# Enterprise Crude Pipeline-12/1/15 - **operation:** document - **citation:** PHMSA FIR, Enterprise Crude Pipeline, 2015-12-01 - **title:** Enterprise Crude Pipeline-12/1/15 - **source type:** incident - **agency:** Pipeline and Hazardous Materials Safety Administration - **status:** historical - **official:** true - **published on:** 2017-04-19 - **effective on:** 2015-12-01 - **summary:** Enterprise Crude Pipeline; Hazardous Liquid Apparent; OK; failure 2015-12-01; apparent cause: Tank Line Failure Due to Internal Corrosion. - **machine formats:** - **json:** https://regulus.evalyn.ai/document/phmsa-fir-enterprise-crude-pipeline-12115-0.json - **markdown:** https://regulus.evalyn.ai/document/phmsa-fir-enterprise-crude-pipeline-12115-0.md - **app url:** https://regulus.evalyn.ai/document/phmsa-fir-enterprise-crude-pipeline-12115-0 - **source url:** https://www.phmsa.dot.gov/inspections-and-investigations/enterprise-crude-pipeline-12115-0 **body:** <<>> USDOT U.S. Department of Transportation PHMSA Pipeline and Hazardous Materials Safety Administration OPS Office of Pipeline Safety Southwest Region Investigators Charles Onwuachi David York Region Director R.M. Seeley Date of Report 12/27/2016 Subject Failure Investigation Report – Enterprise Crude Pipeline, LLC, Cushing West Tank Farm Release Operator, Location, & Consequences Date of Failure 12/1/2015 Commodity Released Crude Oil City/County & State Cushing, Payne County, OK OpID & Operator Name 30829 Enterprise Crude Pipeline Unit # & Unit Name 14464 Oklahoma 30-Inch SMART Activity # 151766 Milepost/Location Cushing Type of Failure Tank line failure due to internal corrosion Fatalities 0 Injuries 0 Description of area impacted On-site impact to soil and containment pond Total Costs $291,898 <<>> Failure Investigation Report: Cushing West Tank Farm Release 12/1/2015 Executive Summary On December 1, 2015, at approximately 10:10 p.m. Central Standard Time (CST), personnel from Enterprise Crude Pipeline, LLC (Enterprise), discovered a spill at their West Cushing Tank Farm in Cushing, Oklahoma. Approximately 1,000 barrels of crude oil were released within the terminal, briefly interrupting operations as Enterprise investigated the source of the leak. Enterprise reported the release to the National Response Center at 11:30 p.m. CST. The spill was contained within the tank farm after travelling along the surface of the ground to a retention pond on the west side of the terminal. The source of the release was determined to be a buried steel tank transfer pipeline within the station that had an outer diameter of 16 inches. Stress Engineering Services of Houston, Texas, performed a failure analysis on the damaged portion of pipe, stating in their final report that the cause of the spill was internal corrosion. The remaining portion of the line was evacuated of product and abandoned in place. No fire or injuries occurred as a result of the failure; however, the spill resulted in approximately $291,898 in total damages. Page 2 of 7 <<>> Failure Investigation Report: Cushing West Tank Farm Release 12/1/2015 System Details Enterprise operates two storage tank terminals in Cushing, Oklahoma, designated as their East & West Tank Farms. The combined storage capacity of the terminals is approximately 3.3 million barrels (MMbbls), 1 inclusive of five larger external floating roof tanks that are leased to Paragon but operated by Enterprise. Currently there are fifteen storage tanks within the terminal that serve as breakout tanks to several crude oil pipelines operated by Enterprise and other entities. Product is transported into the West Terminal through pipeline systems operated by Enterprise, including the Red River Gathering System and the Basin Pipeline. Product can also be delivered to the Seaway Crude Pipeline system that connects the West Cushing Terminal to refineries on the Gulf Coast. Source: http://www.enterpriseproducts.com/about-us/system-map The leak was identified on an 1,160-foot section of steel pipeline with a 16-inch outer diameter that served as a fill line within the facility for Tank 41123. The pipe wall measured 0.25 inches, and was manufactured with a fusion bond external coating; however, the pipeline did not have an internal coating. The maximum operating pressure of the line was designated as 275 pounds per square inch gauge (psig), limited by the American National Standards Institute (ANSI) 150 components installed on the system. The manufacturer and specified minimum yield strength of the line segment was reportedly unknown. The West Terminal is in the Pipeline and Hazardous Materials Safety Administration’s (PHMSA) Inspection System 1970 under the name Enterprise_Crude. 1 Crude Oil Pipelines & Services. Enterprise Products Partners, L.P. Retrieved August 2016. http://www.enterpriseproducts.com/operations/onshore-crude-oil-pipelines-services Page 3 of 7 <<>> Failure Investigation Report: Cushing West Tank Farm Release 12/1/2015 Events Leading up to the Failure On December 1, 2015, at approximately 1:00 p.m. CST, Enterprise started to move product out of Tank 41123. The three pipelines connected to Tank 41123 have outer diameters of 16, 18, and 24 inches. The transfer was scheduled for the 18-inch delivery line, progressing throughout the day and ending by midnight. During the course of this delivery process, Enterprise began a flush into Tank 41123 through the 16-inch fill line at approximately 8:28 p.m. (b)((F) CST. The flush lasted for roughly 30 minutes. At 9:56 p.m. CST, a terminal operator-who was scheduled to take samples from the Manifold A area-detected the scent of crude oil and discovered oil on the ground just north of Manifold A. Emergency Response Upon notification from the terminal operator, operations personnel immediately initiated shutdown of all equipment within the terminal. Notification of the incident was made by telephone, first to operations and maintenance supervisors and then to response contractors and additional operations personnel. Two local spill response teams were mobilized and began arriving at the terminal at 11:30 p.m. with heavy machinery, frac tanks, and vacuum trucks. Crews continued work to identify and sequester the source of the release, isolating Tank 41123 at 11:45 p.m. through the use of manual valves. The oil travelled approximately 1,200 feet from the leak source to an onsite containment area and retention pond. The contaminated soil was removed to an area on the northwest side of the terminal while personnel installed a hard boom across the retention area, removing the oil with surface skimmers. The Cushing West Terminal is not located in an area determined to possibly affect a High Consequence Area as a result of an unintended release. The Terminal is included in the Facility Response Plan written to comply with Title 49 CFR 194; however, the plan was not activated in response to this spill. PHMSA's Southwest Region responded to the site on Thursday, December 3, 2015, to initiate an investigation. Summary of Return-to-Service The 16-inch pipeline was not immediately returned to service following the release. Following visual examination, Enterprise installed a mechanical clamp over the damaged portion of the pipeline on December 3, 2015. The line was drained down and remained inactive, and the damaged portion of the pipe was later removed and sent to Houston, Texas, for failure analysis. With the damaged 16-inch fill line isolated, the West Terminal restarted operations on Wednesday, December 2, 2015. Page 4 of 7 <<>> Failure Investigation Report: Cushing West Tank Farm Release 12/1/2015 Investigation Details PHMSA’s investigation included a review of the events, the response of Enterprise personnel, Supervisory Control and Data Acquisition (SCADA) operations, and internal corrosion management within the terminal. (b) (7)(F) The release was discovered following the flush performed on Tank 41123 through a third-party line. The flush operation required an attendant be onsite at the Manifold A area. As the flush was completed the manual valve to the 16-inch line at Manifold A area was closed, at which time Enterprise personnel had not detected an abnormal condition at the terminal. At approximately 10:00 a.m. on December 2, hydro-excavation revealed the source of the spill to be the 16-inch fill line. A visual examination revealed a small hole at the 6 o’clock position on the piping, buried under approximately 3.5 feet of soil and gravel. No mechanical damage was visible, and the external coating around the defect appeared to be in good condition. Enterprise ordered a 16 x 18 PLDICO Clamp + Sleeve to facilitate the repair, which was completed on December 3, before PHMSA inspectors arrived onsite. At the time of the accident, the pressure within the 16-inch line was estimated to be less than 10 psig. Enterprise provided records indicating the 16-inch line was hydrostatically tested in 1997 to a minimum pressure of 346 psig for 8 hours. Product is transported to the West Terminal through pipelines owned and operated by Enterprise and Enbridge, as well as through a truck terminal located within the facility. Internal corrosion monitoring at the West Terminal is conducted primarily through weight loss coupons installed on incoming pipelines at the East Terminal: there are no monitoring points located within the West Terminal. Records show that the average corrosion rate in miles per year (MPY) over the course of three years leading up to the accident was well below what would be considered significant. Additionally, biocide treatment was started in 2012. Metallurgical Analysis Enterprise sent approximately 6 feet of the failed 16-inch pipe to Stress Engineering Services in Houston, Texas, for analysis. The findings are summarized here; a copy of the final report can be found in Appendix D. In a final report dated July 12, 2016, Stress Engineering concluded that the hole, measuring 1 1/16 inches in diameter and found in the bottom of the 16-inch pipe, was the result of a carbon dioxide-driven attack. Several pits of varying size were found along the bottom of the pipe sample, around which tests registered the presence of hydrogen sulfide, although the report concluded that this did not influence the creation of the pitting. Chemical analysis on deposits within the pit adjacent to the through-wall defect revealed the presence of sand and chlorine, products likely to be entrained in the product stream. Page 5 of 7 <<>> Failure Investigation Report: Cushing West Tank Farm Release 12/1/2015 While the year and manufacturer of the pipe were unknown, tensile and hardness tests show the pipe met the current requirements for the American Petroleum Institute (API) Grades X42, X46, and B. The analysis did not discover any manufacturing or metallurgical defects that could have contributed to the failure, and apart from the external coating missing at the defect, the fusion-bonded epoxy (FBE) coating was determined to be in good condition. Conclusion PHSMA concurs with the findings of the metallurgical analysis. The pit immediately adjacent to the through-wall defect exhibited signs of deposit corrosion, common in station piping where flow rates are generally lower than transmission piping and pigging is largely impracticable. PHMSA determined the accident likely went undetected for approximately one hour, and Enterprise’s response was appropriate following discovery of the spill. Appendices A Map and Photographs B NRC Report #1134731 C Operator Accident Report to PHMSA (#20150464) D Laboratory Analysis Page 6 of 7 <<>> Failure Investigation Report: Cushing West Tank Farm Release 12/1/2015 Appendix A – Map Page 7 of 7 <<>> HMIS-> INCIDENTS-TELEPHONICS Materials Safety Pipeline & Hazardous Administration (Version 4.0.0 PROD) Rules of Behavior Home Logout Menu [Retum to Search! NRC Number: Call Date: 12/02/2015 Call Time: 00:30:00 Caller Information [DAVIO ENTERPRISE CRUDE PIPELINE Last Name: GIBBBIS City: HOUSTON (9420 WEST SAM HOUSTON FKWY NCRTH USA State: [PRIVATE (2818872640 Zp: Phone 2: 77064 • Yes E No F$No Response Is caller the spiter? DAVID Discharger Information ENTERFRISE CRUDE PIPELINE Last Name: Hail City: 19420 WEST SAM HOUSTON FKWY NORTH ¡USA HOUSTON State: (2018972840 Zip: [TX [PRIVATE Phone 2: 77064 Nearest Cty: State: (CUSHING OK Spill Information County: Location Zp Code: 740120 SOUTH 3510 ROAD Spil Date: (12/01/2015 (mm/dd/yay) Spill Time: 2215:00 (24hh:mm:ss) Incient Type DTG Type: k- Select DTG Type -> Description Storage Tanks Reported Incident Type STORAGE TANKS CALLER IS REPORTING A DISCHARGE OF LIGHT SOUR CRUDE FROM A CRUDE TANK DUE TO A CRACKED MANIFOLD. Material / Chris Name Materials Inolved [OL: CRUDE (Chris Code. 800 BARREL(S) [Total Qty. Water Qty. Additional Medium Information: Medium Type: - Select Medium Type. / ONSITE FIRE RESERVOIR (SECONDARY CONTAINMENT) Evacuations: Injuries: Damages: C Yes ® No C Unknown • Yes @ No Unknown Other Agency Notified: Federel Agency Notified: © yes O No Unknown • Yes C No FUnknown State Agency Notified: • yes @ No Unknown Romedial Actions <<>> IN THE PROCESS GETTING A PLANNED TOGETHER FOR CLAN UP. CALLER STATED THAT THE MATERIAL DISCHARGED INTO AN ONSITE PIT WITH WATER IN IT THAT tonal inte IS USED TO PUT OUT FIRES. •ll Rescinded Comments (max 250 charactors) | 22 Preybus 1..1 of 25 <<>> exceed 5100,00 for are violation or each day that such relation persist excep actine rain cavil OMB NO: 2137-0047 penalty shall not exceed $1,000,000 as provided in 49 USC 60122. EXPIRATION DATE: 12/31/2016 Original Report Date: 12/16/2015 U.S Department of Transportation No. 20150464 - 21420 Pipeline and Hazardous Materials Safety Administration (DOT Use Only) ACCIDENT REPORT - HAZARDOUS LIQUID PIPELINE SYSTEMS vith a collection of information subject to the requirements of the Paperwork Reduction Act unless that collection of information displays a current valid federal agency may not conduct or sponsor, and a person is not required to respond to, nor shall a person be subject to a penalty for failure to comply Send comments regarding this burden or any other aspect of this collection of information, including suggestions for reducing the burden to: information OMB Control Number. The OMB Control Number for this information collection is 2137-0047. All responses to the collection of information are mandatory. Collection Clearance Officer, PHMSA, Office of Pipeline Safety (PHP-30) 1200 New Jersey Avenue, SE, Washington, D.C. 20590. INSTRUCTIONS amples. If you do not have a copy of the instructions, you can obtain one from the PHMSA Pipeline Safety Community Web Page i portant: Please read the separate instructions for completing this form before you begin. They clarify the information requested and provide speci http://www.phmsa.dot.gov/pipeline/library/forms. PART A - KEY REPORT INFORMATION Report Type: (select all that apply) Original: Supplemental: Yes Final: Yes Last Revision Date: 2. Name of Operator 1. Operator's OPS-issued Operator Identification Number (OPID): 06/06/2016 30829 3. Address of Operator: ENTERPRISE CRUDE PIPELINE LLC 3b. City 3а. Street Address 1100 Louisiana Street 3c. State Texas Houston 4. Local time (24-hr clock) and date of the Accident: 3d. Zip Code 77002 5. Location of Accident: 12/01/2015 22:10 35.95201 6. National Response Center Report Number (if applicable): -96.759592 National Response Center (if applicable): 7. Local time (24-hr clock) and date of initial telephonic report to the 1134731 12/01/2015 22:35 8. Commodity released: (select only one, based on predominant volume released) Crude Oil - Specify Commodity Subtype: - If Biofuel/Alternative Fuel and Commodity Subtype is - If "Other" Subtype, Describe: - If Biofuel/Alternative Fuel and Commodity Subtype is Ethanol Blend, then % Ethanol Blend: Biodiesel, then Biodiesel Blend e.g. B2, B20, B100 9. Estimated volume of commodity released unintentionally (Barrels): 10. Estimated volume of intentional and/or controlled release/blowdown 1,000.00 11. Estimated volume of commodity recovered (Barrels): (Barrels): - If Yes, specify the number in each category: 12. Were there fatalities? No 1,000.00 12c. Non-Operator emergency responders 12b. Contractor employees working for the Operator 12d. Workers working on the right-of-way, but NOT 12e. General public associated with this Operator 13. Were there injuries requiring inpatient hospitalization? 12f. Total fatalities (sum of above) - If Yes, specify the number in each category: No 13a. Operator employees 13c. Non-Operator emergency responders 13b. Contractor employees working for the Operator 13a. Worse with this Operaight-of- way, bur NoT Form PHMSA F 7000.1 <<>> 14. Was the pipeline/facility shut down due to the Accident? 13f. Total injuries (sum of above) - If Yes, complete Questions 14a and 14b: (use local time, 24-hr clock) - If No, Explain: Yes 14a. Local time and date of shutdown: 14b. Local time pipeline/facility restarted: 12/01/2015 22:10 15. Did the commodity ignite? - Still shut down? (* Supplemental Report Required) 12/02/2015 13:00 16. Did the commodity explode? No 18. Time sequence (use local time, 24-hour clock): 17. Number of general public evacuated: No 18a. Local time Operator identified Accident - effective 7- 2014 changed to "Local time Operator identified failure": 12/01/2015 22:10 18b. Local time Operator resources arrived on site: 12/01/2015 22:10 PART B - ADDITIONAL LOCATION INFORMATION 1. Was the origin of the Accident onshore? If Yes, Complete Questions (2-12) Yes - If Onshore: If No, Complete Questions (13-15) 2. State: 4. City 3. Zip Code: Oklahoma 74023 6. Operator-designated location: 5. County or Parish Cushing Payne 7. Pipeline/Facility name: Specify: Milepost/Valve Station West Terminal 9. Was Accident on Federal land, other than the Outer Continental Shelf 8. Segment name/ID: Cushing West Terminal Tank 23 flush line (OCS)? No 10. Location of Accident: 11. Area of Accident (as found): Underground Totally contained on Operator-controlled property - If Other, Describe: Specify: Under soil 12. Did Accident occur in a crossing? Depth-of-Cover (in): No 36 - If Yes, specify type below: - If Bridge crossing - - If Railroad crossing - Cased/ Uncased: - If Road crossing - Cased/ Uncased/ Bored/drilled - If Water crossing - Cased/ Uncased/ Bored/drilled Cased/ Uncased - Approx. water depth (ft) at the point of the Accident: - Name of body of water, if commonly known: - If Offshore: - Select: 14. Origin of Accident: 13. Approximate water depth (ft) at the point of the Accident: - In State waters - Specify: - Area: - Nearest County/Parish: - Block/Tract #: - On the Outer Continental Shelf (OCS) - Specify: - Area: 15. Area of Accident: - Block #• PART C - ADDITIONAL FACILITY INFORMATION 1. Is the pipeline or facility: 2. Part of system involved in Accident: Interstate Appurtenances, specify: - If Onshore Breakout Tank or Storage Vessel, Including Attached Onshore Terminal/Tank Farm Equipment and Piping 3. Item involved in Accident: - If Pipe, specify: Pipe 3a. Nominal diameter of pipe (in): Pipe Body 16 Form PHMSA F 7000.1 <<>> 3b. Wall thickness (in): 3c. SMYS (Specified Minimum Yield Strength) of pipe (psi): .250 Зе. 3a. Pipe specification: 5L Unknown Pipe Seam, specify: Pipe manufacturer: - If Other, Describe: Longitudinal ERW - High Frequency 3g. Year of manufacture: Unknown Unknown Pipeline coating type at point of Accident, specify: - If Weld, including heat-affected zone, specify. If Pipe Girth Weld, - If Other, Describe: Fusion Bonded Epoxy Зa through 3h above are required: - If Valve, specify: - If Other, Describe: - If Mainline, specify: 3i. Manufactured by: - If Other, Describe: 3j. Year of manufacture: - If Tank/Vessel, specify: - If Other, describe: - If Other - Describe: 5. Material involved in Accident: 4. Year item involved in Accident was installed: 1993 6. Type of Accident Involved: - If Material other than Carbon Steel, specify: Carbon Steel Leak - If Mechanical Puncture - Specify Approx. size: in. (circumferential) in. (axial) by - If Leak - Select Type: - If Rupture - Select Orientation: - If Other, Describe: Pinhole Approx. size: in. (widest opening) by - If Other, Describe: - If Other - Describe: in. (length circumferentially or axially) PART D - ADDITIONAL CONSEQUENCE INFORMATION 1. Wildlife impact: 1a. If Yes, specify all that apply: | No - Birds - Fish/aquatic - Terrestrial 2. Soil contamination: 3. Long term impact assessment performed or planned: Yes 4. Anticipated remediation: No 4a. If Yes, specify all that apply: Yes - Surface water - Soil - Groundwater - Vegetation Yes 5. Water contamination: - Wildlife 5a. If Yes, specify all that apply: No - Ocean/Seawater - Surface - Drinking water: (Select one or both) 5b. Estimated amount released in or reaching water (Barrels): 6. At the location of this Accident, had the pipeline segment or facility 5c. Name of body of water, if commonly known: (HCA) as determined in the Operator's Integrity Management Program? been identified as one that "could affect" a Hiah Consequence Area No 7. Did the released commodity reach or occur in one or more High No 7a. If Yes, specify HCA type(s): (Select all that apply) - Commercially Navigable Waterway: Was this HCA identified in the "could affect" determination for this Accident site in the Operator's Form PHMSA F 7000.1 <<>> Integrity Management Program? determination for this Accident site in the Operator's Was this HCA identified in the "could affect" Integrity Management Program? for this Accident site in the Operator's Integrity Was this HCA identified in the "could affect" determination - Unusually Sensitive Area (USA) - Drinking Water Management Program? for this Accident site in the Operator's Integrity Was this HCA identified in the "could affect" determination - Unusually Sensitive Area (USA) - Ecological Management Program? for this Accident site in the Operator's Integrity Was this HCA identified in the "could affect" determination 8. Estimated cost to Operator - effective 12-2012, changed to "Estimated Property Damage": Management Program? 8a. Estimated cost of public and non-Operator private property "paid/reimbursed by the Operator" removed damage paid/reimbursed by the Operator - effective 12-2012, 8b. Estimated cost of commodity lost 8d. Estimated cost of Operator's emergency response 8c. Estimated cost of Operator's property damage & repairs Estimated cost of Operator's environmental remediation $ $ changed to "Total estimated property damage (sum of above)" 8g. Estimated total costs (sum of above) - effective 12-2012, $ 291,898 PART E - ADDITIONAL OPERATING INFORMATION 2. Maximum Operating Pressure (MOP) at the point and time of the 1. Estimated pressure at the point and time of the Accident (psig): 10.00 Accident (psig): 275.00 3. Describe the pressure on the system or facility relating to the Pressure did not exceed MOP (such as for repairs and pipe movement), was the system or facility 4. Not including pressure reductions required by PHMSA regulations restriction with pressure limits below those normally allowed by the relating to the Accident operating under an established pressure No - If Yes, Complete 4.a and 4.b below: Did the pressure exceed this established pressure 4b. Was this pressure restriction mandated by PHMSA or the 5. Was "Onshore Pipeline, Including Valve Sites" OR "Offshore 2? Pipeline, Including Riser and Riser Bend" selected in PART C, Question No - If Yes - (Complete 5a. - 5f below) effective 12-2012, changed to "(Complete 5.a - 5.e below)" source: 5a. Type of upstream valve used to initially isolate release 5b. Type of downstream valve used to initially isolate release 5c. Length of segment isolated between valves (ft): 5d. Is the pipeline configured to accommodate internal - If No, Which physical features limit tool accommodation? (select all that apply). - Changes in line pipe diameter - Presence of unsuitable mainline valves projecting instrumentation, etc.) - Other passage restrictions (i.e. unbarred tee's, flux leakage internal inspection tools) - Extra thick pipe wall (applicable only for magnetic 5e. For this pipeline, are there operational factors which - If Other, Describe: run? significantly complicate the execution of an internal inspection tool - If Yes, Which operational factors complicate execution? (select all that apply) Form PHMSA F 7000.1 <<>> - Low operating pressure(s) - Incompatible commodity - Low flow or absence of flow - Other - 5f. Function of pipeline system: - If Other, Describe: system in place on the pipeline or facility involved in the Accident? 6. Was a Supervisory Control and Data Acquisition (SCADA)-based > 20% SMYS Regulated Trunkline/Transmission Yes If Yes - 6b. Was it fully functional at the time of the Accident? 6a. Was it operating at the time of the Accident? Yes alerts), events), and/or volume calculations) assist with 6c. Did SCADA-based information (such as alarms), Yes the detection of the Accident? No alert(s), events), and/or volume calculations) assist with 6d. Did SCADA-based information (such as alarms), 7. Was a CPM leak detection system in place on the pipeline or facility the confirmation of the Accident? No involved in the Accident? No 7a. Was it operating at the time of the Accident? 7b. Was it fully functional at the time of the Accident? alarms), alerts), events), and/or volume calculations) assist Tc. Did CPM leak detection system information (such as with the detection of the Accident? alarm(s), alerts), events), and/or volume calculations) assist 7d. Did CPM leak detection system information (such as 8. How was the Accident initially identified for the Operator? with the confirmation of the Accident? 8a. If "Controller" "Local Operating Personnel", including - If Other, Specify: Local Operating Personnel, including contractors contractor" is selected in Question 8, specify: contractors", "Air Patrol", or "Ground Patrol by Operator or its Operator employee 9. Was an investigation initiated into whether or not the controllers) or No, the Operator did not find that an investigation of the control room issues were the cause of or a contributing factor to the controllers) actions or control room issues was necessan due to: (provide an explanation for why the Operator did no - If No, the Operator did not find that an investigation of the (provide an explanation for why the operator did not investigate) controllers) actions or control room issues was necessary due to: Controller nor control room were a contributing factor - If Yes, specify investigation results): (select all that apply) - Investigation reviewed work schedule rotations, Operator), and other factors associated with fatigue continuous hours of service (while working for the - Investigation did NOT review work schedule rotations, Operator), and other factors associated with fatigue continuous hours of service (while working for the - Investigation identified no control room issues Provide an explanation for why not: - Investigation identified incorrect controller action or - Investigation identified no controller issues - Investigation identified that fatigue may have affected the controller(s) involved or impacted the involved controllers) - Investigation identified incorrect control room equipment - Investigation identified incorrect procedures - Investigation identified maintenance activities that affected control room operations, procedures, and/or controller - Investigation identified areas other than those above: PART F - DRUG & ALCOHOL TESTING INFORMATION under the post-accident drug and alcohol testing requirements of DOT's 1. As a result of this Accident, were any Operator employees tested Drug & Alcohol Testing regulations? No 1a. Specify how many were tested: Form PHMSA F 7000.1 <<>> 2. As a result of this Accident, were any Operator contractor employees 1b. Specify how many tailed: DOT's Drug & Alcohol Testing regulations? tested under the post-accident drug and alcohol testing requirements of No 2a. Specify how many were tested: 2b. Specify how many failed: PART G - APPARENT CAUSE Select only one box from PART Gin shaded column on left representing the APPARENT Cause of the Accident, and answer the questions on the right. Describe secondary, contributing or root causes of the Accident in the narrative (PART H). Apparent Cause: G1 - Corrosion Failure G1 - Corrosion Failure - only one sub-cause can be picked from shaded left-hand column - If External Corrosion: Corrosion Failure - Sub-Cause: Internal Corrosion 1. Results of visual examination: 2. Type of corrosion: (select all that apply) - If Other, Describe: 1 - Atmospheric - Galvanic - Microbiological - Stray Current - Other: - Selective Seam 3. The type(s) of corrosion selected in Question 2 is based on the following: (select all that apply) - If Other, Describe: - Field examination - Determined by metallurgical analysis 4. Was the failed item buried under the ground? protection at the time of the Accident? 04a. Was failed item considered to be under cathodic 4b. Was shielding, tenting, or disbonding of coating evident at If Yes - Year protection started: conducted at the point of the Accident? 4c. Has one or more Cathodic Protection Survey been If "Yes, Close Interval Survey" - Most recent year conducted: If "Yes, CP Annual Survey" - Most recent year conducted: - If No: If "Yes, Other CP Survey" - Most recent year conducted: 5. Was there observable damage to the coating or paint in the vicinity of 4d. Was the failed item externally coated or painted? the corrosion? 6. Results of visual examination: • If Internal Corrosion: . Type of corrosion (select all that apply): - Other: General Corrosion - Water drop-out/Acid Corrosive Commodity - Erosion - Microbiological - Other: - If Other, Describe: carbon dioxide Yes 8. The cause(s) of corrosion selected in Question 7 is based on the following (select all that apply): - - Field examination - Other: - Determined by metallurgical analysis Yes 9. Location of corrosion (select all that apply): - - If Other, Describe: - Low point in pipe - Other: - Elbow Yes Form PHMSA F 7000.1 <<>> 11. Was the interior coated or lined with protective coating? 10. Was the commodity treated with corrosion inhibitors or biocides? - If Other, Describe: Yes 12. Were cleaning/dewatering pigs (or other operations) routinely No Not applicable - Not mainline pipe 13. Were corrosion coupons routinely utilized? Complete the following if any Corrosion Failure sub-cause is selected AND the 'Item Involved in Accident" (from PART C, Not applicable - Not mainline pipe 14. List the year of the most recent inspections: 14a. API Std 653 Out-of-Service Inspection 14b. API Std 653 In-Service Inspection - No Out-of-Service Inspection completed Complete the following If any Corrosion Failure sub-cause is selected AND the "Item Involved in Accident" (from PART C, - No In-Service Inspection completed 15. Has one or more internal inspection tool collected data at the point of the Question 3) is Pipe or Weld. Accident? 15a. If Yes, for each tool used, select type of internal inspection tool and indicate most recent year run: - - Magnetic Flux Leakage Tool - Ultrasonic Most recent year: - Geometry Most recent year: - Caliper Most recent year: - Crack Most recent year: - Hard Spot Most recent year: - Combination Tool Most recent year: - Transverse Field/Triaxial Most recent year: - Other Most recent year: Most recent year: 16. Has one or more hydrotest or other pressure test been conducted since Describe: If Yes - original construction at the point of the Accident? No Most recent year tested: - If Yes, and an investigative dig was conducted at the point of the Accident.: Has one or more Direct Assessment been conducted on this segment? - If Yes, but the point of the Accident was not identified as a dig site: Most recent year conducted: 18. Has one or more non-destructive examination been conducted at the Most recent year conducted: point of the Accident since January 1, 2002? recent year the examination was conducted: 18a. If Yes, for each examination conducted since January 1, 2002, select type of non-destructive examination and indicate most - Guided Wave Ultrasonic Most recent year conducted: - Handheld Ultrasonic Tool Most recent year conducted: - Wet Magnetic Particle Test Most recent year conducted: - Dry Magnetic Particle Test Most recent year conducted: - Other Most recent year conducted: Most recent year conducted: Describe: G2 - Natural Force Damage - only one sub-cause can be picked from shaded left-handed column Natural Force Damage - Sub-Cause: 1. Specify: - If Earth Movement, NOT due to Heavy Rains/Floods: Form PHMSA F 7000.1 <<>> - If Heavy Rains/Floods: - If Other, Describe: 2. Specify: - If Lightning: - If Other, Describe: 3. Specify: 4. Specify: - If Temperature: - If Other Natural Force Damage: - If Other, Describe: Complete the following if any Natural Force Damage sub-cause is selected. 5. Describe: conjunction with an extreme weather event? 6. Were the natural forces causing the Accident generated in 6a. If Yes, specify: (select all that apply) - Tropical Storm - Hurricane - Tornado - Other - If Other, Describe: G3 - Excavation Damage - only one sub-cause can be picked from shaded left-hand column Excavation Damage - Sub-Cause: - If Previous Damage due to Excavation Activity: Complete Questions 1-5 ONLY IF the Item Involved in Accident" (from PART C, Question 3) is Pipe or Weld 1. Has one or more internal inspection tool collected data at the point of 1a. If Yes, for each tool used, select type of internal inspection tool and indicate most recent year run: - - Magnetic Flux Leakage - Ultrasonic Most recent year conducted: - Geometry Most recent year conducted: - Caliper Most recent year conducted: - Crack Most recent year conducted: - Hard Spot Most recent year conducted: - Combination Tool Most recent year conducted: - Transverse Field/Triaxial Most recent year conducted: - Other Most recent year conducted: Most recent year conducted: 2. Do you have reason to believe that the internal inspection was Describe: completed BEFORE the damage was sustained? original construction at the point of the Accident? 3. Has one or more hydrotest or other pressure test been conducted since Most recent year tested: 4. Has one or more Dired Assessment been conducted pressure (psig: - If Yes, and an investigative dig was conducted at the point of the Accident: - If Yes, but the point of the Accident was not identified as a dig site: Most recent year conducted: 5. Has one or more non-destructive examination been conducted at the Most recent year conducted: point of the Accident since January 1, 2002? recent year the examination was conducted: 5a. If Yes, for each examination, conducted since January 1, 2002, select type of non-destructive examination and indicate most - Guided Wave Ultrasonic Most recent year conducted: Most recent year conducted: Form PHMSA F 7000.1 <<>> - Handheld Ultrasonic Tool - Wet Magnetic Particle Test Most recent year conducted: - Dry Magnetic Particle Test Most recent year conducted: - Other Most recent year conducted: Most recent year conducted: Describe: Complete the following if Excavation Damage by Third Party is selected as the sub-cause. 6. Did the operator get prior notification of the excavation activity? 6a. If Yes, Notification received from: (select all that apply) - - Excavator - One-Call System - Contractor - Landowner Complete the following mandatory CGA-DIRT Program questions if any Excavation Damage sub-cause is selected. DIRT (www.cga-dirt.com)? 7. Do you want PHMSA to upload the following information to CGA- 8. Right-of-Way where event occurred: (select all that apply) - - Public - Private - If "Public", Specify: - Pipeline Property/Easement - If "Private", Specify: - Power/Transmission Line - Railroad - Federal Land - Dedicated Public Utility Easement - Data not collected 10. Type of excavation equipment: 12. Was the One-Call Center notified? 12a. If Yes, specify ticket number: exists, list the name of the One-Call Center notified: 12b. If this is a State where more than a single One-Call Center 15. Were facilities marked correctly? 14. Were facility locate marks visible in the area of excavation? Did the damage cause an interruption in service? 17. Description of the CGA-DIRT Root Cause (select only the one predominant first level CGA-DIRT Root Cause and then, where 16a. If Yes, specify duration of the interruption (hours) available as a choice, the one predominant second level CGA-DIRT Root Cause as well): - If One-Call Notification Practices Not Sufficient, specify: - If Locating Practices Not Sufficient, specify: - If Other/None of the Above, explain: - If Excavation Practices Not Sufficient, specify: G4 - Other Outside Force Damage - only one sub-cause can be selected from the shaded left-hand column Other Outside Force Damage - Sub-Cause: - If Damage by Car, Truck, or Other Motorized Vehicle/Equipment NOT Engaged in Excavation: - If Damage by Boats, Barges, Drilling Rigs, or Other Maritime Equipment or Vessels Set Adrift or Which Have Otherwise Lost 1. Vehicle/Equipment operated by: 2. Select one or more of the following IF an extreme weather event was a factor: - Tornado - Tropical Storm - Other - Heavy Rains/Flood - If Previous Mechanical Damage NOT Related to Excavation: Complete Questions 3-7 ONLY IF the "Item Involved in - If Other, Describe: 3. Has one or more internal inspection tool collected data at the point of Accident" (from PART C, Question 3) is Pipe or Weld. Form PHMSA F 7000.1 <<>> the Accident? 3a. If Yes, for each tool used, select type of internal inspection tool and indicate most recent year run: - Magnetic Flux Leakage - Ultrasonic Most recent year conducted: - Geometry Most recent year conducted: - Caliper Most recent year conducted: - Crack Most recent year conducted: - Hard Spot Most recent year conducted: - Combination Tool Most recent year conducted: - Transverse Field/Triaxial Most recent year conducted: - Other Most recent year conducted: Most recent year conducted 4. Do you have reason to believe that the internal inspection was Describe: completed BEFORE the damage was sustained? since original construction at the point of the Accident? 5. Has one or more hydrotest or other pressure test been conducted - If Yes: Most recent year tested: 6. Has one or more Direct Assessment been conducted on the pipeline Test pressure (psig): segment? - If Yes, and an investigative dig was conducted at the point of the Accident: - If Yes, but the point of the Accident was not identified as a dig site: Most recent year conducted: 7. Has one or more non-destructive examination been conducted at the Most recent year conducted: point of the Accident since January 1, 2002? recent year the examination was conducted: 7a. If Yes, for each examination conducted since January 1, 2002, select type of non-destructive examination and indicate most - Guided Wave Ultrasonic Most recent year conducted: - Handheld Ultrasonic Tool Most recent year conducted: - Wet Magnetic Particle Test Most recent year conducted: - Dry Magnetic Particle Test Most recent year conducted: - Other Most recent year conducted: Most recent year conducted: - If Intentional Damage: Describe: 8. Specify: - If Other Outside Force Damage: - If Other, Describe: 9. Describe: G5 - Material Failure of Pipe or Weld - only one sub-cause can be selected from the shaded left-hand column "Weld." Use this section to report material failures ONLY IF the "Item Involved in Accident" (from PART C, Question 3) is "Pipe" or Material Failure of Pipe or Weld - Sub-Cause: 1. The sub-cause shown above is based on the following: (select all that apply) - Determined by Metallurgical Analysis - Field Examination - Other Analysis - Sub-cause is Tentative or Suspected; Still Under Investigation - If "Other Analysis", Describe: (Supplemental Report required) Form PHMSA F 7000.1 <<>> - If Construction, Installation, or Fabrication-related Or If Original Manufacturing-related: T 2. List contributing factors: (select all that apply) - Fatigue or Vibration-related - If Other, Describe: Specify: - Mechanical Stress: - Other - If Environmental Cracking-related: - If Other, Describe: 3. Specify: - If Other - Describe: Complete the following if any Material Failure of Pipe or Weld sub-cause is selected. 4. Additional factors: (select all that apply): - Dent - Pipe Bend - Gouge - Arc Burn - Lack of Fusion - Crack - Buckle - Lamination - Misalignment - Wrinkle - Burnt Steel - Other: 5. Has one or more internal inspection tool collected data at the point of - If Other, - **truncated:** true - **body characters:** 44928