the level of protection `at the tank edge. Another difficulty is that with the original cathodic protection system the protective current does not distribute evenly to the underground 40

/ / O January 10. 1997 OPS Task Force Report Colonial Pipeline Company structures including tank bottoms because the cathodic protection current takes the path of least resistance. Consequently, some structures receive less current than others, leaving them unprotected. The difficulty caused by operations is that when the tanks are empty, parts of the uneven tank bottoms do not contact the soil and consequently are not protected by the cathodic protection system. Since this is an end terminal, the tanks may be emptied as many as five times daily allowing such tank bottoms to be inadequately protected from corrosion. To date, 14 of 25 bottoms have been replaced. Colonial has initiated a program to correct the cathodic protection problems by installing anodes underneath the tanks but not all the tanks have been retrofitted and the system may not be effective when the tanks are empty. 5.4 Valve Spacing To control the quantity of product that may spill into a water crossing, 49 CFR Part 195 section ß 195.260 e, requires that valves be installed on each side of a water crossing that is more that 100 feet wide. However, pipeline desigt~ and construction requirements in Part 195 are not applicable to hazardous liquid pipelines constructed before March 31, 1970. Since Colonial's original mainline was designed and constructed before the regulations were enacted, it does not have to comply with this requirement of the code. Colonial's second mainline, which was constructed in the 1970's, is required to cOmply with the regulations in effect at that time. In 1991, Colonial initiated a study to identify major rivers or water crossings that did not have valves installed within five miles of either side of the water crossing. The two main pipelines andthe stub lines were evaluated. The study was completed in 1992 and updated in 1993. Two hundred and six new possible valve locations on the mainlines and stub lines were identified in the study. Colonial's position regarding the resulting list is that it was intended to be used as anevaluation tool to identify critical crossings, where valves might be installed to mitigate the product spilled in case of a leak. Colonial also intended to upgrade the original mainline to meet the requirements of the regulations, if possible, and initiated a project to install valves, but it did not estabhsh a time table to complete it. In 1991, Colonial installed ten valves at river crossings on the 32-inch Line 4 in Virginia. The project was partly due to hydrostatic testing needs but it also served as the start of the program.The next valveinstallation project was initiated in 1992 and completed in 1996. Eighteen 36- inch diameter valves and one 8-inch diameter valve were installed under this project. Two additional valves have been installed since then. More valves have not been installed because` of competing priorities. Colonial has committed its maintenance funds to the OPS mandated programs, such as, running the ILl tool to determine pipeline integrity, or they have identified more critical projects, such as, the Out-of-Service Inspections for Tanks. To date, Colonial hasspent or budgeted more than $8.6 million on valve installations including $3 million dollars for 1997. 41

January 10. 1997 OPS Task For~ Report Colonial Pipeline Company 5.5 Maps and Records Changes at the stations are made by `1red.hning" drawings. When enough changes have been made, copies of the marked up drawings are'sentto Mapping and Drafting at company headquarters. Copies are also kept at the pump stations. The permanent changes are then made to the Originals and copies of these drawings are sent to the field for their files. Changes to the pipeline are made on the alignment sheets. The changes are reflected by completing forms, such as, Foreign Line Crossings, Form 3004, and Change Diagrams, Form 3331. Colonial's procedures do not specify a time interval to incorporate changes to the original drawings nor for distribution of the new drawings. Although Colonial field personnel reported that the "turn around" time for. revising drawings could be lengthy, they did not think this to be a problem since they had "marked-up" copies of the drawings in their files. Finally, changing and issuing the up-dated drawings does not mean that Transportation Services C‡ntrollers, a critical player in the safe operation of the pipelines, is aware of the changes. Transportation Services is not included on the distribution list in Form 3331. 5.6 Priorities Following re-engineering Colonial formed a committee, System Integrity Project Management. SIPM, to identify maintenance and capital projects and assign priorities to them. The committee is comprised of eleven key personnel from various positions in the company. Key maintenance projects are approved by this committee. For the fiscal year 1997, $16 million have been allocated for SIPM identified projects, such as, smart pig runs and confirmation/repair digs, tank inspection and maintenance, right-of-way ROW clearing and reclaiming and cathodic protection close interval surveys as shown on Table 5.3. Table 5.3: SIPM Budget Allocation Not final budgetProject-CategoryPercent AllocationSmart Pig49.8%Tank Inspection and Maintenance32.9%ROW11.0%Close Interval Survey ,6.3% 5.7 Emergency Response The OPS Oil Pollution Act requires pipeline operators to submit Spill Response Plans to reduce environmental impacts in case of spills. Colonial has submitted such a plan which wasapproved by OPS. Most of the emergency response equipment is stored and maintained at the District yards. The remainder is located along the right-of-way at the pump stations~ In addition to this equipment, Colonial also has contracts with various vendors who can respond to emergency situations. 42

January 10, 1997 OPS Task Force Report Colonial Pipeline Company 5.8 In-Line Inspection Program 5.8.1 Introduction In-line inspection ILl tools have become a significant component of pipeline integrity assessments in the pipeline industry. ILl tools are commonly called TMsmart pigs" because of the sophisticated electronic technology they utilize. Colonial has been applying ILl technology for about 20 years. In 1996 and 1 997t, 20% of their maintenance budget is specifically applied to ILl and associated remediation projects. The Task Force evaluation of Colonial's ILl program included the review of their methodologies, as well as an analysis of a representative sampling of ILl projects. Focus areas of the evaluation included: * Hydrostatic Testing and ILl Technology * Initiation of Colonial's ILl Program * Application of ILl Technology * Rehabilitation Analysis & Timeliness of Repairs * ILl Program Management 5.8.2 Hydrostatic Testing and In-Line Inspection Since March 1970, federal regulations have required that replacement pipe and components be hydrostatically tested prior to being put in service for hazardous liquid pipelines. These regulationsalso require that hydrostatic pressure testing be performed after construction before a pipeline can be placed in service. Hydrostatic pressure testing can also be used to re- establish pipeline integrity or to reclassify maximum operating pressure. All of these tests provide an opportunity to verify the strength and integrity of the pipeline. For integrity assurance purposes, hydrostatic pressure testing is only one of the methods available to establish a pipeline's integrity and is explicitly noted in 49 CFR Part 195 Sections 195.300-310. OPS experience indicates that hydrostatic testing to a greater pressure than the MOP can help identify anomalies, such as, corrosion or fatigue cracks before damage can progress enough to cause a leak or rupture at normal operating pressures. Hydrostatic pressure testing has been the preferred technique for integrity assurance, and remains a useful destructive testing technique to find weaknesses, cracks and corrosion in pipelines. Although infrequent, damage from crack growth during testing may occur at defects. The cracks may grow, but be just small enough to survive hydrostatic pressure testing and, over time, result in a subsequent pipeline failure. Hydrostatic testing also involves some environmental issues of water disposal not generally associated with the use of ILl technology. It is clear that a reliable non-destructive testing method that could find pipeline anomalies smaller than would be* discovered by hydrostatic testing, and without the associated crack growth and water disposal problems, would be a preferable technique. Industry's response has been the development of ILl technology, ILl tools have been in* commercial application for more than twenty years. The OPS has been actively involved with ILl `Fiscal 96 Forecast: Revenue S575mm; Income $158mm: all Maintenance $5Omm, of wflich $lOmm is U. 43

January 10, 1997 OPS Task Force Report Colonial Pipeline Company technology since the eariy 1970's by participating in the approval of the ILl requirements of the Trans-Alaska Pipeline System. Over that period of time, ILl tools have been developed to detect dents, ovality, certain gouges, corrosion and metal loss. A new generation of prototype ILl * technology became available in 1995 to reliably detect longitudinal weld-seam cracks in hazardous liquid pipelines. The OPS continues to encourage the improvement of ILl inspection technology, particularly in tools which will enhance the detection of mechanical damage and cracks. For example, on June 20, 1996, the Department of Transportation announced a $1.9 million contract, for a two year joint industry/government research project to develop technology that will enhance the capability to find such damage and cracks. See Appendix G for more details. Colonial's original construction included launchers and receivers for.cleaning pigs. Colonial, as well as many other hazardous liquid pipelines, frequently uses cleaning pigs to pushsediment and water from their pipeline to help keep the pipe clean and insure product quality. Over the past ten years, Colonial made significant renovations to traps and removed some tight radius elbows to accommodate IL tools. Based on the comparison2 in Table 5.4, Colonial's system has a higher percentage of piggable pipelines~ than the industry average. Table 5.4: Piggable Hazardous Liquid Pipelines in USHazardous Liquid PipelinesIndustryMileage' IndustryPercentageColonialMileageColonialPercentagePigg‡ble, with traps586.33555.7%5,14496.4%Piggable, needing traps52,39033.8%60.1%Not Piggable16.27510.5%1873.5%Total155,0005,337 5.8.3 Initiation of Colonial's ILl Program Colonial first ran ILl tools in the mid 1970's as a. pilot tests. One segment was the Fort St. Joe, FL to Bainbndge, GA stub line that was constructed in 1941. The ILl tool found a considerable amount of corrosion. Colonial subsequently had two notable ruptures attributed to corrosion in the early 1980's which helped formulate Colonial's ILl program. The first line segment to be formally inspected by Colonial had a potential for in-casing corrosion problems'. Another 2lnstrumented Internal lnspe~ion Devices Report. LJSDOT. November-1992 3Public Law 104-304. amended 10-12-96, 49 usc 601020 reaffirms OPS to establish regulations to mandate that pipelines be construoted or renovated to accommodate smart pigs. `Figures for Industry may not be exam due to the recent addition of c2o%SMYS pipelines. `Length of trap was not deÒned in survey. Manassas. VA: March-1980 & Birmingham, AL in-casing; April-1985 Peiham - Atlanta, 35, constru~ed in 1962-63 44

January 10, 1997 OPS Task Force Report Colonial Pipeline Companyoperator had a failure in Kentucky due to in-casing corrosion in 1985 which drew nationalattention. The failure in Kentucky was a catalyst for the OPS to issue its first HFO under newenforcement rules, requinng the application of ILl as a part of the remediation program. Morerecently, Colonial's Reston, VA 1993 and Texas Eastern's Edison, NJ 1994 failures have bothemphasized the use of ILl technology to re-establish the integrity of pipelines. Although there isno present federal regulation that specifically requires the utilization of iLl tools, the OPScontinues to require ILl in selected compliance case.Colonial has utilized iLl extensively as shown in Table 5.5. Logistical advantage andcomparatively lower costs have made ILl a significant component of the line integrity program atColonial. The combination of all ILl tool runs is in excess of 12,000 miles, a significant portion ofwhich was voluntary. This effort has prompted several thousand excavations to confirm andrepair detected anomalies. This work has provided an opportunity for Colonial to develop abroad range of experience in iLl technology. Table 5.5: Hydrostatic Testing and ILl as of Nov. 1996"~"ColonIal Pipsibna Mllesg. ~TotalMilesHydrostanc~ ILlC~ip~.¯~mation IU~ ~Corrosion IU~Seani crack~t2Not Hy¯ro-tested~ ILl ~since construdionMainlines, 30". 40'2.8871402,8832.833185413Stubs&Del,very,6"-lr2.4501012.3492.1050189Total Mileage5.3372415.2324.9831851935.8.4 Application of ILl TechnologyA step by step description of Colonial's ILl Program has not been established by Colonial in awritten guide. Colonial does target iLl projects to segments based on a number of factors. Theybelieve that influencing factors are too unique to estab~sh in a formal guidance document. Theyrely on the experience, of their staff to target ILl projects using fundamental risk managementprinciples on an annual basis,. and make dynamic adjustments as necessary.The program has evolved into an average ten year cycle that is frequently adjusted to accountfor operational changes, advances in associated technology, review of cathodic protectionsystem data, the analysis of past and recent failures, and regulatory mandates. Colonial's iLl `Appendts a Tb. DOT R&D Program on Mechanical Damage: February.1 996 `Some line segments have been hydro-tested or Ill inspedied multiple times. `°Additional projeds are currently in progress or scheduled. Refers to hydrostatic testing performed sometime after the original MOP was established. `~ British Gas ILl tool has not yet been run in any 30' or 40" pipe. t3 Lower pressure ma in the Houston. TX area, still on Coloniars IU proje~ list. 45

p~ January 10, 1997 OPS Task Force Report Colonial Pipeline Company program follows a step progression, where a caliper/deformation tool is run first, then a metal loss/corrosion tool. They have recently introduced an ultrasonic crack detection tool for selected pipe'~ in the original mainline that has experienced long-seam crack failures. This combination of technologies is assembled to provide a basis for an ongoing assessment of their pipeline system. When an ILl project is initiated, vendors are targeted based on their ability to provide tools in the required pipe size, applicable technology, past performance, scheduling options and the ability to reference previous pig run data. Colonial considers these factors to be so important that they have not awarded ILl contracts based solely on price since 1993. In addition to the primary review of ILl logs by the vendors, Colonial began to train company inspectors to review ILl logs in 1987. This effort was to better identify targeted remediation work by scrutinizing the pig logs and to identify other anomalies that were not addressed by pig vendors. Traditionally, pig vendors only identify the worst anomaly in any one pipe joint. Colonial is working toward identifying all significant anomalies for repair and minimizing unnecessary excavations. In support of this goal, Colonial arranges for ILl vendor-provided training for its employees as a part of each ILl project. Internally, Colonial has provided training programs covering radiography, compression wave ultrasonic testing, magnetic particle testing. and visual weld inspection. They also conduct an annual maintenance meeting in Atlanta that includes a discussion of lessons learned" in ILl projects, which focuses on log interpretation and construction planning. Colonial also encourages its inspectors to achieve certification in the use of ultrasonic NDT equipment. Through interviews with Colonial personnel, the Task Force developed the following sequenceof steps in their ILl program. The asterisked *items shown below are included in the Pigging Guide of Colonial's Maintenance Manual and generally follow recommended industry practices, such as API Recommended Practice 1129, Assurance of Hazardous Liquid Pipeline. System Integrity. Management Directives and Technical Strategies: 1. Review and revise the overall program strategy and line segment pnoritization. 2. Establish target segments on an annual basis. 3. Establish projects for technical and administrative tracking. 4. Match specific tools to project requirements. 5. Target vendors based on technical capabilities, past performance and economic factors. Project Initiation: 6. Coordinate projects with pipeline schedules. 7. Peifoim any necessar, construction and run dummy or cleaning pigs. 8. * &ecute ILl run/runs. Data Analysis: 9. Review IL.! runs in progress with verification digs and calibration. 10.' IdentiI~j preliminary anomalies and make initial assessment Pipe manufacturers National Tube and Republic Steel. 46

January 10, 1997 OPS Task Force Report Colonial Pipeline Company ii.' Direct prompt repair efforts to identified severe conditions. 12. * Calculate for any required pressure reductions. 13. * Conduct formal data analysis. 14. Train district project personnel to interpret the data of each pig run. 15.' Receive and review subsequent detailed report 16.' Map anomalies for reference and comparative analysis with previous pig runs. 17. Discount anomalies found and addressed in previous pig remediation. 18. * Focus on notable anomalles for consideration of priority attention. 19. * ldentif~.' and prioritize anomalies for excavation and repair.Assessment and Repairs: 20. * Excavate anomalies for examination and repairs. 21.' Calculate any loss of pipe strength due to the physical characteristics examined. 22.' Compare pipe strength with maximum operating pressure constraints. 23.' Schedule required construction and operations logistics. 24.' Execute targeted rehabilitation.Analytical Review: 25. Conduct metallurgical analysis as necessary 26. Restore pressure restrictions. 27. * Archive data for future analysis. 28. Close-out projects for administrative processing.5.8.5 Rehabilitation Analysis and Timeliness of RepairsTo better understand how Colonial's ILl program is applied, a quantitative analysis wasundertaken by the Task Force. The Task Force examination of Colonial's ILl program hasprovided the basis for this review. In some instances, ILl is not always feasible where complexmanifolds and changing pipe sizes make pigging impractical. A small portion of Colonial's stuband delivery lines cannot pass an ILl tool and are still dependent on hydrostatic tests to verifyline integrity. These lines are typically 300-400 feet in length with short radius bends andoperate at about 100 psig. A listing of all ILl projects is included in Appendix D: Tables D-3 and0-4.The Task Force targeted eight lii projects for detailed analysis. Two of the line segments havebeen ILl inspected with MFL in the late 1980's and again early in 1996, providing the opportunityto perform a comparative examination. Other ILl projects include a sampling of different pipesizes, ILl technology, pig run dates, construction period, and under the different managementstyles of the former East - West division of Colonial's organization. The eight ILl projects areshown in Table 5.8. Additional information aboUt these projects is located in Appendix D-5. 47

O January 10, 1997 OPS Task Force Report Colonial Pioeline "~----~- - Table 5.6: Selected Colonial ILl Run ReviewsLocation-LineSizeMilesConst. .Tool -RunDateReviewProcessClassifiedAnomaliesRepairedCoetion dateDorsey, MDLinden, NJ- 3301951963MFLSep-88Jan-89General &ComparaliveAll SevereAll MediumAug-92Dorsey, MDLinden, NJ330'1951963MFLMay-96General &Co~~Target alles.. & Mod. inprogressAnderson, SCGreensboro, NC236"2001963MFLSe~~'General &ComparativeAll SevernAll MediumAug-91Anderson, SCGreensboro, NC23r2001963MFLMar-96General &Coiparative Target allSev. &Mod.. and TSI in~Houston, ~Baton Rouge, ~1402601979MFLJan-93 ~General Target anSev. & Mod., and TSIinogressChattanooga. TNNashville. TN1910112"1471972CaliperMay-89GeneralAll AnomaliesSep-91Greensboro. NCDorsey. MD ~432"2881963MFLJun47General.All SevereAll Medium,target TSPJun-90, TSP's~in,Louisa, VADorsey, MD432"1031963UltrasonicCrackpigJun-95Feb-96General *All AnomaliesPlanned for These ILl projects were carefully selected to provide a broad overview and representative data about ILl for Colonial's entire pipeline system. The Task Force visited Colonial's district offices at Spartanburg, SC, Dorsey Junction, MD and Woodbury, NJ to review pertinent ILl run data and related pipe remediation efforts. The on-site review provided an understanding of how ILl data review and pipe remediation efforts are performed at Colonial. Colonial utilizes a variety of IL! tools caliper and/or geometry for pipe diameter reduction; MFL for metal loss defects I corrosion and ultrasonic crack detection to locate longitudinal weld cracks. Among the three locations, there is a consistency of data analysis and resulting repairs. Colonial's data analysis includes top side indication TSI analysis as described later in this section. In many cases, Colonial starts pipe remediation effort upon receipt of "preliminary data" from thepigging vendor. The pipe is then excavated at target locations to validate the readings of the ILl data. Colonial's pipe remediation efforts indicate that anomalies are classified and located to help coordinate excavations. Priority is given to severe anomalies, even though efficientconstruction planning may have to be sacrificed in the process. Historically, the entire pipe joint was exposed. Colonial Inspectors are now trained to better analyze logs to excavate only at classified anomaly locations's. Colonial asserts that their inspectors are as knowledgeable in the ~ Colonial investigates all long-seam crack anomalies.48

O January 10, 1997 OPS Task Force Report Colonial Pipeline Company analysis of ILl tool data as the vendors. It was observed that all anomalies classified as severe and medium were excavated and analyzed. Appropnate repairs are then executed as per Colonial's operations and maintenance requirements. Necessary repairs were made by several techniques based on the findings of each excavation i.e., pipe replacement, sleeve, or re-coating. The repair completion period is dependent on a number of factors associated with each specific project, and is typically from 1.5 to 4 years in duration. Priority is always given to severe anomalies. Extended remediation periods are usually applied to low level moderate and light anomalies dependent on available resources. On an overall system basis, Colonial has had more corrosion problems with their older lines installed in the 1960's, even though cathodic protection is now applied to all lines. For example, Colonial attributes the corrosion-oriented failures on Line 2 to the industry standard time lag of up to one year for the installation and adjustment of cathodic protection systems". Cathodic protection was applied to the looped lines, such as Line 1 shown below, immediately after construction in 1979. Table 5.7 highlights this phenomenon. Table 5.7: Lines 1 and 2, Anomaly ComparisonAnderson, SC toGreensboro, NCMilesConst. ILlInspect. Yr.SevereAnomaliesUne2,36~20019631987209Line 1,40200197919930 As a result of this phenomenon, Colonial is targeting some new pigging projects'7 to track previously identified light" corrosion. Colonial repairs severe and moderate corrosion inremediation projects. Comparing previously recorded light corrosion that has not been repaired, with new pig data, will provide a vehicle to track the effectiveness of the cathodic protection and the integrity of pipe.coating.. The Dorsey Junction, MD to Linden, NJ 30-inch line is one of these lines. Where some other line segments may have more of a tendency to develop corrosionpitting, the somastic coating on this line, in conjunction with regional soil conditions, has a tendency to contribute to the development of general corrosion over large surfaces. To make a valid comparison, the data from a second pig run must be collected with the same sensitivity asthe first. According to Colonial, the ability to monitor the condition of previously recorded light corrosion in comparison with new ILl tool data will allow them to focus resources to the more active areas of corrosion on their system. Finding gouges in dents caused by mechanical damage with ILl tools is more difficult than locating corrosion. Presently there is no single ILl tool that can always identify a gouge in a lS CFR ß195.242, enacted in 1968. allows the installation of cathodic protection to follow construction by one year. Example: Dorsey Junction- Linden, 30":.MFLs in 1989 & 1996. ` Corrosion is typically scaled as percent of wall loss: Light <25%: Moderate 25-50%: Severe >50%. 49

January 10, 1997 OPS Task Force Report Colonial Pipeline Compan1 dent. The 1993 accident in Reston, VA was initiated by a gouge in a dent approximately at the 11 :.30 clock position, damaged by mechanical equipment. OPS for the first time required Colonial CPF 13503-H to develop an ILl plan using a combination of tools which would findpossible mechanical damage. The OPS approved an ILl plan that called for Colonial to run both a magnetic flux leakage and geometric ILl tools for a 45 mile pipeline segment. Colonial was required to analyze the combination of data, all TSI and note all anomalies identified as possiblelongitudinally oriented gouges. These anomalies were excavated, examined and evaluated. Specifically, Colonial examined 42 anomalies in the upper quadrant of the pipe, and of those, four appeared to have a gouge in a dent caused by mechanical equipment. All four wererepaired. Other anomalies were also examined and seven other repairs were made. Both the OPS and Colonial are confident that this inspection program was a success and would have found any dents or gouges in pipelines similar to those found at the failure site. Both parties were also confident that the anomalies found were smaller than would be found by a hydrostatic test. Based on the accident history of Colonial mainlines between Greensboro, NC and DorseyJunction, MD, and on the successful ILl program described above, Colonial and the OPS entered into a Consent Order in August 1995 CPFI45OI-H, which requires Colonial to run a similar inspection program for these segments of pipelines. This program was initiated in 1995.In addition to the OPS Orders, Colonial has advised the Task Force, because of lessons learned and their own analysis, that they have initiated a program to review other selected previous IL tool data for TSI. Additional information may be found in Table 5.8. Table 5.8: Colonial's Targeted TSI AnalysisLineSizeSegmentConat.Prompted by:336"Greensboro, NC Dorsey Jct. MD1979OPS HFO. 4193Consent Order, 8/95140"Houston, TX . Baton Rogue. LA1979CPL, Risk Assessment, Formal Memo* 236"Epes. AL - Anderson. SC1963/1979CPL Risk Assessment, Project List236W'Anderson, SC -Greensboro. NC1963CPL, Risk Assessment. Project List432"Greensboro, NC - Dorsey Jct. MD1963CPL, Risk Assessment, Project ListVanous OPS Orders - 8/90 to 8/95 5.8.6 Longitudinal Seam Crack ILlColonial utilized a new technology prototype crack pig in 1995/96 in the 32-inch diameter pipeline in Virginia and Maryland as noted in Table 5.6. The crack pig has successfully demonstrated an ability to find Árack-likÈ features along longitudinal seam welds. Table 5.9provides additional information about the ILl findings. Colonial chose to expose all anomalies features and field verified using ultrasonic and eddy current examination and NDT technology. Colonial has currently adopted a policy of placing temporary sleeves and subsequently cutting out all confirmed longitudinal seam weld cracks to re-establish pipeline integrity. It is important to note that the longitudinal seam weld cracks detected by the ILl crack pig were smaller than 50

O January 10, 1997 OPS Task Force Report Colonial Pipeline Companywould have been found by a hydrostatic test. Based on the successful application of the ILl crack pig, the OPS recently required Colonial to utilize the crack pig to inspect the original mainline, system-wide from Pasadena, TX to Linden, NJ, in locations where National Tube and Republic Steel were the pipe manufacturers.' Table 5.9: Summary of Excavation Results, British Gas Crack Pig in Virginia and Maryland, 1995" and 199620 Feature2'Classification type Number ofconfirmed CracksNumber of non- cracksTotal of significantfeatures reportedC-i151227C-231922C-301818Weld Detectsand Others01111Total186078 5.8.7 ILl Program Management The Engineering Services Team develops and manages the ILl program from AtlantaI Headquarters. They establish a list of targeted ILl line segments for each year's budget, based on the ten year plan. During budget planning, the Project Managers prepare for the anticipated costs and personnel to address ILl excavations and repairs. After the ILl vendor supplies the formal conclusions report of a ILl tool run, the Projects Group assumes a lead role in anomaly investigations and associated remediation. Colonial fieldI maintenance personnel also review new ILl logs. Headquarters personnel remain available for assistance, and will likely become involved if abnormal situations arise. Maintenance personnel - repair all severe and moderate corrosion damage, all construction and third party damage, andI all crack-like features as identified by the new ultrasonic crack detection tool. Colonial's general remediat ion philosophy is to restore the full strength of the pipe, even if the current operating pressures do not require full strength. Maintenance personnel from different operatIng districtsI establish records for the construction repairs of each ILl project. Headquarters engineering staff has not tracked or recorded individual remediation projects since the reorganization making if difficult for Colonial to maintain a comprehensive perspective on their ILl program.I Colonial has shared the experience of their pigging program to the benefit of the pipeline industryV. They are a member of the ASME B31 .4 Committee and actively participate on API 19 British Gas Research & Technology. Elastic Wave Technology, Louisa to Remington, VA, 47.5 miles. 20 British Gas Research & Technology. Elastic Wave Technology. Remington, VA to Dorsey Junction, MD, 55.5 miles. 21 c-i is most crack-like. C-2 and C-3 are crack-like to lesser degrees. ~ Coloniais Experience with lL~, paper presented at the International Pipeline Conference. Alberta Canada, 1996. 51

O January 10, 1997 OPS Task Force Report Colonial Pipeline Companycommittees and standards groups. As a part of that participation, Colonial has suggested to theOPS that API Recommended Practice 5L1 should be included in federal regulations to insurethe safe transportation of pipe. Fundamental to this issue is that no metal-to-metal contact otherthan pipe-to-pipe should be allowed. Colonial has experienced six fatigue crack failures~, five ofwhich were in National Tube pipe that was not transported in accordance with a pipe loadingprocedure similar to API 5L1. In lieu of specific regulations, Colonial now provides a loadinginspector each time they take receipt of pipe at steel mills, and specifies that pipe manufacturersload pipe in accordance with API 5L1.Colonial has also helped fund the early development of ILl ultrasonic crack technology forlongitudinal weld-seam crack detection in hazardous liquid pipelines. In 1996, Colonial appliedthe new technology for longitudinal weld seam crack detection in an ILl inspection fromSimpsonville, SC to Gastonia, NC. The OPS is an advocate of this new technology and hasaccepted its application in the Colonial Systems'. OPS, as stated earlier, has required Colonial torun the new ILl tool system-wide for all pipe that has a history of longitudinal weld seam splits.Colonial is now incorporating ultrasonic crack detection tools into their general ILl program andis assisting in the development of these tools for smaller line sizes and short radius bends. ~ Colonial Pipeline Fatigue Failures, OPS Task Force Report. September 14. 1990. 24 CPF 14501H, 08-15-95 & HFO 26501H, 07-31-96 52

January 10, 1997 OPS Task For~ Report Colonial Pipeline Company 6.0 Training Report 6.1 Introduction As mentioned earlier, throughout Colonials operational history, several 37 out of 194 reportable accidents have been attributed to operator error. Preliminary investigations link`I operator error as a contributory cause to the recent accident near Simpsonville, SC. Prior to this, the OPS, as mandated by law, has pursued new regulations which would provide guidelines to pipeline operators for the qualification of operation, maintenance and emergency responsepersonnel, see Appendix G. This initiated the Task Force's examination into Colonial's personnel training. Consequently, the Task Force examined Colonial's training program with a primary focus in the following areas: * Organization Operations and Maintenance personnel initial training * Continual Training Program * Advancement and Career Development * Program Improvements The Task Force visited Colonial's headquarters and interviewed the training staff, collected data on its schoolsand seminars, and reviewed corporate manuals to address the effectiveness of Colonial's training. This section of the report will be a summary of those visits and will present the Task Force's view of Colonial's training program. 6.2 Organization The 1994 reorganization had relatively little effect on Colonial's Training staff. All of the corporate training with the exception of the pipeline controller training is managed by the Safety and Training Team which is made up of five members within the Human Resources Team1: Team Member Training Resoonsibilities Operations Trainer: Training programs for the field operations personnel. Technical Skills Trainer: Training programs for the field technical and pipeline maintenance personnel. Contingency Training Coor.: Training programs for Emergency Response. Safety Coordinator Training programs for safety related issues, OSHA training. Assistant Training Coordinator: Assist in the development and implementation of training. `The re-engineering has neither reduced or increased the corporate training staff. 53

O January 10, 1997 OPS Task Force Report Colonial Pipeline Company According to Colonial's Technical Skills Trainer, Colonial has, since its inception, offered a TMcafeteria" approach to their training program. Employees have the freedom to choose from several types of training to meet their specific needs. Colonial feels that this, coupled with their PIPE program refer to Section 6.3.4, would satisfactorily meet all requirements under Part 195. To that end, Colonial conducts many schools throughout the year on fire and HAZWOPER training. Additionally, they offer a variety of other courses which cover varied subject matter; for example: Pump, Valve, Basic Electrical and Supervisory Maintenance Schools2. This allows Colonial to meet the training requirements of Part 195 and present options to their staff to broaden their knowledge base. Enhanced attention in the areas of pipeline and tank maintenance has been given since 1992. This was in response to Colonial's aging system and the steps they are undertaking to maintain and ensure system integrity. It is typical for "non-professionar employees3 to enter Coionial at the Utility B classification. These employees are entered into the training program from the onset. The following sections describe Colonial's entry level and advancement process for its field maintenance and operating personnel. 6.3 Employee Training Program 6.3.1 Operations For the purpose of this report, Colonial has five positions which fall under the classification of Operations: Utility B, Utility A, Operator B, Operator A and Senior Operator. The Operations Trainer is responsible for the training program for these positions. In their current organization, new hires will enter the Colonial system as a Utility B. Colonial's established training program requires that all probationary employees4 participate in the Operator Training Program, complete the operator training guide andparticipate in an on-the-job training program for at least six months prior to being considered for promotion to Utility A. Failure to complete this required training will result in termination. The Operator Training Guide is given to all incoming employees. It is a manual designed to give the new employee an overall exposure to the Colonial pipeline system and pipelining in general5.It is meant as a study tool which, based on its design, will require the employee to seek out the varied reference materials available in order to complete the required sections. Additionally, the manual directs the employee to obtain information from other more experienced employees tocomplete essential parts. The manual covers many topics through a series of questions which require the employee to look up the answer in one of Colonial's manuals or ask a more senior 2 See Appendix E: Table E-1 ~ Field operators, technicians, maintenance personnel. Engineers, Accountants etc. have a separate training program and were excluded from this report. ~ Employees with less than six months of employment. ~ Index included in Appendix E.

O January 10, 1997 OPS Task Force Report Colonial Pipeline Company operator for assistance. The majority of questions require short answers with some objectivity. While they work on the manual, each employee is paired with a qualified employee in each ofthe job classifications. The new hire spends time learning each of the operator positions as part of his training. While the manual requires at least 30 days of on-the-job training, each employee typically receives training for most of the six months of probation. A senior employee trainer.will show the probationary employee the essentials of the job function and after that allow the new employee to carry out the essential functions while under supervision. This is the probationary employee's opportunity to show competence in the job classification. According to Colonial's Operations Trainer, the strainer", who is selected by the local team leaders, is not an official position and is often not the same individual for all new employees. The Operations Trainer pointed out that some field personnel dislike the added duty required for training. The effect is that the exchange of information to the new employees is not consistent. Each location has operational tasks unique to that location. The Task Force was unable to locate any local training guidelines for new employee training. After six months, when the training guide has been completed and the employee has demonstrated competence, Colonial promotes the employee to the. Utility A position. Theemployee and the supervisor will review all material covered during the trainingpenod. When the supervisor has confirmed that the employee has adequately absorbed the material, a recommendation for advancement will be written. The employees will not necessarily receive additional training as they advance through the operational levels. Colonial feels that once the initial training is completed, the employee is qualified to perform all duties within the operations level. It is typical for an employee to fill in for another employee due to illness or other absenteeism. This enables the employees to maintain their knowledge of the duties required for the different operating positions. 6.32 Controllers As stated ËarliÈr, the pipeline controller training is not included within the Safety and TrainingTeam but is conducted by the Transportation Service Central Team TSCT. TSCT has formed two teams made up of controllers and sponsored by a Shift Supervisor to monitor and improve the training program. The Control Room Training and Compliance Team reviews and revises the. existing training program; and the Error Focus Team reviews minor accidents and reports to the controllers about lessons learned.~ For the purpose of this report, Colonial has three positions which fall under the heading of Pipeline Controllers: Associate Controller, Controller and Relief Controller. Typically, all vacancies within the Controller classifications are filled by personnel from field positions, therefore, they have already completed the training described in Section 6.3.1. Before filling a vacancy, all qualified candidates are invited into the Atlanta Control Center for a two week orientation. This gives the TSCT the opportunity to ~valuate the candidates and assess their potential to become a Controller. Also, the candidate is given the opportunity to see what the job involves. After all candidates have had the opportunity to complete the orientation, the team 55

O January 10. 1997 OPS Task Force Report Colonial Pipeline Company selects the most qualified candidate to become an Associate Controller. Once selected, the Associate Controller associate begins a training program, generally six months, which is similar in design to the operations training. The associate is given an Associate Controller Training Guide; a manual describing the requirements of the new associate. The associate reviews the operating manuals and begins an on-the-job training program which consists of learning the operations of the control system by working with a trainer Controller6. A checklist is used by the trainer to ensure complete coverage of normal, abnormal and emergency operations. Also, a series of eight tests are administered to the associate during the training period. Associate Controllers fill vacancies on the stub line system. By the end of the six month training they will have had at least 3 ½ months of training on the stub line systems. At the end of the training program, when it has been determined that the associate is qualified, Colonial promotes the employee to Controller and permits the individual to work a shift alone.The Controllers receive additional "refresher training when they change operational systems. It is the preferred company practice that a stub line Controller be transferred to the mainlines. When this happens, that Controller will receive an additional six weeks of training on the newcontrol system. Once again, the Controller will be evaluated and qualified before being allowed to work a shift alone. If the Controller is selected to become a Relief Controller, additional training, very similar to the training received as an Associate Controller is provided. The Relief Controller is trained on every system and, as the job requires, qualified on all the control systems. 6.3.3 Pipeline Maintenance and Technicians The maintenance and technician personnel training is supervised by the Technical Skills Trainer. For the purpose of this discussion, Colonial has three positions which fall under the headings ofmaintenance and technicians: Project Inspector, Associate Technician and Technician. In their current system, these positions are filled as a result of an internal transfer from Operations. Since all employees filling these positions are internal transfers, they have already completed. the training as described in section 6.3.1. An additional requirement for a technician position is the successful results of a Technician Test. This is a written test which provides an evaluation of the analytical ability and knowledge of related topics for the position being sought. Training for newly promoted pipeline maintenance and technicians is again on-the-job training with supervision from a senior employee. Also, all of the pipeline maintenance personnel are required to complete an excavation standards class. ~ See Appendix E. 56

O January 10, 1997 OPS Task Force Report Colonial Pipeline Company 6.3.4 Continuing Training Programs 6.3.4.1 Field employees As part of the effort to meet the requirements of ß195.403a, Colonial requires all field employees to complete appropriate sections of the computer based Pipeline Instructional andProficiency Examination PIPE program7. Current policy requires that all employees pass eachrequired test with a minimum score of 80%. Colonial conducts other annual training as required under Part 195. Fire training school is conducted throughout the year, and key employees are required to attend this class at least once every three years. HAZWOPER refresher is required annually for all HAZWOPER trained employees. Additionally, Colonial has established an extensive video library to assist with training.Colonial requires local monthly safety meetings to augment the training program. These meetings are conducted by the employees and the duties are rotated among the staff. Colonial has established several required topics that need to be covered annuall?. Within Colonial's Accident Prevention Manual is guidance for the employees to prepare and present an effectivesafety meeting. The corporate training team does conduct a random review of these meetings to evaluate their effectiveness and make additional recommendations. 6.3.4.2 Controllers Controllers do not have a formal continuing training program. The shift supervisor is capable ofmonitoring the operations of all of the Controllers on a shift to identify any operational weaknesses, If identified, the shift supervisor would conduct an informal training session with the individual controller. There was a requirement to complete the Controller ContinuingEducation Program CCEP9, but when the control center relocated in 1991 the CCEP computer program was lost10. Consequently, the controllers have not completed the CCEP since 1991. On occasion, the Controllers will participate in other corporate training. Examples are HAZWOPER and Pipehne Hydraulics school. ~ A computer based program made up of multiple choice questions on various topics ranging from Hazardous Materials to Right of Way Encroachment. 8 Required Topics: Fire Fighting Equipment, Lockout/Tagout. Emergency Response, CPR & First Aid, Safe Handling of Hazardous Waste, Right To Know MSDS, Confined Space Entry, Safe Driver Awareness. `~ A computer based program similar in nature to PIPE. `° The computer program has not been retrievable from the mainframe since the relocation. 57

O January 10, 1997 OPS Task Force Report Colonial Pipeline Company 6.3.4.3 Pipeline Maintenance Employees All project inspectors are enrolled in the "Pipeline Maintenance School". This annual school is`5? typically a three day course with two days dedicated to an optional subject and one day dedicated to a review of Coloniars Maintenance Manual and current practices. Currently, the school is in the completing a four part series on non-destructive testing. Colonial also conducts annual tank inspection and maintenance schools. Other specialized training is conducted on an as needed basis. For instance, if a group oftechnicians request a turbine meter school, the training department will coordinate the effort and* conduct a school with either in-house or vendor supplied trainers. Colonial provides an opportunity for all employees to request attendance at outside schools or seminars that theemployee feels may be beneficial. The training coordinator did point out, however, that this option is rarely utilized and the practice is not applied consistently company wide. 6.4 AdvancementJCareer Development Colonial has no formal career development program. All promotions or advancement for operator personnel are selected based on seniority. A list of interested candidates is compiled and the most senior employee is awarded the position. It is Colonial's policy to promote stub line Controllers to the mainlines and from there, possibly,promoted to a Relief Controller. As described earlier, this person has the responsibility of knowing the six control systems. Shift Supervisor vacancies are filled from the Relief Controller positions. * 6.5 Program Enhancements 6.5.1 Coordination Teams When Colonial re-engineered, they instituted a team approach t‡ solving problems and addressing the needs of the company. From this new management philosophy sprang several teams for improving the training program. The Operations/Technical Training Coordination Team OTTC was formed to "Coordinate.operations and technical training programs that address the occupational skills and knowledge needs of employees, as well as performance and regulatory compliance needs of Colonial Pipeline Company."1' A major offshoot of this team was the Technician Task Force. TheS Technician Task Force proposed changes to the selection, training and advancement practices to the current technician classification. The proposed program will focus on training and qualification prior to promotion to the title of Associate Technician. This proposed program is achange from the current system; it will place emphasis on training and qualification prior to promotion. These proposals are currently before Colonial's management for consideration. "Taken from OTTC Team Charter. 58

O January 10, 1997 OPS Task Foite Report Colonial Pipeline Company Other proposals currently under consideration are the PRISM12 training program and a new employee orientation package. The Control Room Training and Compliance Team was formed to eachieve the best trained and most qualified control room team. ~ The major focus of the team is to review current training practices and recommend changes as necessary. The most recent proposal was the development of the Relief Controller Training Guide. This document provides more structure and better documentation of the Relief Controller training. 6.5.2 Recent Proposals Colonial continually examines their training programs and, when necessary, makes changes toimprove their program. Colonial is currently proposing significant changes to their program. Among the recommendations is the implementation of a new computer program to replace the existing PIPE program.This new system, known as PRISM, will be an improvement over the current system in many ways. The new system will allow the Operations trainer to efficiently access the training records to determine where deficiencies exist and allow notices to be sent to the employees so that theymay address these deficiencies. With PIPE, while it is possible to do this, it is very cumbersome and, according to the Operations Trainer, not performed. The new program will randomly access a database of questions thus eliminating the robotic approach of answering the same questions.year after year. The TSCT is in the final stages of implementing a pipeline control simulator. This will providethe Controllers an opportunity to train in simulated emergency or abnormal situations. The intent is to require a minimum amount of time per year per Controller on the simulator to maintain competence in these situations. The simulator is planned to be operational by the end of the 1997. The training team is looking into better ways to evaluate the employees. For example, there is no mechanism to evaluate operators following a promotion or transfer. They are currently developing a follow-up technique. 12 See Section 6.5.2 13 Taken from Team Charter 59

O January 10, 1997 OPS Task Force Report- Colonial Pipeline Company7.0 Recommendations and Findings7.1 RecommendationsBased on this in-depth examination of Colonial, the Task Force has concluded that Colonial andOPS need to take a comprehensive, risk-based approach to ensuring the safe andenvironmentally sound operation of the pipeline and makes the following recommendations~Support for the recommendations can be found in Section 7.2. Each recommendationreferences the related findings that led to these recommendations.OPS will produce an action plan to implement these recommendations, including anycompliance actions, forty five days from the publication date of this report.Recommendation No.1: Colonial should perform an Operational Reliability AssessmentORA of their entire pipeline system mainlines~ stub lines, delivery lines and associatedfacilities to assess and assure the system integrity. An ORA would comprehensively assessColonial's operation and maintenance of the entire pipeline system and determine what steps, ifany, should be taken to minimize the probability of a failure and mitigate the failure. As anintegral part of this assessment, OPS and Colonial should continue to support undergroundutility damage prevention programs one call systems. [Related findings: 1, 2, 7, 8, 19, 38]Recommendation No. 2: Colonial needs to develop a comprehensive management approachto the operation and maintenance of their pipeline system. Colonial needs to improvecommunications between field locations and headquarters and develop ways to assure thatgood ideas and lessons learned are shared throughout the company. Of particular concern isthat Colonial should update their maintenance manuals to eliminate conflicts, and see that allprocedures are followed. In addition, the training program should incorporate feedbackinformation to determine the effectiveness of the training. [Related findings: 3, 5, 9, 12, 15, 24,28, 29, 30, 31, 32, 33,34, 35, 36, 37, 39, 40, 41, 42, 43, 44, 45, 46, 47]Recommendation No. 3: Colonial needs to operate their SCADA system with less manualintervention by implementing available computer technology. Colonial is now upgrading theirSCADA system and should take advantage of this opportunity to make further improvements,such as providing threshold points in the SCADA for the Controllers to base a suspicion of aleak, use standardized or consistent colors on the displays, and refine those displays to achievethe most effective and informative format. [Related findings: 6, 13, 16, 17, 18, 25]Recommendation No. 4: Colonial needs to insure that operating practices are consistent andfollow written procedures. In addition, Colonial should create a stronger continuity andcompleteness in the implementation of operational change controls and insure that a thoroughanalytical operation review process is in place. [Related findings: 10, 11, 14, 20, 21, 22, 23,26, 27]Recommendation No. 5: OPS should expand its multi-region comprehensive inspections ofpipeline companies that traverse more than one OPS Region. Separate inspections ofdifferent sections of a pipeline operator's system may not provide a comprehensive integral 60

O January 10, 1997 OPS Task Force Report Colonial Pipeline Companyassessment of the pipeline system and do not always provide an opportunity to develop acomprehensive understanding of the system. A global perspective will allow the OPS to focuson problem areas and apply targeted expertise where needed. [Related findings: 4]7.2 FindingsThe following are the specific findings discovered as a result of the Task Force's investigation.Each finding is followed by a reference to the specific section of the report where the findingrelates.7.2.1 GeneralI. colonial has reported 194 accidents to the OPS. Their accident rate is one of the highest in the HLP industry. The June 26, 1996 accident near Simpsonville, SC is Colonial's largest reported spill. 3.3.12. Colonial has been a strong supporter and participant in one call systems. In states that lacked a one call program, Colonial and OPS have promoted the establishment of these programs. OPS has provided grant funds to states and one call systems to initiate and enhance excavation damage prevention programs. 3.23. There are four open compliance actions which have significant portions of work remaining to be resolved. Among these are the ILl of the mainlines, evaluation of Colonial's pipeline designs and evaluation of Colonial's over-pressure protection equipment. 3.3.34. Colonial has been issued 17 compliance actions as a result of standard inspections. No discemable trends were found in the standard inspection compliance actions. Only one relationship could be identified between the standard inspection compliance actions and the accidents Colonial has experienced - corrosion. 3.27.2.2 Operations5. Colonial's headquarters engineering staff has been reduced by 45%. 4.26. The size and thai-put rates of Colonial's pipelines have a tendency to generate very volatile swings in volume line balance, making it difficult for the Controllers to perform a manual volume line balance. There are no formal guides or threshold points for the Controllers to base a suspicion of a leak. 4.3.27. During the General Physics interview, the Controller stated that on the day of.the incident he thought that the situation at Reedy River was not as serious as it had been. 4.3.38. Thermal strip chart recorders have solved the maintenance problem of the former clogged ink well units. However, these recorders only print in black, making it sometimes impossible to distinguish the path of an individual data line among others on 61

O January 10, 1997 OPS Task Force Report Colonial Pipeline Company the same recorder. Colonial stated that they have decided to replace the thermal-paper recorder with multi-color units. 4.4.19. Roanoke's pressure chart scale of 0-1,000 psig does not permit the station to record pressures that may approach or exceed the segment's MOP of 1,305 psig. 4.4.310. Missing Controller reports represent 28% of the total numberof reports and are identified as "none filed" in Appendix C-i. 4.5.2ii. Colonial indicates that there is no longer a position in the organization to review malfunction reports and analyze outage trends. Reports are being used to trigger maintenance efforts, but no one is currently doing a trend analysis. 4.5.212. Due to the dead band of the high line pressure switch, multiple pumps may trip on a high line pressure unnecessarily. 4.6.113. The Line 2 Controller encountered 79 alarms during the first ten minutes surrounding the Reedy River accident. Colonial has not performed a recent study of their current alarm practices. 4.6.314. A review of the operating pressure data showed that during a 15 day period preceding the Reedy River accident, Controllers routinely violated the 100 psig maximum suction pressure limit at the Simpsonville Station. 4.6.315. There is an inconsistency on the upper limit of tank alarm during fill. Those locations to the west or south of Greensboro, NC will terminate the delivery prior to maximum fill level alarm. Those locations to the east or north of Greensboro, NC will terminate the delivery when maximum fill level alarm is achieved. 4.716. Colonial has intentionally designed their SCADA system to require a manual dial-up to remote RTU's when the primary communication path is lost. Controller must initiate backup communication when they deem necessary. 4.8.117. There are inconsistencies in use of color on the SCADA displays. 4.8.218 Controllers performing similar tasks do not use the same set of displays. 4.8.219. The in-house transient model does not accurately account for the varying specifications of the installed high line shutdown pressure safety switches. 4.9.120. There is no audit or report function within the transient model to detail the segment parameters. 4.9.221. Colonial has no written guide to direct coordination and implementation of MOP changes across the organization. 4.9.222. There were four changes made to the Line 2 operating parameters over a six week 62

O January 10, 1997 OPS Task Force Report Colonial Pipeline Company period, repetitive changes may be confusing and result in operating parameter errors. 4.1023. The Colonial directive to limit Simpsonville Station to no more than 5,000 hp was lined out of a Colonial memo. At the time of the Reedy River incident the Simpsonville Station was operating to 7,000 hp. 4.1024. The inlet pressure instrument at Murfreesboro station may be inappropriately isolated from the mainline and convey a false reading to the Atlanta Controller. 4.1125. The Controllers SCADA display for Murfreesboro does not reflect the actual configuration of equipment at the station. 4.1126. Over-pressure protection on the Murfreesboro line segment did not actuate to relieve excessive line pressures. The pressure safety equipment at Coalmont and Murfreesboro were apparently not designed and/or calibrated property. 4.1127. The main line block valve relief settings for stub. lines are not included in the System Operating Pressure Limits Manual. They should be in the manual. 4.117.2.3 Maintenance28. The contents of Colonial's D.O.T. Reference Guide do not agree with the Preventive Maintenance. 5.329. An analysis of Colonial's Form 3308 is no longer being performed by Engineering Services, although it is required by the D.O.T. Reference Guide. 5.330. Colonial does not consider the lR drop when evaluating the level of cathodic protection. 5.3.1.131. Colonial does not use company employees to conduct the annual cathodic protection surveys. This work is contracted with no assurance that the same personnel will perform next year's survey. This places a weighty burden on the Corrosion Managers. The Corrosion Managers are overlooking a few anomalies from the annual surveys. Moreover, the remediation lists are not being prepared. 5.3.1.132. There is no reference in Colonial's Procedure 3305, Pipe Inspection Report, to Procedure 2546, Reporting Safety-Related Conditions. A reference is required because calculations should be performed using Procedure 2546 to confirm that the pipe is safe or that it needs repairs or replacement if serious corrosion is found and recorded on Form 3305. 5.3.233. Colonial has initiated a program to correct the tank bottom corrosion problem at Linden, NJ. Colonial is installing anodes and monitoring equipment underneath the tanks but to date not all the tanks have been retrofitted and the system may not be effective when the tanks are empty. 5.3.4 63

O January 10, 1997 OPS Task Force Report Colonial Pipeline Company~4. Colonial's uses two procedures, Foreign Line Crossings Form 3004 and Change Diagrams Form 3331, to incorporate field changes to the original drawings. The procedures do not specify a time interval to incorporate the changes to the original drawings nor do they specify how the revised drawings are to be distributed. All key Teams involved in the safe operation are not being informed of changes that have been made in the field. 5.535. A step by step description of Colonial's ILl Program is not estab~shed in a written guide. Each individual or group is well versed in the necessary tasks, but there is no complete listing and sequence of the overall process. 5.8.436. The repair completion period of ILl projects is dependent on a number of factors associated with each specific project, and is typically from 1.5 to 4 years in duration. Extended remediation periods are usually applied to low level moderate and light anomalies dependent on available resources. 5.8.537. Colonial has scheduled time to perform TSI review is only on those ILl logs shown in Table 5.8, some of which have been ordered by the OPS. 5.8.538. The OPS recently required Colonial to utilize the ultrasonic ILl crack tool to inspect those portions of the original mainline from Pasadena, TX to Linden, NJ, where National Tube and Republic Steel were the pipe manufacturers, within a five year period. 5.8.639. Colonial's Field Maintenance groups assume a lead role in anomaly investigations and associated remediation. Although headquarters personnel remain available for assistance, they have not tracked ILl remediation projects since the reorganization. 5.8.77.2.4 Training40. Colonial's on the job training program is not consistent in what is related to new employees. Colonial does not perform a direct check on what the employee learns Evaluations are filled out by the Operations Manager not the trainer. 6.3.141. The completed Operator Training Guide is not reviewed with the employee. 6.3.142. There is no formal evaluation program to determine the qualification of the pipeline maintenance or technician personnel following on the job training. 6.3.143. The Transportation Services Team has invested all their energy in the production of a pipeline simulator, other viable means of abnormal or emergency training is not being pursued. Subsequently, training in abnormal or emergency situation is negligible. There is some uncertainty in the ability of a simulator, and another method of training would be necessary if the simulator fails. 6.5.244. Colonial has not established a minimum requirement for the Relief Controllers to maintain their certification. 6.3.2 64

O January 10. 1997 OPS Task Force Report Colonial Pipeline Company45. The PIPE tests are not checked by the local supervisors, nor by the Operations Training Coordinator. The results of the PIPE tests, were checked by the Task Force for 1995 and nearly 41 % of the employees who were required to take the tests did not fulfill their obligation. The CCEP test are no longer being taken. 6.3.446. There is no formal evaluation program following transfers in field operation positions. 6.3.147. Colonial did not have any procedure for verifying that the supervisors had an understanding of the procedures for which they are responsible. 65

Appendix A Table A-I Colonial Pipeline Company Organization Authorized Complement Before and After Re-EngineeringOrganizationCirca 4194OrganizationCirca 1196PercentChangeAuthonzed Complement 718 [Actual 711] Headquarters 231 Field Offices 487Authorized Complement 673 Headquarters 188 Field Offices 485-6%-19%+1%Executive 7 President 1 Vice Presidents 2 Staff 4Leadership Team 5 President 1 Vice Presidents 2 Staff 2-Engineering 60 Director 1 Engineers Mechanical Group 6 Electrical Group 5 Project Eng. Group 4 Specialists 2 Environmental 8 Regulatory 4 Communications 3 Drafting 6 Mapping 3 Network 1 Admin. Staff 3 Process Computer Engineer 3 Staff 9 Contractors 1~ . - .Technical Services Team 22 Leader 1 Hydraulics 1 Project Engineering 6 See Environmental Team Regulatory 3 ~ Mapping/Drafting 7 ~ * Network included in IS team Admin Staff 1 - Process Comp. included in TSCT Purchasing 3-32% . .Environmental Team 17 Leader 1 Project Managers 7 Technicians 8 Admin Staff 1Information Systems 21 Manager 1 Supervisors 6 Programmers 9 Engineer 1 . Staff 4Information Systems Team 17 Manager 1 Programmers 7 Network 3 Telecommunications 2 Trainer 1 Staff 3-19% .Aviation 6Aviajion Team 7

Human Resources Department 10 Manager 1 Safety/Training 5 Public Affairs 2 Staff 1 Contractor 1Human Resources Team 14 Director 1 Safety/Training Team 5 Staff 2 Contractor 2 Employee Resources 4+14% . .Employee Relations Department 9Benefits Team 4Legal Department 14 . Right of Way 4 Attorneys 3 Staff 7Legal Team 13 Public Relations 2 Right of Way 3 Attorneys 3 Staff 3 Auditors 2-Internal Auditing 2Financial Division 5Financial Services 17 .-Accounting 14Purchasing 11Purchasing included in Technical ServicesPlanning & Business Development Department 6Performance & Development 5-Operations Control Department 8 Manager 1 Quality Assurance 6 Col1tractor 1Transportation Services Central Team 68 Manager 1 Quality Assurance 3 Admin Staff 1Pipeline Control System Team 15 Controller Super 4 Controllers 30 Power Op 3 . Schedulers 9 Customer Relations 1-Operations Planning and Pipeline Control 42 Controlling Super 3 Controllers 29 Power Op. 3 Engineering Staff 4 Staff 2 Contractor 1Scheduling & Shipper Relations 16 .Regional Staff -2 Regions 487 Managers 13 Supervisors 41 Engineering 10 Corrosion Tech 4 Admin Staff 13 Maintenance Staff 31 Environmental 9 Right of Way 1 Operations 286 Technicians 77 Quality Control 1District Staff -4 Districts 485 Team Leaders 8 Operations Mgrs. 24 Project Manager 1 7 Corrosion PM 4 Admin Staff 11 Project Inspector 38 * See Environmental Team Right of Way 4 Operations 291 Technicians 78 Quality Control 1+1%~

Appendix B Table B-I Hazardous Liquid Pipeline Reported1 Major Spills By Date 1996 -1990OperatorDateVolumebbl.Type ofFailureCause1 Promix LLC10/26/965900PipelineCorrosion.2 Lakehead Pipeline Co.. Inc.08/24/965000~pelineCorrosion3 Colonial Pipeline Co.06/26/9622800PipelineCorrosion4 Marathon Pipeline Co.05123/9611308PipelineOutside Forces5 Arco Pipeline Co.05/20/965080StationOutside Forces6 Chevron Pipeline Co.03/11/966565PipelineCorrosion7 Diamond Shamrock Refinery02/17/966355PipelineOutside Forces6 Mobil Pipeline Co.9 Marathon Pipeline Co.11103/9506/16/9592005264PipelineStationMechanical DamageFailed Pipe10 Texaco Trading & Trans.01/02/9530000TankFailed Weld11 Colonial Pipeline Co.10120/9420000PipelineOutside Forces12 Colonial Pipeline Co.10/20/9410000PipelineOutside Forces13 Mid-America Pipeline Co11/05/947237PipelineOutside Forces14 Texaco Pipeline Inc. 10/21/94 535015 Conoco Inc. 03/10/94 9000PipelinePipelineOutside ForcesOutside Forces16 Mid-America Pipeline Co 02/01/94! 6720StationEquipment Malfunction17 Emerald Pipeline Co. 06/04/93~ 5277PipelineOutside Forces18 Gulf Central Pipeline Co. 05/04/93~ 5692PipelineMechanical Damage19~Ashland Pipeline Co. 05/01/93 5016PipelineFailed Pipe201 Four Corners Pipeline Co. 04/06/93 6200 PipelineFailed Weld21_Koch_Pipeline Co. 03/29/93: 6600L Tank22~CoIonial Pipeline Co. 03/28/93: 9708 PipelineOtherMechanical Damage23ITexas Eastern Product P/1 03/27/93 7560TankOperator Error24IBelle Fourche Pipeline Co. 10/12/92 6000PipelineOutside Forces25 Coastal States Crude Gathering 10/12/92 6500PipelineCorrosion26tKoch Pipeline Inc. 03/29/92 67131PipelineOutside Forces27~Sigmor Pipeline Co. 01121/92 6415~PipelineFailed Weld -28 Amoco Pipeline Co. 01/17/92 5000PipelineCorrosion29lWilliams Pipeline Co. 01/13/92 7200PipelineFailed Weld30! Platte Pipe Une 01/09/92 5375PipelineFailed WeldColonial Pipeline Co. 12/1 9191 13100PipelineMechanical32!Chevron Pipeline Co. 08/29/91 5840PipelineMechanical Damage331D - S Pipeline Corp. 07/07/91 6235PipelineOutside Forces34~Amoco Pipeline Co. 06/30/~1 28200PipelineCorrosion35 Koch Gathering System Inc. 06/1419 1 5290StationEquipment Malfunction -36!Shell Pipeline Co. 04/07191 8150PipelineFailed Pipe37lMobil Pipeline Co. 03121/91 5359PipelineFailed Pipe38!Lakehead Pipeline Co. 03/02/91 40500PipelineOther39IFour Corners Pipeline Co. 03/19/90 12000TankEquipment Matfunction4OtExxon Pipeline Co. O2/13/90~ 20027PipelineCorrosionData from OPS Database.

Appendix. B Table B-2 Colonial Standard Inspections Compliance ActionsCPFDATEACTION2508W1979WarningMissed River Xing Inspection, Missing CP Test Station, Atmos. Corrosionon Valve.2N01231984WarningMissed River Xing Inspection2VV01201984WarningMissed River Xing Inspection4W03001984WarningRelief Vlv. lnsp. Interval too long per procedure & regulation. Atmos.Corrosion on Breakout Tanks2W01431985WarningLow Cathodic Protection Potentials2510Closed1988FOCP$15,000fi 195.401b: 402a; 402ab; 402b; 416a; 416a; 420a;1094Closed1988FOCP$10,500ß195.416b1103Closed1989FOCP~$ 5,000ß~195.430; 402a2W01 311989WarningRight-of-way not inspected2W02671989WarningMissed Main Line Valve inspection Intervals21502Closed1991FOCP$3,000ß195.41222501Closed1992FOß 195.412b22506W .1992 .WarningRelief VIv. lnsp.. Interval too long per procedure & not regulation, Atmos.Corrosion on Breakout Tanks23501W1992WarningRelief Vlv. Insp. Interval too long, Incomplete Relief VIv. InspectionRecords25505W1995Warning.Internal Corrosion Procedure is not updated, Improper Pubic OfficialLiaison25506W1995WarningBreakout tank not inspected, 0 & M not kept up to date. Cath. Prot. - IRdrop not considered26500Open1996NPVPCPNOA$8,500~ 195.402; 404420; 428; 242, ß199.7; 202 ~Note: CPF Compliance Progress File. Warning Warning Letter, FO Final Order, NPV Notice of ProbableViolation, PCP Proposed Civil Penalty & NOA Notice of Amendment. Warning letters are considered closedwhen issued

Appendix B Table B-3 Colonial Accident Compliance ActionsCPFDATETYPEIncidentViolationsRequired Actions2508ClosedNov 1979FOMay 1979June 1979Greenville. SCß 195.406a1Over pressure* 14% pressure restriction. .1031ClosedMay 1980FOCOMarch 1980Manassas, VA andOrange County, VAß195.401UnsafeOperation`.7% pressure restriction.* Stabilization of hydraulic gradient.* Inspect casings for corrosion, make correctiveactions. .I 0504AOpenSee 14501.HAug 1990Jan 1994 .TestingPlanDec. 1989Orange County, VA* Operational Reliability Assessment Line 04.* Hydro test National Tube Pipe: Chantilly, VA toDorsey Jct., MD.* Pressure restriction.21505-HClosed .Dec. 1991HFODec 1991Simpsonville, SC..HFO - Simpsonville, SC to Gaffney, SC.* Pressure restriction.`Metallurgical examination of failed pipe.13503-HOpenSee 14501.H.Mar. 1993 .HFOMarch 1993Reston, VA~ . .~HFO - Chantilly, VA to DorseyJct., MD.* Extensive ILl Program.* Pressure restriction- 20%.* Metallurgical examination of Pipe.* Inspect for top side damage, corrective actions.44508OpenMay 1994NPV .PCPFeb 1994Baton Rouge, LAß 195.406bOver pressureProposed Civil Penalty $ 25,000.14501-HOpen.Aug 1995FOCO. ~Dec. 1989Orange County. VAMar 1993Reston, VA. , .Consolidates I 0504A and 13503-H.* MFL Pig 36" pipeline Greensboro. NC toDorsey Jct., MD.* MFL Pig 32" pipeline Greensboro; NC toDorsey Jct, MD.``Crack' Pig 32" Louisa, VA to Dorsey Jct, MD.* Various ILl tool runs through year 2000.26503-HOpen .Jul 1996HFO..June 1996Simpsonvilie, SC*HFO - Original Pipeline Houston to Linden. NJ.* Pressure restriction.* Repair observed pig anomalies.* Evaluate pressure switches and take requiredaction.* Run Crack pig in original mainline withNational Tube and Republic steel.26505OpenOct. 1996NPVPCPJune 1996Macon, GAß 195.54Late ReportProposed Civil Penalty $ 1,500. .26506OpenNov. 1996NPVPCPPCONov. 1996Murfreesboro, TN . .ß 195.406bOver pressureProposed Civil Penalty $ 25,000.* Evaluate SCADA displays, corrective actions.* Evaluate system design, corrective actions.I Note: NPV Notice of Probable Violation, FO Final Order, HFO Hazardous Facility Order, CO Consent Order, PCP Proposed Civil Penalty.

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Appendix B Table B-5 Largest HLP Reported SpIlIslOperatorDateVolumebbl.Type ofFailureCause1Mid-America Pipeline Co.04/04/87122000StorageEquipment Malfunction2Phillips Pipeline Co.09/04/8655000TankUnknown3Lakehead Pipeline Co.03/02/9140500PipelineOther4Lakehead Pipeline Co.07/13/8931300PipelineFailed Pipe5Texaco Trading & Trans.01/0219530000TankFailed Weld6Amoco Pipeline Co.06/30/9128200PipelineCorrosion7Amoco Pipeline Co.06/11/8724000PipelineOther8Texaco Pipeline Co.01/24/8923534PipelineFailed Pipe9Colonial Pipeline Co.06/26/9622800PipelineCorrosion10Shell Pipeline Corp12/24/8820554PipelineFailed Pipe11Exxon Pipeline Co.02/13/9020027PipelineCorrosion12Colonial Pipeline Co.10/20/9420000PipelineMechanical Damage13Texaco Inc 05/30/8719150PipelineMechanical14Total Pipeline Co. 04/16/8718000TankOther15 Texas Eastern Products 08/15/8616~Amoco Pipeline Co. 02/08/881729415000PipelinePipelineOutside ForceOutside Force17 Chevron Pipeline Co 10/0718614000TankOperator Error18~Colonial Pipeline Co. 12/19/9113100PipelineMechanical Damagel9lLakehead Pipeline Co. 04/24/8612500PipelineMechanical20t Four Corners Pipeline Co. 03/19/9012000Tank DamageEquipment MalfunctionITexaco Trading & Trans. 12/22/85i 12000Total Pipeline Co. 12/18/89' 12000PipelineFailed Pipe`Data from OPS Database 1985-1996

Appendix B Table B-6 Hazardous Liquid Operator Accident Rate Comparison - 1987 - 19961MilesA~t~t1987198819891990199119921993199419951996IndustryN/AN/A237193163180216212230244188130CoIoniaI531700015034471314131525Operator A72250.0013718191610778563Operator B72040.00106847333423138Operator C71370.0011216119512113850Operator 071180.001052515137820005Operator E65290.0011612849111210532Operator F61350.000988798849601OperatorG55230.0008912637433920OperatorH54090.002352416916141617645Operator I52450.000690331453944Operator J36520.0014271163852712Operator K32890.000880341524442Operator L31200.0014752612910632Operator M27330.001021012375333Operator N26880.0016053134451710Operator 026340.0013754~52132743Operator P14130.000710111010222* Pipeline Operators having a significant mileage of pipe with D/t ratio greater than 70. Data from OPS Database 2 Average # of accidents per mile per year.

Appendix B Table B-7Hazardous Liquid Pipeline Operators Accident Cause Comparison: 1968 - 19961IIIIIIIIIICorrosionFailed Pip.FailedWeldOperator ErrorMalfunctionOtherOutsIdeTotal1968-1969420593626Accidents46%6%4%3% -*21%1859171970-1 97455277859920%37%5%6%6%-33135114951975-1979295504023%24%4%3%7%-34038012181980-198425233245328%31%25%3%2%5% -.286342990198554701529%35%30%4%0%8%1%5228%5329%1831986541381226%6%4%6%251692091987701561024%33%29%6%2%4%83%6563237 *19885511613727%4626%5528%5%3%6%3%1931989341381293528%5220%8%4%7%5%21%31%16319905114 j 510114828%7%I 2%5%6%180199166101513184022%5430%4%6%6%8%21619924311151118%6225%20%5%7% 7%5%21219935510 7 151729%6725%23%4% 3% 6% .7 %29%5923019944911 21 8 227620%4% 8% 3%9%31%5724419953614 9 26523%19%7% 4% 13%2%45531881996528 7 728%32%5% I4242164HLPTotaI.2138356 292 4224%11826%26%1911 f_703927%30%5% 4% 6%2%25%Colonial242 6 . 3708012%1% 3% 19%0%47194Data From OPS Database.

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Appendix C Figure C-4 Controller's Strip Chart Display Typical £1~I *`~i~*RSO2 BRJO2 RSO2 ATHO2CLD PPL CLL 9.38 KOB PAB 1 1FEB02 MCBO2 COBO2 CLDO2 PPLO2 CLLO2 KOBO2 PABO2 MDDO2DNBO2 ANBO2 BUO2 SIBO2 SPTO2. GFBO2 GABO2 CR102 KABO2MDBO2 EPBO2LEBO2 GBJO2DOT-I349 426 374 407369 383503, 439j~-`-ii--J~I-..."..--~-..."."_I~ -11~-j~----l`1... BRSBRJ12.3FEB MCB 1COBMDD MDBEPB2

Appendix C Figure C-5 Controller's Real Time Nomograph RTN Screen Typical I~ ___ A~B BU ~IB J02 FEB02 MCBQ2 COBO2 CLDO2 PPLO2 CLLO2 KOBO2 PABO2 MDDO2 MDBO2 EPBO2 S02 ATHO2 DNBO2 ANBO2 BUO2 SIBO2 SPTO2 GFBO2 GABO2 CRTO2 KABO2 LEBO2 GBJO2 DOT-.GAB4CRT KA~

Appendix D D-1. Colonial Pipeline Company Maintenance Procedures Table of ContentsI Unit and Main Circuit Breakers Metalclad Switchgear Motor Control CenterI 48 Volt DC Power System Motor Powered Valve Operators Hydraulic Gate Valve OperatorsI Indicon Vibration Monitors GPE Control System - Cabinet Type GPE Control System - Unit Regulator TypeI Mason Neilan Control Valves Ball Control Valves - Custom Controls Hyd Operator Pressure Transmitters Station RecordersI Critical Pressure Switches Pressure Switches Automatic Tank GaugingI Tanks Tanks Line Pig SigsI Main and Lateral Line Motors Main and Lateral Line Pumps Buffalo Protective SystemI Central Hydraulic System Metering Equipment Pressure Relief Valves Variable Speed DriveI Metering Thermometers Protective Relays Reserved for Future Use.I Reserved for Future Use Reserved for Future Use Reserved for Future UseI Reserved for Future Use Station/Unit Protection CheckoutMP 1- Page IMP2-PagelMP3-PagelMP4- Page 1MP5-PagelMP6-Page 1MP7-Page 1MP8-PagelMP9-PagelMPIO-PagelMP1I-PagelMP12-PagelMPI3-PagelMP 14- Page 1MP 14- Page 3MP 15- Page 1MP 16- PagelMPI6-Page5MP 17- Page 1MPI8-PagelMPI9-PagelMP2O-PagelMP2I-PagelMP22-PagelMP 23- Page 1MP24-Page IMP25-PagelMP26-PagelMP 27- Page 1MP 28- Page 1MP 29- Page 1MP 30- Page 1MP 31- Page 1MP 32- Page 1

Appendix 0-2 COLONIAL PIPELINE COMPANY DOT REFERENCE GUIDE INDEX Subject Matter Form Page No. Evaluation of Training Objectives 1.1 I Distribution List 1.2 Completion of DOT Reports 1.3 Routing of DOT Reports 1.4 I Retention of DOT Reports 1.5 Compliance Index 1.6 Reporting Safety Related Conditions 2546 2.1 I Foreign Line Crossings 3004 3.1 Notification Procedure for - R-O-W Excavations 3.4 Break, Leakorlncident 3014 4.1 I Unscheduled Line Shutdown 3020 5.1 Pipe Inspections 3305 6.1 Mainline/Lateral Line Valve Inspections 3306 7.1 I Tank Inspections 3307 8.1 Critical Equipment Maintenance Schedule 3308 9.1 * Relief Valve Inspections 3309 10.1 I Pipeline Anomaly SEE FORM 3305 3311 11.1 Change Diagrams 3331 12.1 Rectifiers, Bonds, Polarization Cells 3340 13.1 I Nondestructive Testing 3351 14.1 Bonding Information 3352 15.1 Cathodic Protection Layout 3353 16.1 `I. Visual Inspection of Above Ground Piping 3354 17.1 Notification of National Response Center 3355 18.1 Casing Reports 3361 19.1 Hydrostatic Testing - Emergency Pipe 3365 20.1 I Dispatching Malfunctions 3533 21.1 Inspection of Fire Protection Equipment 7051 22.1 Potential Survey 23.1 I Pipeline and Facility Abandonment 24.1 Hydrographic Inspection of Waterways 25.1 Moving Operating Pipelines 26.1 I Signs and Markers 27.1 Corrosion Control Procedures 28.1 Training Guide for Reading Cathodic I Protection Devices 29.1 Maintenance Procedures for Cathodic - Protection Rectifiers 30.1 Public Information Program 31.1 Inspection of Pipeline ROW 32.1

Subject Matter Form Paae No. CFR Title 49, Part 190 Pipeline Safety Procedures CFR Title 49, Part 195 Transportation of Hazardous Liquids by Pipeline* CFR Title 49, Part 199U Drug & Alcohol TestingASME 831.4 Liquid Transportation Systems for Hydrocarbons, Liquid Petroleum Gas, Anhydrous Ammonia, and Alcohols

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Appendix G Current OPS Proje~ts. Proposed RulemakingsI OPS is pursuing regulatory changes that willenhance the pipeline industry an make it one of the safest modes of transportation. The regulatory projects being pursued by OPS include:I. PS-lOlA Mandatory Participation in Qualified One-Call System by Pipeline Operators - The intent of the rule is to require operators of onshore gas, hazardous liquid and carbon dioxide pipelines to participate in qualified one-call systems as part of theI required excavation damage prevention programs. Final rule is being prepared for publication. P5-94 Qualification of Pipeline Personnel - The intent of the rule is to ensure thatI persons performing safety-related operations, maintenance and emergency response be "qualified by the operators~ A committee is being formed to conduct a negotiated rulemaking.I. Ps-i 30 Response Plans for Onshore Oil Pipelines - The intent is to increase response capabilities and minimize environmental impact of onshore oil spills from pipelines. A public hearing is being planned.I. PS-133 Emergency Flow Restricting Devices EFRD - The intent of the rule is to prescribe the circumstances under which an operator of a hazardous liquid pipeline facility must use an EFRD or other such procedure, system or equipment. NPRM` expected to be published in 1997. PS-141 Increased Inspection Requirements -. The intent is to prescribe circumstances in which a liquid operator must perform ILl of their pipeline. Final action is expected in 1997.I . PS-i 21 Pressure Testing of Older Hazardous Liquid and Carbon Dioxide Pipelines - On June 7, 1994 RSPA issued a final rule that required the hydrostatic pressure testing of certain older hazardous liquid pipelines that were never tested to current standards.I The compliance deadline has been extended to consider risk based alternatives. PS-144 Risk-Based Alternative to Pressure Testing Rule - OPS will propose ILl as an alternative to hydrostatic testing. NPRM publication proposed.I. PS - not assigned Design and Construction of Welded Breakout Tanks - OPS proposes to adopt API standards for tanks in 1997. Study of Pipeline Infrastructure - The Office has contracted with New Jersey Institute of Technology to examine the pipelineI industry's infrastructure and other related issues. In a recent publication NJIT looks at Parts 192 and 195 and compares the US regulations to pipeline regulations in other countries. This is one of the most comprehensive comparison of foreign pipeline standards to U.S. pipeline safety standards that has ever been conducted. The report, which compares pipeline safety regulations from Canada, Australia, the UnitedI Kingdom, Germany and Japan with the United States Regulations, demonstrates that the regulations are quite similar in their approach to the design, construction, and operation of 1 of 3

pipelines located in close proximity to densely populated and/or environmentally sensitive areas. The report also highlights the different concepts found in foreign regulations but not in the United States regulations such as life of pipeline, fatigue life, third-party factors and use of on-line instrumentation for leak detection and earthquake movement. The OPS will consider these in future rulemaking actions where applicable.The major differences between the United States pipeline safety regulations and some of the other foreign regulations are the concepts of pipeline life, fatigue life, and third-party factors which are found in the Australian or United Kingdom's regulations, and the employment of onhin-e leak detection equipment and earthquake impact measuring equipment in the Japanese regulations. Although the concepts of pipeline life, fatigue life, and third-party factors are not explicitly noted in the United States regulations, one can argue that third-partyfactors areindirectly accounted for through the requirements for patrolling and the use of markers along pipes, as well as by the damage prevention programs required in the regulations. Also, the concepts of design life and fatigue life of pipelines, while not directly articulated in the UnitedStatesregulations, can be indirectly tested through findings from the use of leakage surveys as required in the regulations, or if there are any changes required or requested in the class location with time and/or a desire for operators to upgrade the pipeline which would necessitatepressure testing of the lines. However, if no leakage is noted, and no changes are contemplated in the operation of the pipeline, the concept of the life" of the pipe is not directly. or indirectly addressed in the United States pipeline safety regulations. NJIT also has submitted abstracts from over 900 articles on the pipeline industry based on an extensive literature search. They are also documenting their exhaustive review of the RSPA,pipeline accident, incident, and annual data along with recommendations on improving data collection and are proposing to set` up a computer program for operators to use to electronically file accident reports with OPS. This would standardize data entry and provide on-line help for assisting with completion of the reports. Applied Research to Pipelines Leak before Rupture Currently, OPS has contracted with Texas Transportation institute to investigate the U. S. Code of Federal regulations CFR for the maximum allowable operating pressure of transmissionpipelines. Current regulations may not preclude a large-scale rupture of gas pipelines or a large-scale leakage from a hazardous liquid pipeline due to unstable growth of a through crack. The specific objective of this research was to develop procedures to apply fracture mechanicsconcepts, in particular leak before rupture, to hazardous liquid and gas pipeline. Researchers studied the circumstances in which ruptures can occur in pipelines which have been designed and are operated according to the regulations, but have developed cracks due to third party damage and/or fatigue, corrosion, or stress corrosion cracking. 2of3

In hazardous liquid pipelines, X60 steel, which has a very good toughness as measured by resistance to crack growth in a J-R curve, would appear to give leakage rates as a percentageof throughput that could be easily found prior to rupture for all CFR Class 4 locations. On the other hand, X52 steel, which has a much lower resistance to crack growth, gives lower rates at the critical flaw-site that are at or below 8% of throughput, which is assumed to be the level ofreliable detection, for three of the four diameter to thickness ratios considered. These pipelines would appear to be at risk to develop through-cracks that could grow undetected to a size sufficient to give rupture. However, if the period of time between the formation of a throughcrack and its growth to a critical size to give rupture is long enough, as it might well be, then the cumulative leakage may still give ample opportunity for the existence of a through-crack to be detected prior to catastrophic rupture. The final report is expected early 1997. Dent Crack Acceptability OPS has contracted with Texas Transportation Institute to analyze recently completed or in-progress ~dent/crack acceptability" research to determine if an acceptance level exists for dents and cracks in on-shore pipelines. Any discrepancies in findings can be resolved through additional research and recommendations can be developed for OPS review regardingrestrictions on the operation of an onshore pipeline containing dents, whether smooth or containing damage, considering both static and dynamic loading. Current criteria for allowable * dents in pipelines are contained in industry codes and standards ASME B31 .4 and B31 .8. Those criteria were developed on the basis of tests conducted by subjecting pipelines to static loads. Concerns have been raised that dents accepted per current criteria will fail under fatigue loading. The contractor will analyze recently completed or in-progress research on dent/crack failure behavior to determine acceptance levels for dents. Areas of discrepancies will be identified and research performed to resolve those discrepancies, either by test or by theoretical calculation. The Contractor will conduct failure tests of twelve 12 to fifteen 15 pipe to determine the behavior of typical onshore pipeline dents plain and containing damage whensubjected to cyclic pressures representative of gas and hazardous liquid pipeline operation; and develop criteria for determining the acceptability of dents in operating pipelines, both gas and hazardous liquid. This study is to be completed within 12 months of contract award. The report is expected Mid-1997. In-Line Inspection Technology OPS has contracted with Battelle Memorial Institute to study MFL technology. Mechanicaldamage Third Party Damage is a leading cause of pipeline failures on both liquid and natural gas. While there are several commercially available inspection tools to detect mechanical damage, little is known on what types of damage is not detected. Previous GRI research haslookedinto the use of MEL tool to find dents and residual stresses, cold working damage and residual stresses and metal loss. This research has made some relationships between mechanical damage and MEL signal strength. This latest research will address advancing MELS technology for mechanical damage and cracks. There initial research is encouraging and their final report is expected by late 1998. 3 of 3

Appendix H H-I Glossary of TermsAFE Authorization for Expenditure.Anomaly An indication or feature on or within a pipe that is abnormal.API American Petroleum Institute.ASME American Society of Mechanical Engineers.Bad Data Data which does not accurately indicate the actual field reading.Bare Pipe Pipe without an external coating to inhibit corrosion.Barrel Unit of measure equivalent to 42 gallons, bbl means barrel or barrelsBatch A volume of homogeneous material traveling through a pipeline.BPH Barrels per hour.Breakout Tank A tank used to relieve surges in a hazardous liquid pipeline; or to receive and store hazardous liquids being transported by a pipeline for re-injection and continued transportation by pipeline. CFR~1 95.2 & 195.432.Button Box A discrete control panel equipped with associated switches.Casing Protective enclosure that surrounds a pipe, typically used at road, water and railroad crossings.Cathodic Protection The process of applying an electrical current on a metallic pipe to inhibit corrosion.Celerity A measure of wave propagation speed.CFR Code of Federal Regulations.Chart Recorder A device used to record an instrument reading for subsequent review andlor archiving.Command A computerized check of a Controller's SCADA command, to alert theVerification Controller of possible upset conditions that may occur as a result of the command given.Conditional Alarm An alarm that is inhibited or influenced by other factors~CP Cathodic Protection lof5

CPMCutCut-OutDead-BandDelivery LinesElevation ProfileExpert SystemFlash MonitorFloatGravitometerHard CutHAZWOPERHeart CutHFOHLPHubHVLILlJointComputational Pipeline Monitoring, using computer resources andcomplex algorithms to analyze pipeline data in support of the pipeline'soperational integrity.The separation of a large volume of homogeneous material in a pipeline,or the interface between different materials.Section of pipe that is removed from the pipeline, usually as a result ofsevere corrosion, cracks or mechanical damage.Refers to the difference between the trip and reset points of theinstrument.A pipeline segment connecting Colonial's facilities to a customer terminal.Connecting the measurements of a pipeline's location in the vertical.direction over a given horizontal distance.Computer-based system that applies intuitive reasoning to resolveinformation from complex source data.Analyzer to determine the flash point characteristic of fuel oils.Where material is drawn from a tank while it is still being filled.Analyzer to deterMini the specific gravity of petroleum products.Where the start or stop of a pipeline delivery is calculated on volume, asizable distance from product interface points.Knowledge or Training in the handling of hazardous materials.Another term for Hard CutHazardous Facility Order, as generated by the Office of Pipeline Safety.Hazardous Liquid PipelineA key tank storage location, or interchange point for mainline or stubpipelines.Highly Volatile Liquid, a hazardous liquid which will form a vapor cloudwhen released to the atmosphere defined in ß195.2.In-Line Inspection, a term used to describe the inspection of a pipelinefrom the interior of the pipe.A section of pipe, usually 40 feet in length, although longer lengths areoccasionally manufactured.2 of 5

Lateral A pipeline of small diameter, as compared to a mainline, for the continued transport of material towards a delivery facility.Launcher Section of pipe used to insert a pig at the end of a pipeline segment; is configured so as to isolate the section with a valve for pig insertion.Linefill The volume of space within a pipeline segment, prior to the effects of applied pressure.Line-Pack Refers to the compressibility of materials, where pressure affects volume.Loop Line A pipeline that parallels another pipeline.Mainline In Colonial's Pipeline System, a pipeline segment that is as at least 30 inches in diameter, that is a part of the primary connection between Pasadena, TX and Linden, NJ.Major Spill For the purposes of this report, a major spill is defined as a release of 5,000 bbl of product or more.Mass Balance A technique to balance the material into and out of a pipe segment that incorporates volume balance with an adjustment for the compressibility and temperature of the specific material or materials in the pipe.MFL Magnetic Flux Leakage, a type of ILl technology.MLBV Mainline Block Valve.MOP Maximum Operating Pressure, as identified in CFR ß195.406.NDT Non-Destructive Testing of a pipe.Nominate The process used by Shippers to request space for a given volume of material in a pipeline within a specified time period.OPS Office of Pipeline SafetyPig . A device which passes through a pipeline usually propelled by the material being transported; a smart pig uses one or more physical, electro-mechanical or ultrasonic principles for measuring the severity and position of anomalies in a pipeline.Pig Signal An instrument that detects the passage of a pig, either with a mechanical or electrical detection technique.Pipe-to-Soil An electrical measurement of a potential between a pipe and the surrounding soil environmentPLC Programmable Logic Controller, provides station control logics and sometimes data transport to another location. 3 of 5

Pressure Gradient A profile of the pressure across a pipeline segment.Pressure Wave A short-term change in pressure that travels across the pipeline segment from a point where a flow anomaly has occurred.Prorate Term applied to the process of allocating pipeline space, when shippers nominate in excess of the pipeline's capacity.Pump Trip The sudden action of stopping a pump as a result of either an equipment malfunction or errant hydraulic condition.Railroad Chart A graphical method of portraying the movement and position of rail cars or pipeline batches over time.Receiver Section of pipe used to catch a pig at the end of a pipeline segment; is configured so as to isolate the section with a valve for ~ig removal.Rectifier Electrical device used to generate current in support of a Cathodic Protection System.ROC Rate-of-Change, refers to a type of alarm.RTN Real Time Nomograph, a graphical profile of the pressures at a series of stations that includes a calculated pressure gradient between stations.RTIJ Remote Terminal Unit, collects field data and provides data transport to another location.SCADA Supervisory Control and Data Acquisition SystemShipper An entity who uses a pipeline to transport its hazardous liquids.Slack When the pressure in the pipeline decreases below the vapor pressure of the fluid forming vapor bubbles in the pipeline.Sleeve A fixture applied around a pipe, intended to restore or increase the strength of the pipe at that point.Stale Data Existing data viewed on the SCADA system that has not been updated from the remote location due to an abnormal condition.Steady-State Achieved when flow is established with practically no pressure variations occurring in the segment.Strip Diverting a portion of pipeline flow into another pipeline or a tank.Stub Line In Colonial's Pipeline System, a pipeline segment that is between 6 inches and 16 inches in diameter, connecting from one of the mainlines to delivery facilities. 4 of 5

System Interlock Whefi data from several locations is combined to alert operators of a potential problem, in which the individual data elements would not necessarily indicate a potential problem.Tank Source Providing all material to be shipped from a Tank.Tight Line When the entire volume of an originating pipeline is being supplied directly from another pipeline, thereby being fully dependent on the uninterrupted operation of that source pipeline.Transducer Sensor used to monitor and convert an instrument reading to an electronic signal.Transient Dynamic condition, where pressure and flow rates are changing across a segment.Trap Section of pipe used to stage the launching or retrieval of a pig from a pipeline.TSI Top Side Indication, refers to a feature on the top portion 10 o'clock -2 o'clock of the pipe. .Volume Balance The most basic method of checking operational pipeline integrity: volume in versus volume out.Wall thinning Usually attributed to the effect of general corrosion, where the wall thickness has been reduced in a general fashion. 5of5

IAppendix H H-2 Reference Material 1. 49 U.S.C., Public Law 104-304, Pipeline Safety Act. As Amended October 12, 1996. 2. American Petroleum Institute. "Line Pipe Specifications." API 5L, 40th Edition, 1992. 3. American Petroleum Institute. "Application of Smart-Tools & Emerging Technologies withinthe Hazardous Liquid Pipeline Industry." July 1996. 4. American Petroleum Institute. "Railroad Transportation of Line Pipe." API 5L1, 3rd Edition,1992. 5. American Petroleum Institute. uDeveloping a Pipeline Supervisory Control Center." APIPublication 1113, 2nd Edition, March 1993. 6. American Petroleum Institute. "Training and Qualification of Liquid Pipeline Controllers."API Recommended Practice 1118, First Edition, December 1995. 7. American Petroleum Institute. "Training and Qualification of Liquid Pipeline Operators."API Recommended Practice 1119, Reaffirmed, December 1995. 8. American Petroleum~ Institute. "Assurance of Hazardous Liquid Pipeline System Integrity." API Recommended Practice 1129, First Edition, August 1996. 9. American Petroleum Institute. "Computational Pipeline Monitoring." API Recommended Practice 1130, First Edition, October 1995. 10. American Society of Mechanical Engineers. "Liquid Transportation Systems for Hydrocarbons, Liquefied Petroleum Gas and Anhydrous Ammonia and Alcohols." ASME B31.4, 1992 Edition, as amended 1994. 11. American Society of Mechanical Engineers. "Manual for Determining the Remaining Strength of Corroded Pipelines." ASME B31G, 1991 Edition. 12. Borerier, Dr. Sherry. Volpe National Transportation System Center. "Remote Control Spill Reduction Technology Report." 29 September 1995. 13. British Gas Inspection Services. "Elastic Wave Pipeline Inspection Report * Louisa to Remington." 21 February 1996. 14. Canadian Energy Pipeline Association. "Detection of SCC on Buried Pipelines." National Energy Board, Stress Corrosion Cracking Inquiry, Issue 3, CEPA MH-2-95, February 1995. 15. Code of Federal Regulations, 49 CFR Part 190. Pipeline Safety Program Procedures. 16. Code of Federal Regulations, 49 CFR Part 195. Transportation of Hazardous Liquids by Pipeline. 1 of 3

17. Colonial Pipeline Company. "Over 93 percent of fuel recovered from Reedy River spill." Linefihl Newsletter. Volume 34, Number 3, August, 1996.18. Colonial Pipeline Company. System Operating Pressure Limits. Revision 20, 15 January 1993, and as amended.19. Colonial Pipeline Company. Department of Transportation, Reference Guide.20. Colonial Pipeline Company. "Financial Plan and Forecasting." Strategy Team Meeting Minutes, 29-30 October 1996.21. Coy, Byron. Tele-conference with Valmet Automation, Buss Brown and Wayne Schnell. 10 October 1996.22. Fields, Dr. R.J., Dr. R. DeWit and Dr. T. Foecke. "Design and Maximum Operating Pressure of Pipelines." Metallurgy Division, National Institute of Standards and Technology. Letter Report to G. Joseph Wolf of RSPAIOPS, 31 May 1994.23. General Physics Corporation. ~Assessment of Controller Training and the Supervisory Control and Data Acquisition System in use at Colonial Pipeline Company." For USDOT/RSPA, Office of Pipeline Safety. Report Number DTRS56-96-C-0002-002, January 1997.24. Grimes, Keith. British Gas Inspection Services, Inc. "Stress corrosion crack in-line pig shows promise in tests." Pipeline & Gas Industry, March 1995.*25. Gute, William H., Director, OPS Eastern Region. `How the Office of Pipeline Safety utilizes in-line inspection results." The Pipeline Pigging Conference, Houston, TX, February 1996.26. Interprovincial Pipe Line Inc. "Pipeline Internal Inspection Program." Pipeline Integrity, Engineering Services Department. June 1994.27. Johnson, Dennis C., Stephen S. Thomas. "Colonial's Experience with Finding Longitudinal Defects with Internal Inspection Devices." International Pipeline Conference. Calgary, Alberta, Canada, Summer 1996.28. Joyner, Frederick, Director, OPS Southern Region, Letter regarding High Line Controlling Switches. To: V. A. Yarborough, Vice President Operations, Colonial Pipeline Company. 12 November 1996.29. Kiefner & Associates. "Investigation of Pig Indicated Anomalies in Selected Specimens of Line 4- Louisa to Remington." 7 August 1996.30. Kiefner, John. "Preventing Pipeline Service Failures." Pipeline Digest, April 1996.31. Leis, B. N., T. A. Bubenik and J. B. Nestleroth. "Stress-Corrosion Cracking in Pipelines." Pipeline & Gas Journal, August 1996.32. Mitchell, Jesse L. "Smart Pigs Are Getting Smarter." Texas Eastern Products Pipeline Company. Houston, TX. 2of3

33. National Transportation Safety Board. `MAPCO Natural Gas Liquids, Inc., Pipeline Accident Report in April 7, 1992.' NTSB/PAR-93/01, PB93-916502. 34. National Transportation Safety Board. `Pipeline Special Investigation Report. Evaluation of Accident Data and Federal Oversight of Petroleum Products. Pipelines.' NT$B/SlR- 96/02, PB96-91 7002. 35. New Jersey Institute of Technology. `Pipeline Industry Comparison of U.S. with Foreign Pipeline Land Use and Siting Standards Maintenance, Rehabilitation and Retrofitting Policies and Practices.' For USDOTIRSPA, Office of Pipeline Safety, Report Number DTRS56-94-C-0006, April 1996. 36. Office of Pipeline Safety. `Colonial Pipeline Fatigue Failures - Task Force Report.' 14 September 1990. 37. Pipeline Digest. `Pipeline Pigs'. June 1996. 38. Research and Special Programs Administration. `Instrumented Internal Inspection Devices, A Study Mandated by P.L. 100-561.' United States, Department of Transportation, November 1992. 39. Stress Engineering Services, Inc. `Cyclic Pressure Fatigue Life of Pipelines with Plain.Dents, Dents with Gouges, and Dents with Welds'. For Pipeline Research Committee at the American Gas Association. PR-201-927, PR-201-9324, June 1994. 40. Texas Transportation Institute, Texas A&M University System. `Development of a Procedure to Apply Leak-Before-rupture Concepts to Gas and Hazardous Liquid Transmission Pipelines.' For USDOT/RSPAIOPS, Contract DTRS56-95-C-0003. 41. Ulrich, Lloyd W., Chief, Technical Division, Office of Pipeline Safety. `The DOT R&D Program on Mechanical Damage.' The Pipeline Pigging Conference, Houston, TX, February, 1996. 42. Yarborough, V. A., Vice President Operations, Colonial Pipeline Company. Letter regarding High Line Controlling Switches: To: Frederick A. Joyner, Director, Southern Region, DOTIRSPA/OPS. 29 October 1996. 3 of 3

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Appendix E Table E-1 Colonial Pipeline Company Training Summary: 1990-1 996Training Type1990199119921993199419951996Substation Maintenance1Station Sequence- 211Tank Maintenance2111111Valve Maintenance11111Switchgear Maintenance41Meter, Prover School141I.Valve Operator MaintenanceIFire Prevention8884466Emergency Response249DOT Supervisors3Excavation Safety153Pump Maintenance21Motor Maintenance31Pipeline Construction3Pipeline Maintenance.11333SCADA Maintenance21Corrosion SchoolIITank Gage SchoolIQuality Control Test Equipment Maintenancei11:Coupler Alignment11Soltron Maintenance.IBasic Electrical School1Defensive Driving School1171010559CPR/ First Aid71~.I11HAZWOPERJRefresherSchooI914141311Vendor supplied training

Appendix E E-2 OPERATOR TRAINING PROGRAM1NEW EMPLOYEESAs a new employee you will be considered an operator trainee until you are fully qualified toprovide unsupervised relief in operating classifications. As such, you are being developed toperform other operating jobs. Your future value to the company depends on the effectiveness ofthe training you receive.QUALIFICATIONS FOR ADVANCEMENTBefore you can be qualified for advancement, you must demonstrate that you have the knowledgeand understanding of operating practices, equipment, and work procedures necessary for goodoperation and are sufficiently skilled in performing operating functions. To do this you must: 1. During your six month evaluation period, demonstrate an aptitude for pipeline operations, a desire to learn, and a willingness to work safely and to follow rules and procedures. 2. Submit in writing, to your leader, satisfactory answers to questions in the Operating Training Guide. 3. Demonstrate your operating ability while working on shift as a trainee under appropriate direction for at least 30 days during you evaluation period. During this time you will not be paid shift differential.OPERATOR TRAINING GUIDEThe guide is given to you and explained by your leader when you start work. It consists primarily ofspecific questions pertaining to operating problems and procedures. You are expected to answerthe questions in writing, as your training progresses. Your Leader will review with you the questionsyou have answered and your progress at the end of 30, 60, 90 and 120 days. When yousatisfactorily answer all questions in the guide, your leader will review and return it to you. You areto keep it as a source of reference.You should use the following sources to assist you in completing this program. Operating Guide Accident Prevention Manual Emergency Directory Computer-Based Training Program Posted Procedures and InstructionsAmong the best sources, of course, are your leader, co-workers, and the daily work assigned to you. Taken from Colonial's Operator Training Guide. 1 of 2

INDEX PIPELINE OPERATION TRAININGA. Operations 1. Hydraulics 2. Pipeline Operations * 3. Tank Gaging and Sampling 4. Meters and Provers 5. Ticketing 6. Scraper SequenceB. Product Quality Assurance 1. Quality AssuranceC. Maintenance 1. Equipment Operating and Maintenance 2. Cathodic Protection0. Product Scheduling 1. Scheduling and ControllingE. Safety 1. Fire Prevention 2. Accident PreventionF. General 1. Radio Communications 2. ROW and Encroachments 3. Report and FormsG. Review 1. Review and Checklist 2of2

Appendix E E-3 ASSOCIATE CONTROLLER TRAINING PROGRAM1 MINIMUM SIX MONTHSThe Associate Controller Training Program consists of the following phases: A. Training Period on System 3- one full rotation of shifts B. Training Period on System I or 2 - one full rotation of shifts C. Training Period on System 4 - one full rotation of shifts D. Training Period on System 5 or 6- one full rotation of shifts E. Scheduling Orientation- one to two weeks F. Inventory Orientation - one to two weeksThe final six weeks of the Associate Controller Training Program will be spent training on thesystem that the Associate Controller will be operating after the completion of the training period.The period of time spent on any position may be lengthened, depending upon the progress andneeds of each individual trainee.Upon completion of all phases of the Associate Controller Training Program, the AssociateController will be awarded a Certificate of Completion. Taken From Colonials Associate Controller Training Guide' 1 of 6

Associate Controller TrainingController training is separated into two parts and are to be done concurrently. A. Individual Study is a study of reference material as follows: 1. Controllers Operating Guide 2. System Operating Pressure Limits Manual 3. Quality Control Manual 4. Pipeline & Dispatching Hydraulics Manual .5. Emergency Directory 6. Contingency Plan B. On the Job Training with a qualified controller: Dunng the period of on the job training, the training controller witl instruct the associate controller in all phases of pipeline operation pertaining to controller operations. This would include general controller duties, as well as duties tailored to the specific pipeline system involved. 1. To insure that the trainee masters the basic fundamentals as rapidly as possible, special consideration should be given to the following areas: a Log Sheets - to become familiar with locations, codes, terminology, calculating linefills and mImes. b. Schedule. c. Entering transactions for mImes and line fills. d. Unit operation under the direction of the training controller. e. Use of the nomograph and unit select model. The trainee is not expected to remember the units required, that is learned through years of experience, but he/she must know the methods available for making unit selections. 2. At the discretion of the trainer the trainee with be allowed to perform aft the duties of the controller. These duties with be closely supervised by the training controller. 3. Continue to instruct the trainees in all areas of need. 4. Keep up the daily check list to insure that all phases of training are covered. 5. Progress of the trainee will be determined by the following methods: a. Daily check list b Self-evaluation c. Evaluation by the training controller d. Evaluation by the Shift Supervisor e. Progress Assessment Form - completed at the end of each training rotation f. Regularly scheduled tests in all phases of operations written and/or oral 6. At the end of the pn the job training period, the trainee is expected to have demonstrated that he/she has gained a thorough understanding of all phases of operations and is able to apply this knowledge to successfully fulfill the duties and responsibilities of a Controller. 2of6

Check ListsCheck lists are included in this guide. These check lists should be used daily and coded inaccordance with the legend at the bottom of the check list. A. Training Check List- consists of six sets of check lists 3 sheets each, one to be used at each controller training position. These check lists should be used by the trainer to: .1. Determine a starting point in the program for a newly assigned trainee. This should minimize the amount of time needed to determine what subjects have or have not been covered by a previous trainer. 2. Insure that all areas of operation are covered. 3. Detect any areas of deficiency in order to emphasis may be placed on these subjects. Insure that the trainee gains a satisfactory level of knowledge in all aspects of the operations pertaining to the pipeline controllers position. 3of6 ~

Progress Assessment FormThis form should be used to aid the trainee, their trainer and shift supervisor in identifyingstrengths and weaknesses of the trainee. A plan of action should also be developed in order tocorrect any shortcomings of the trainee. The trainee, trainer and shift supervisor should meet atthe end of each training rotation to discuss and evaluate these areas. 4 of 6

Progress Assessment Form Trainee ___________________________ Date - Training Period From________________ To_ System ___________________________ Ranking System 1- 10 1 being the lowest; 10 being the highest Normal Operations1.Work Ethic Exhibited _____ 2. Willingness to Complete Required Tasks _____ 3. attitude Toward Trainers Instructions _____~* Commitment to Produce Accurate Work _____ 5. Use of Monitoring and Command Equipment _____ 6. Aptitude for the Job _____~* Knowledge of Rules, Regulations and Work Processes _____ 8. Familiarity with Operating Guide and Temporary Notices _____ 9. Ability to Effectively Communicate with Others _____ I 0.Understanding of Pipeline Hydraulics _____ Total Abnormal Operations Ability to Respond Quickly and Effectively to One or More of the Following: 1. Unintended Closure of Valves or Unit Shutdowns1. 2. Increase or Decrease in Pressure Outside Normal Operating Limits 3. Loss of Communications 4. Equipment Malfunction or Personnel Error 5. Correcting Variations from Normal Operation of Pressure and Flow Controls 6. Notification of Proper Personnel Total Emergency Situations 1. Proper Response to Notice of Emergency or Hazardous Situation 2. Effective Action to Notice of Emergency or Hazardous Situation3. Taking Necessary Action Shutdown or Pressure Reduction 4. Notification of Proper Personnel and Public Officials Total Total Score 5of6

Strengths_Weaknesses~CommentsTrainee's Signature_______Trainer~s Signature________Shift Supervisor~s Signature.6 of 6

Appendix F Table F.1 Colonial Leaks 1000 bbl. Or More: 1968 - 1996 As Shown on MapDate State06/26196 SCLocationLineDia.VolumeSpilledbblCostPrimary CauseContributory CausesSimpsonville33622800$4,000,000Corrosion`~perator Errorl0/20I94 TXHams14020,000$10,000,000Outside Forces - Flood01128/70 ALTuscaloosa County13614,717$5,150Operator ErrorRailroad12/19/91 SCSimpsonville33613,100$250,000Third Party Damage-11122/75 NJHamilton Township33012,802$2,074Normal Pipeline OperationRailroad Fatigue Crack10/20/94 TX03/28/93~ VAHamsFairfax23363610,0009,708$10,000,000$10,000,000Outside Forces - FloodThird Party Damage -.06/16/79! SC05/131791 SC03/06/801 VA NC12/18/89 VA1/23/82 SCGreenville CountyGreenville CountyPnnce William Charlotte Unionville Betton 2 36 9400 $1,850 2 36 8,000. $1,500 4 I 32! 8,000! $934Tank N/A 5,770! $2,000 4 321 5,043~ $75,000Tank I N/A I 4,7651Operator ErrorNormal Pipeline OperationOperator ErrorCorrosion -Roof DrainNormal Pipeline Operation~quipment Failure - Tank Roof.Railroad Fatigue Crackqailroad Fatigue CrackRailroad Fatigue Crack04/05/85 ALShelby County 1 36! 4.000i $12,000Corrosion*Supervisory Error02/07/791 TNHamilton18 10~ 3.613 $65Construction Improper Backfill.11J19/71~ TXBeaumont2 36* . 3.500 Other11/08/85 VA jChesterfield27 16 2,875 $85,700lThird Party Damage08/28/72: TNRutherford20 10 2,475 $500 IConstruction. Improper Installation.01/05/88! NJDepford Township3 I 30~ 2,375 $450,000lCorrosionQperator Error01123/89! NC03/06/801 VAGreensboroOrange CountyStation N/A 2,221 Operator Error 4 32 2,190 $729lOperator Error01/13/73! TNNashville20 8 2,005 $l8IThird Party DamageFatigue Crack08/05174: TXOrange County2 36 2.000 $1,500!CorrosionOperator Error06/22/90: VA08/22/75! VA Chesterfield 27 16 2.000 $50,000!Third Party DamageCumbertand County I Tank N/A: 1.770 Corrosion - Roof Drain02/06/96: TNChattanooga` 8 1.750 Outside Forces Electrical02119/701 NC ` Paw Creek . DischargeStation N/A 1.600 S2.000:Operator Error r08/29/90' VA Chesapeake26 12 1,600 Third Party Damage11/5/96 TN Murfreesboro20 8 1,500 Unknown!Operator Error08/14/76: GA Cobb County19 12 1,334 $1,200Other03/14/72 LA Baton RougeStation N/A 1.300 Operator Error09/21/80 NJ WoodbridgeStation N/A 1,242 Operator Error07/09/72: LA E. Baton RougeStation N/A 1.195 Operator Error3/77 GA AtlantaTank N/A 1,165 Operator Error - Improper setupEquipment Failure-Alarm09/22/78 TN ! CharlestonStation N/A 1.150 Failure Gasket04/03!72 NJ Middlesex County $15~EguipmentStation N/A 1.125 $40,000lOperatorEnor08/28/78 NC Gastonia2 36 1,025 $1,200IThird Party Damage09/08/71 NJ Woodbndge Township' Tank N/A 1,000 ICorrosion - Roof Drain08/22/68. GA Bolingbroke 17 8 1.000 $200lCorrosion* Under Review

Appendix F F-2 Colonial Pipeline Leak MapThe following is a map of Colonial's pipeline system. The significant leaks spills greater than1,000 bbls. have been recorded on the map. The RED highlights leaks that occurred on themainlines. The BLACK highlights the leaks that did not occur on the mainlines.

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