CAL FIRE - Of?ce of the State Fire Marshal Pipeline Safety Division Pipeline Accident Report: Failure Investigation Report Lead Investigator Name/Title: Thomas M. Williams IV, Pipeline Safety Engineer Supervisor Name/Title: Linda Zigler, Supervising Pipeline Safety Engineer, Chuck MacDonald, Supervising Pipeline Safety Engineer Activity Report 20160520TMW1 Report Date: April 6, 2017 Cal OES Control 16-2999 NRC Report #:1148267 and 1148268 OPERATOR, LOCATION, AND CONSEQUENCES Date of Failure: May 20, 2016 Time Detected: 0035 hours, Pacific Standard Time (PST) Operator Name: Shell Pipeline Company, LP CSFM Billing Code: 330 CSFM Inspection Unit 0560A CSFM Pipeline ID 0708 (North San Joaquin Valley - Tracy to Avon) PHMSA Operator ID: 31174 Leak Location (CityICounty): Latitude I Longitude Location: Pipeline: 20/24 inch ?Tracy to Avon ln ras a plpe lne Type of Failure: Seam Failure - weld Commodity Released: Crude Oil Number of Barrels Released: 500 barrels Number of Barrels Recovered: 400 barrels Number of Fatalities: None Number of Injuries: None Waterways Impacted: None Description of Property Damage: Contaminated Soil Total Costs (Property Damag? Commodity Loss Estimated Total): $4,540,000 1. WM 454/2? 7 Thomas M. Williams lv, Pipeline Safety Engineer Ml 4/z/2w7 Chuck Mac Donald, Supervising Pipeline Safety Engineer Page 1 EXECUTIVE SUMMARY At 0035 hours (PST) May 20, 2016, the Shell Pipeline Company LP Control Center located in Houston, Texas detected a drop in the operating pressure on the North San Joaquin Valley (SJV) pipeline system. The Tracy Pump Station automatically shut down on low suction pressure and the Houston Control Center Controller immediately shut down the entire SJV pipeline system and isolated the leaking section of pipe by closing the mainline line block valves at Westley, Tracy, Marsh Creek and Avon Pump Stations. The failure occurred in an open field on the Tracy to Windmills Farm segment of the Tracy Pump Station to Avon Pump Station (CSFM Line ID #0708) pipeline approximately of a mile north of the Tracy Pump Station located near West Patterson Pass Road and Interstate 580 in Alameda County, California. No waterways were impacted, and no fire, injuries or death occurred because of the spill. A 79.8-foot section of pipe containing the rupture was cut out and replaced with a new section of pre-hydrostatically pressure tested pipe. A 26-foot long section of pipe containing the rupture was transferred via chain of custody to Det Norske Veritas, Inc. (DNV-GL), a testing laboratory in Dublin, Ohio, for metallurgical examination. A review of the metallurgical examination results in the Laboratory Report Number OAPU8311MPHB (PP158491) issued on November 7, 2016, revealed the pipe ruptured at a fatigue crack that initiated at the toe of the Double Submerged Arc Weld (DSAW) longitudinal seam weld on the inside surface of the pipe. The release occurred on pipe that was originally purchased by Texaco Trading Transportation Inc. from Columbia Gas and installed by Texaco in 1989. After repairs were made, the entire pipeline was hydrostatically pressure tested, and the pipeline was reactivated on July 19, 2016. Page 2 DESCRIPTION OF THE PIPELINE SYSTEM The North SJV pipeline system is part of common carrier pipeline system that delivers, heavy, light and blended crude oil from the San Joaquin Valley to San Francisco Bay area refineries. The entire system is approximately 177 miles in length and starts at the Coalinga Pump Station and terminates at the Martinez Refinery. The entire system was originally constructed by Texaco Trading 8 Transportation Inc. This system is comprised of the following seven pipeline segments: I CSFM Line ID #0704 is a 24?inch pipeline originally constructed in 1967 that transports crude oil 6.14 miles from Shell Coalinga Tank Farm to Mack Hill Valve Station. I CSFM Line ID #0401 is a 20-inch pipeline originally constructed in 1967 that transports crude oil 46.44 miles from Mack Hill Valve Station to Panoche Pump Station. I CSFM Line ID #0705 is a 20-inch pipeline originally constructed in 1968 that transports crude oil 34.6 miles from Panoche Pump Station to Butts Road Valve Station. I CSFM Line ID #0707 is a 24-inch pipeline originally constructed in 1967 that transports crude oil 7.07 miles from Butts Road Valve Station to Gustine Pump Station. I CSFM Line ID #0796 is a 20-inch pipeline originally constructed in 1967 that transports crude oil 42.17 miles from Gustine Pump Station to Tracy Pump Station. I CSFM Line ID #0708 is a pipeline originally constructed in 1968 that transports crude oil 38.12 miles from Tracy Pump Station to Avon Pump Station. I CSFM Line ID #0709 is a 20-inch pipeline originally constructed in 1968 that transports crude oil 2.98 miles from Avon Pump Station to Martinez Refinery. According to representatives of 12.55 miles of the following segments in the North SJV system have pipe that was purchased from Columbia Gas by Texaco Trading and Transportation. This pipe was manufactured in Houston, Texas by Armco Steel in 1982 and was shipped from Columbia Gas in the northeast United States to Coalinga, California in 1988. I CSFM Line ID 0708 3.05 miles of the total 38.12-mile long pipeline. I CSFM Line ID 0704 3.4 miles of the total 6.14-mile long pipeline. I CSFM Line 0707 6.1 miles of the total 7.07-mile long pipeline. Page 3 DESCRIPTION OF PIPELINE FAILURE AND INITIAL RESPONSE A sudden pressure loss was detected by the Control Center at 0035 hours (PST) on May 20, 2016. The Tracy Pump Station automatically shut down on low suction pressure and the Houston Controller immediately shutdown the entire North SJV pipeline system. The Controller then isolated the leaking section of pipeline by closing the following motor operated valves (MOV): Westley Valve #001, Tracy Valve #008, Marsh Creek Valves #001 and #008, North 20/24?inch Main Line Block Valves #158 and #169, and the Avon #1 Block Valve. These valves were closed in their pre-planned sequence to prevent any pressure surges. Calculated pressure at the release location at the time of failure was 694 psi. notified both the California Office of Emergency Services (Cal DES) and the National Response Center (NRC). CAL FIRE Office of the State Fire Marshal (OSFM) responded to the release after being notified by Cal OES. The pipeline failure was in a rural area with dry grass on rolling hills. Vacuum trucks were brought in to recover the spilled oil. At the time of the failure, the pipeline was transporting SJV heavy crude oil. The flowrate was 6,126 barrels per hour (BPH) and the discharge pressure was 694 psi at the Tracy Pump Station. The maximum operating pressure (MOP) was 936 psi. Representatives of and the Oil Spill Response Organizations Patriot Environmental Services and Ponder Environmental Services excavated, exposed the pipeline, and recovered the spilled oil. Crude oil had sprayed over an area of approximately 100 feet long by 100 feet wide and had partially soaked into the soil. According to the United States Department of Transportation, Pipeline and Hazardous Materials Safety Administration (PHMSA) Accident Report Form 7000-1 submitted by approximately 500 barrels of crude oil was released and 400 barrels were recovered. Excavation of the failed pipe showed that a rupture occurred along the length of the longitudinal seam at the 3:26 o?clock position. The rupture was approximately 3.77 feet in length by 4.5 inches in width, defined as a fish mouth failure. The seam failure was located 14.17?feet and 17.94-feet respectively from the upstream girth weld. The specifications of the failed pipe section are: Year Manufactured: 1982 Manufacturer: Armco Steel Pipe Diameter: 24-inch Outside Diameter Wall Thickness: 0.260-inch Specified Minimum Yield Strength: (60,000 psi) Pipe Specification: Pipe Seam: Double Submerged Arc Weld (DSAW) Type of Coating: Polyolefin Depth of Cover: 84-inches Page 4 REMOVAL OF DEFECTIVE PIPE SECTION was contracted by to perform the metallurgical examination of the failed pipe. At approximately 0300 hours (PST) on May 22, 2016, a 79-foot 8-inch long section of the 24-inch pipe containing the seam failure was cut out and removed. Pipeline Safety Engineers from OSFM were on site to monitor the activities. An estimated 29-foot pipe section that contained the 26.4-foot field joint was wrapped in plastic, mounted and secured on pallets, and stored in a guarded area until it could be transported to the Laboratory in Dublin, Ohio. OSFM staff witnessed the chain of custody process of the failed pipe section from to a third?party shipping contractor, Byars Trucking. handled the pipe section according to ?Handling Instructions for Retrieval of Pipe Section(s) Containing Defects SJV 24-inch Crude Line? procedure, dated September 17, 2015. Representatives of followed their Chain of Custody procedures for storing and shipping of the pipe. PIPELINE REPAIRS On May 22, 2016, a 79-foot 8-inch long section of pre-hydrostatically tested pipe (CSFM Test ID #16-04897) was installed by Doty Brothers Construction Company of NonNalk, California. The hydrostatic pressure test was conducted by Contra Costa Inspection (CCI), an OSFM approved hydrostatic testing firm. The specifications for the replacement pipe are: Manufacturer: CSI Tubular Products, Inc., Fontana, California Pipe Diameter: 24-inch Outside Diameter Wall Thickness: 0.375-inch Specified Minimum Yield Strength: X-65 (65,000 psi) Pipe Specifications: Pipe Seam: Electric Resistance Weld (ERW) Prior to Doty Brothers? personnel performing the repairs of the pipeline, OSFM Pipeline Safety Engineers verified the Operator Qualification (00) records of the following: - Lead Inspector - Doty Brothers welders - Applus Non-Destructive Testing Technician. OSFM Pipeline Safety Engineers observed the welding of the replaced section of 24?inch pipe. The pipeline tie-in welds were non?destructively tested by x?ray and a phased array ultrasonic test, performed by Applus. After the welds were successfully Page 5 tested, the tie-in welds were coated with a 3-Iayer epoxy and were wrapped with Polyken Liquid Adhesive and Polyken tape coating. On May 23, 2016, after consultation with the OSFM, the North SJV pipeline system was temporarily returned to service at a 20% reduced pressure from 694 psi to 555 psi to displace the heavy crude oil remaining in the line to prevent the crude oil from solidifying in the pipeline. The pipeline temporarily operated at 555 psi, which is a 20% reduced pressure from the 694 psi pressure at the time of the failure. The pipeline system was shut down after the crude oil was displaced. Prior to reactivation of the North SJV pipeline system, successfully hydrostatic tested the following segments of the pipeline system that contain the suspected Columbia Gas pipe. I CSFM Line ID #0708 was hydrostatic tested on June 9, 2016 by Contra Costa Inspection (CSFM Test ID 16-05004). An 8-hour test was conducted and the minimum test pressure obtained was 1,070 psi. . CSFM Line ID #0704 was hydrostatic tested on June 17, 2016 by Contra Costa Inspection (CSFM Test ID 16?05015). An 8?hour test was conducted and the minimum test pressure obtained was 1,070 psi. - CSFM Line ID #0707 was hydrostatic tested on June 30,2016 by Contra Costa Inspection (CSFM Test 16- 0.5019) An 8? hour test was conducted and the minimum test pressure obtained was 1,070 psi. INVESTIGATION DETAILS The pipeline (CSFM Line ID #0708) experienced the following two previous releases due to seam failure. - June 6, 1998: (Equilon Pipeline Company) 300 barrels of crude oil was released near Midway Road and I-580. Pipe failed approximately one mile of Tracy Pump Station due to a pipe seam defect. An estimated 40 feet of pipe was replaced (Cal OES Control - September 16, 2015: (Shell Pipeline Company, LP) 900 barrels of crude oil was released at mile post 137, near Tracy, California, on the Coalinga to Avon pipeline. Pipeline ruptured at a pre-existing fatigue crack initiated from small corrosion pits along the internal surface at the toe of the longitudinal seam weld. (Cal OES Control 15-5483 NRC #1128732). A review of the September 16, 2015 pipeline rupture investigation report revealed that on August 6, 2015, TD Williamson (TDW) performed a Magnetic Flux Leak (MFL) and deformation In-Line Inspection (ILI) survey on the pipeline (CSFM Line 0708). The preliminary TDW ILI report issued on September 2, 2015 indicated no immediate conditions were found, as defined by Code of Federal Regulations, Title 49, Part 195.452. Fourteen days later, the pipeline ruptured approximately 1,800 feet Page 6 of the Tracy Pump Station. The final TDW ILI report was received by on October 14, 2015 and did not identify any metal loss or deformation anomalies at the leak location. Following the September 16, 2015 release, contracted with DNV-GL to perform a metallurgical analysis on the failed section of the pipe. This analysis determined that the pipe section ruptured at a pre-existing fatigue crack on the longitudinal seam. The line was repaired and resumed operation on September 21, 2015. initiated a voluntary 20% reduced operating pressure to 724 psi from the previoUs 905 psi while they investigated the pipeline for similar fatigue crack features. decided to use a Rosen Ultrasonic Crack Detection Tool (UT-C) and a Circumferential Magnetic Flux Leak Tool on the 24-inch pipe in the North SJV pipeline system. The Rosen tool was utilized on December 3, 2015 and the UT-C survey was utilized on December 4, 2015. A preliminary Rosen MFL-C ILI report on January 14, 2016 identified two metal loss anomalies on the Butts Road Valve Station to Gustine Pump Station pipeline (CSFM Line ID 0707). Type full encirclement sleeves were used to repair these anomalies. On March 7, 2016, Rosen issued the final MFL-C report that identified an additional 19 anomalies within a 42-foot section of pipe on the Butts Road Pump Station to GustinePump Station pipeline (CSFM Line ID 0707). These anomalies were also repaired using Type full encirclement sleeves. On April 11, 2016, the preliminary Rosen ILI report was received by In the report, five anomalies were. identified. Two of these anomalies were on the Tracy Pump Station to Avon Pump Station pipeline (CSFM Line ID 0708). These anomalies were excavated and no crack indications were found. The anomalies were recoated and the line was backfilled. Two anomalies were identified on the COalinga to Mack Hill Valve Station pipeline (CSFM Line ID 0704) requiring an excavation dig. The first anomaly revealed a crack like indication that was repaired with a Type full encirclement sleeve. The second anomaly identified a metal loss feature and it was repaired and recoated. The last anomaly identified by Rosen was a crack like anomaly on the Butts Road Valve Station to Gustine Pump Station pipeline (CSFM Line ID 0707). However, upon examination no dents or cracks were found and it was repaired with a Type full encirclement sleeve. On May 2, 2016, the final Rosen ILI report was provided to that identified two anomalies that required excavation. One anomaly was a 3~inch flat spot and the other anomaly was a seam weld repair that was done at the pipe mill. Both anomalies were repaired and recoated. Based on the Rosen MFL-C and UT-C results, decided to remove the pressure reduction on the 24-inch segments of the North SJV pipeline system. The 20% Operating pressure reduction was removed on May 17, 2016 Page 7 and the pipeline was operating at the normal operating pressure. Three days later, on May 20, 2016, the pipeline (CSFM Line 0708) failed approximately 4,000 feet of the Tracy Pump Station. Immediately following the release, and the OSFM requested that Rosen review and re-evaluate the data from the December 3 and 4, 2015 Rosen surveys. Rosen?s review of the data concluded that the survey data did not report any features at the location of the failure. contracted with Kinder Morgan Energy Partners to perform a Kinder MOrgan Assessment Protocol (KMAP) review of the Rosen data at the failure location. The KMAP is a Kinder Morgan proprietary analytical process that is designed to search for flaws in longitudinal seam welds. The result of the KMAP confirmed that there were no reportable features in the pipe section that failed from the data they received. conducted an internal Root Cause Analysis (RCA) on the May 20, 2016 rupture. According to the RCA, found that Rosen?s software used to evaluate the Rosen survey did identify a crack like feature in the longitudinal seam at the failure location. The RCA found that the Rosen software identified the crack as 7.594 inches long and 0.150 inches deep (57.7% of 0.260?inch nominal wall thickness) at odometer reading 4073.718 (rupture location). During the manual review by Rosen ?an incorrect amplitude was selected? and an anomaly depth was calculated at <0.08?inch. Rosen believed that the reporting threshold was 0.08-inch. The Rosen analyst then called the anomaly at 4073.718 (rupture location) as being 0.013-inch. RCA indicates that the Rosen report did not show an anomaly at the rupture location due to this error. As a result, resumed operations with normal Operating pressure on May 17, 2016. OSFM contacted Rosen to confirm the data provided in the RCA, however, Rosen only confirmed that they did not report the crack-?like anomaly at the position in the failed pipe section. also contracted with DNV-GL to perform a metallurgical analysis on the failed pipe. DNV-GL issued the final report of the metallurgical analysis on November 7, 2016 (Test Report Number OAPU8311MPHB The examinations performed to determine the metallurgical cause of the failure and to identify any contributing factors included; a visual and photographic examination, dimensional measurements, magnetic particle examination, light microscopy and scanning electron microscopy of the fracture surfaces, cross sections examination, energy dispersive spectroscopy, tensile tests and Charpy V-notch tests, chemical analysis of the steel, and failure pressure calculations. Page 8 A review of the final report of metallurgical examination conducted by DNV-GL revealed that: . The pipe joint ruptured at a fatigue crack initiated at the toe of the DSAW longitudinal seam weld on the inside surface of the pipe. - A likely contributing factor was a peaked geometry of the failed pipe joint at the seam weld that introduced a bending stress. . A contributing factor was corrosion micro?pits on the internal diameter surface that provided initiation sites. I A contributing factor of aggressive pressure cycling of the pipeline. - Possible environmental effect on crack growth. - Another possible contributing factor that could not be ruled out was transit fatigue during transportation of the pipe. conducted the metallurgical examination in accordance with industry accepted standards and used the following American Society for Testing and Materials (ASTM) standards: - ASTM E7 Standard Terminology Relating to Metallography . ASTM E3 Standard Methods of Preparation of Metallographic Specimens I ASTM E8 Test Methods for Tension Testing of Metallic Materials I ASTM E23 Standard Test Methods for Notched Bar Impact Testing of Metallic Materials - ASTM A751 Standard Test Methods Practices and Terminology for Chemical Analysis of Steel Products. According to the final report, there was no evidence of external corrosion found. Tensile testing indicated that the pipe met the tensile requirements for American Petroleum Institute (API) 5L Grade X60 pipe. The composition of the base metal of the failed joint and the joints up stream and down stream met the requirements of API- 5L Grade X80 pipe. It should be noted that the report also indicated that the fatigue crack likely occurred while the pipeline was in service, and that transit fatigue during the pipe transportation cannot be ruled out. According to transportation records, the pipe was manufactured by Armco Steel in Houston, Texas for Columbia Gas and was ?shipped to the northeast United States in 1982. In 1988, Texaco purchased the pipe from Columbia Gas and transported it to Coalinga, California for installation and the records for this shipment cannot be located. American Petroleum Institute Recommended Practice 5L1, ?Recommended Practice for Railroad Transportation of Line Pipe,? 7th edition, September 2009, (API RP 5L1) is used to assure that pipe is prOperly loaded and transported to avoid transit fatigue. API RP 5L1 also states that pipe with a diameter to wall thickness ratio greater than 50 is Page 9 susceptible to transit fatigue. The failed pipe had a ratio of 92 wall thickness). INVESTIGATION FINDINGS . - The OSFM concluded that the primary cause of the May 20, 2018 release was a fatigue crack that initiated at the toe of the longitudinal seam weld on the inside surface of the pipe (CSFM Line lD #0708) that developed and grew through continuous pressure cycling. - The May 2, 2016, Rosen UT-C report failed to identify the crack like feature in the longitudinal seam of the pipe. . It is possible that transit fatigue may have occurred during transportation of the pipe in 1988. RECOMMENDATIONS 1. Effective immediately, the Tracy Pump Station to Avon Pump Station pipeline (CSFM Line 0708) shall be placed on the State Fire Marshal?s list of higher risk pipeiines as required by Government Code Section 51013.5 will be required to either perform in?line inspections or hydrostatic tests every two years. The pipeline will be removed from this list after May 20, 2021, if there are no more leaks due to corrosion or manufacturing defects during this time. 2. shall replace the entire sections of the pipeline that contain ?Columbia Pipe?. These sections are the 3.05 miles of the total 38.12-mile long pipeline from Tracy Pump Station to Avon Pump Station (CSFM Line lD 0708), 3.4 miles of the 6.14-mile long pipeline from Coalinga Pump Station to Mack Hill Valve Station (CSFM Line ID 0704), and 8.1 miles of the 7.07?mile long pipeline from Butts Road Valve Station to Gustine Pump Station (CSFM Line ID 0707). 3. shall require all vendors to immediately notify personnel of any raw data that is excluded from all future reports. should also review their process for conducting crack detection surveys for all seam types of pipe DSAW, ERW, etc. 4. shall review and evaluate their pipelines that undergo aggressive pressure cycling to determine if additional crack detection surveys should be conducted on these pipelines and to determine if pressure cycling can be minimized. 5. The OSFM Pipeline Safety Division shall conduct a comprehensive and in-depth Headquarters review of Integrity Management Program. This inspection will be conducted the week of September 25, 2017. Page 10 Photo Log of Spill - Operator: Shell Pipeline Company LP. Tracy Windmill Farms Spill Date: May 20, 2016. Photograph #1 Description of Photograph: Photo taken by Pipeline Safety Engineer Thomas Williams on the morning of May 20, 2016 This is an overview of the San Joaquin Valley Heavy Crude Oil (CSFM #0708) spill site (Tracy Windmill Farms looking South.) Photograph #2 Description of Photograph: Photo taken by Pipeline Safety Engineer Thomas Williams on May 20, 2016. This is another overview of the spill on The San Joaquin Valley 20124? Heavy Crude Oil (CSFM #0708) Tracy Windmill Farms looking North. Photograph #3 Description of Photograph: Photo taken by Pipeline Safety Engineer Thomas Williams on the morning of May 21, 2016. This is a View of the rupture on The San Joaquin Valley 20l24? Heavy Crude Oil (CSFM #0708) . 375 ?3-343?? 240-?) i810 H#-l30034h\ 2? Photograph #4 Description of Photograph: This is a picture of the CSFM Pre-hydrotested pipe information Photo taken by Pipeline Safety Engineer Thomas Williams on the morning of May 21, 2016. Photograph #5 Description of Photograph: Photo taken by Pipeline Safety Engineer Thomas Williams on May 22, 2016. This is a photo of Doty Brothers Construction Company cutting out the failed section of pipe to send to Lab. Photograph #6 Description of Photograph: Photo taken by Pipeline Safety Engineer Thomas Williams on the early morning of May 22, 2016. This is a photo of Doty Brothers Construction Company weld the new section of pipe. Photograph #6 Description of Photoqraph: Photo taken by Pipeline Safety Engineer Thomas Williams on the early morning of May 22, 2016. This is a photo of ApplusRTD technicians shooting x-rays on the welds on CSFM #0708 Photograph #6 Description of Photoqraph: Photo taken by Pipeline Safety Engineer Thomas Williams on May 22, 2016. This is a photo of ApplusRTD technicians using Phased Array Hazardous Materials Spill Report - 16?2999 Page 1 of 2 Governor's Of?ce Emergency Services Hazardous Materials Spill Report DATE: 05/20/2016 RECEIVED BY: TIME: 0221 Cal OES - 16-2999 NRC - La. PERSON NOT IFYING Cal OES: 1. NAME: 2. AGENCY: 3. 4. Ext: 5. Shell Pipeline 1.b. PERSON REPORTING SPILL (If different from above): 1. NAME: 2. AGENCY: 3. 4. Ext: 5. 2. SUBSTANCE TYPE: 2. a. Measure c. TYPE: d. OTHER: e. f_ VESSEL SUBSTANCE: - PIPELINE 300 Tons 1. Crude Oil Unknown Bbl-(S) PETROLEUM Yes POTENTIAL RELEASE RP States: Drop in pressure in the pipeline that DESCRIPTION: connects from Martinez to Coalinga, possibly in the Tracy area per his supervisor. Unknown on any release, though pressure would indicate that a release is occurring somewhere on the line. The line has been isolated, shutdown from Houston, Texas. h. CONTAINED: i. WATER j. WATERWAY: k. DRINKING WATER INVOLVED: IMPACTED Unknown Unknown Unknown 1. KNOWN Unknown IMPACT - 3. a. INCIDENT LOCATION: Between Tracy and Martinez, closer to Tracy. Station markers are Tracy station and Marsh Creek. b. CITY: c. COUNTY: d. ZIP: Tracy San Joaquin County SAN JOAQUIN VALLEY UNIFIED APCD 4. INCIDENT DESCRIPTION: 3. DATE: b. TIME (Mz'liraiy): 0. SITE: - d. REPORTED CAUSE 05/20/2016 0205 Pipe Line Unknown e. INJURIES f. ATALITY g. EVACUATION 11. CLEANUP BY: No No No Unknown 6. NOTIFICATION INFORMATION: 21. ON SCENE: b. OTHER ON SCENE: c. OTHER NOTIFIED: d. ADMIN. AGENCY: San Joaquin County e. SEC. AGENCY: Environmental Health f. ADDITIONAL COUNTY: Alameda g. ADMIN. AGENCY: Alameda County County, Contra Costa County Environmental Health, Contra Costa County Health Services Department h. NOTIFICATION LIST: DOG Unit: 6 Unit: 5B DPG-OSPR, DTSC, US EPA, USFWS, COASTAL COM, CDPH-D.O., DOG, EB PARKS, LANDS, PARKS REC, SFM, USCG, P, Co/Hlth, Co/E?Hllh 1 1/28/2016 Hazardous Materials Spill Report 16?2999 Page 2 of 2 llihoto Attachment: Control No: 16-2999 Created by: Waming Center on: 05/20/2016 02:21:27 AM Last Modi?ed by: Warning Center on: 05/20/2016 02:49:58 AM 11/28/2016 Hazardous Materials Spill Update - 16?2999 Page 1 of 2 PreVDoc NextDoc Governor?s Office of Emergency Services Hazardous Material Spill Update CON 16-2999 114826 7 NOTIFY RECEIVED BY: AREA: 05/20/2016 0221 OCCURENCE Tracy/San Joaquin County 05/20/2016/0205 SAN JOAQUIN VALLEY UNIFIED APCD 1.a. PERSON NOTIFYING Cal OES: Shel1 Pipeline 1.b. PERSON REPORTING SPILL (If different from above): IAGENCY: ll SUBSTANCE TYPE: a. SUBSTANCE: b. QTY: Measure c. TYPE: d. OTHER: 9, PIPELINE f, VESSEL Amount 300 Tons 1.Crude Oil Unknown Bbl-(S) PETROLEUM Yes Orignal Description:POTENTIAL RELEASE RP States: Drop in pressure in the pipeline that connects from Martinez to Coalinga, possibly in the Tracy area per his supervisor. Unknown on any release, though pressure would indicate that a release is occurring somewhere on the line. The line has been isolated, shutdown from Houston, Texas. PERSON NOTIFYING Cal OES OF SPILL UPDATE: NAME: AGENCY: Ext: NRC UP ATE Measure QUANTITY Amount 1_ Bb1.(s) 2. 3. 4. UPDATE KNOWN IMPACT: IUPDATE CAUSE: SITUATION UPDATE: Per the NRC Report: SCADA SYSTEM NOTICED A COMPLETE LOSS OF PRESSURE ON A 24? PIPELINE. THE LINE WAS SHUT-DOWN AND COULD HAVE POTENTIALLY DISCHARGED PETROLEUM CRUDE. BELOW GROUND PIPELINE. REMEDIAL ACTIONS 11/28/2016 Hazardous Materials Spill Update - 16?2999 Page 2 of 2- CREWS ENROUTE FOR ASSESSMENT, NOTIFIED LINE IS DOWN, VALVES ARE FAX NOTIFICATION LIST: DFG-OSPR, DTSC, US EPA, USFWS, COASTAL COM, DOG, EB PARKS, LANDS, PARKS REC, SFM, USCG, Co/HIth, Co/E?Hlth ADMINISTERING San Joaquin County Environmental Health AGENCY: SECONDARY AGENCY: ADDITIONAL COUNTIES: Alameda County, Contra Costa County ADDITIONAL ADMIN. Alameda County Environmental Health, Contra Costa County Health Services AGENCY: Department OTHER NOTIFIED: Unit: SB CONFIRMATION REQUEST: FAX NOTIFICATION LIST: ADMINISTERING AGENCY: ADDITIONAL ADMIN. AGENCY: SECONDARY AGENCY: ADDITIONAL COUNTIES: DOG Unit: Unit: Created by: Warning Center on: 05/20/2016 03:04:37 AM Last Modi?ed by: Warning Center on: 05/20/2016 03:11:09 AM 11/28/2016 Hazardous Materials Spill Update 16-2999 Page 1 of 2 PrevDoc NextDoc Governor's Office of Emergency Services Hazardous Material Spill Update 16-2999 NOTIFY RECEIVED BY: AREA: 05/20/2016 0221 OCCURENCE Tracy/ San Joaquin County 05/20/2016/0205 SAN JOAQUIN VALLEY UNIFIED APCD La. PERSON NOTIFYING Cal OES: Shell Pipeline 1 1.b. PERSON REPORTING SPILL (If different from above): IAGENCY: SUBSTANCE TYPE: 3. SUBSTANCE: b. QTY: Measure c. TYPE: (1. OTHER: 3, PIPELINE f, VESSEL Amount 300 Tons LCrude Oil Unknown Bbl-(S) PETROLEUM Yes Orignal Description1POTENTIAL RELEASE RP States: Drop in pressure in the pipeline that connects from Maltinez to Coalinga, possibly in the Tracy area per his supervisor. Unknown on any release, though pressure would indicate that a release is occurring somewhere on the line. The line has been isolated, shutdown from Houston, Texas. Update(s): 05/20/2016 03:04:37 AM - Per the NRC Report: SCADA SYSTEM NOTICED A COMPLETE LOSS OF PRESSURE ON A 24" PIPELINE. THE LINE WAS SHUT-DOWN AND COULD HAVE POTENTIALLY DISCHARGED PETROLEUM CRUDE. BELOW GROUND PIPELINE. REMEDIAL ACTIONS CREWS ENROUTE FOR ASSESSMENT, NOTIFIED LINE IS DOWN, VALVES ARE 05/20/2016 04:03:39 AM RP States: No waterways impacted. Location: .75 miles NNW of West Patterson Past Road and I 580 in San Joaquin County. 500 barrels is equivalent to 21,000 gallons of crude oil released. PERSON NOTIFYING Cal OES OF SPILL UPDATE: NAME: AGENCY: Ext: Shell Pipeline UPDATE rWeasure QUANTITY Amount 1. 500 1313118) 2. 3. 11/28/2016 Hazardous Materials Spill Update 16-2999 Page 2 of 2 4. UPDATE KNOWN IMPACT: UPDATE CAUSE: SITUATION UPDATE: RP States: No waterways impacted. Location: .75 miles NNW of West Patterson Past Road and I 580 in San Joaquin County. 500 barrels is equivalent to 21,000 gallons of crude oil released. FAX NOTIFICATION LIST: DFG-OSPR, DTSC, us EPA, usrws, COASTAL COM, DWP-DO, DOG, EB PARKS, LANDS, PARKS REC, SFM, USCG, Co/Hlth, Co/E-Hlth ADMINISTERING San Joaquin County Environmental Health AGENCY: SECONDARY AGENCY: ADDITIONAL COUNTIES: Alameda County, Contra Costa County ADDITIONAL ADMIN. Alameda County Environmental Health, Contra Costa County Health Services AGENCY: Department OTHER NOTIFIED: Unit: 5B CONFIRMATION REQUEST: Please con?rm receipt via email or call 916?845-8911. FAX NOTIFICATION LIST: ADMINISTERING AGENCY: ADDITIONAL ADMIN. AGENCY: SECONDARY AGENCY: ADDITIONAL COUNTIES: DOG Unit: Unit: Created by: Wanting Center on: 05/20/2016 04:03:39 AM Last Modi?ed by: Warning Center on: 05/20/2016 04:24:40 AM 11/28/2016 Hazardous Materials Spill Update - 16?2999 Page 1 of2 x717- Mw?? 331/ Governor's Of?ce of Emergency Services Hazardous Material Spill Update 16?2999 NOTIFY RECEIVED BY: AREA: 05/20/2016 0221 OCCUREN CE Tracy/San Joaquin County 05/20/2016/0205 SAN JOAQUIN VALLEY UNIFIED APCD La. PERSON NOTIFYING Cal OES: LAGENCY: Shell Pipeline 1.b. PERSON REPORTING SPILL (If different from above): EGENCY: 1 SUBSTANCE TYPE: a. SUBSTANCE: 1). QTY: Measure c. TYPE: (1. OTHER: e, PIPELINE f, VESSEL Amount 300 Tons 1.Crude Oil PETROLEUM Yes Origna] Description:POTENTlAL RELEASE RP States: Drop in pressure in the pipeline that connects from Martinez to Coalinga, possibly in the Tracy area per his supervisor. Unknown on any release, though pressure would indicate that a release is occurring somewhere on the line. The line has been isolated, shutdown from Houston, Texas. Update(s): 05/20/2016 03:04:37 AM Per the NRC Report: SCADA SYSTEM NOTICED A COMPLETE LOSS OF PRESSURE ON A 24" PIPELINE. THE LINE WAS AND COULD HAVE POTENTIALLY DISCHARGED PETROLEUM CRUDE. BELOW GROUND PIPELINE. REMEDIAL ACTIONS CREWS ENROUTE FOR ASSESSMENT, NOTIFIED LINE IS DOWN, VALVES ARE 05/20/2016 04:03:39 AM RP States: No waterways impacted. Location: .75 miles NNW of West Patterson Past Road and I 580 in San Joaquin County. 500 barrels is equivalent to 21,000 gallons of crude oil released. 05/20/2016 04:24:53 AM - Per NRC TO THE REPORTING PARTY THERE IS A DISCHARGE OF 500 BARRELS OF CRUDE OIL ONTO THE GROUND. NO WATERWAYS IMPACTED. REMEDIAL ACTIONS ?5 CREWS ENROUTE FOR ASSESSMENT, NOTIFIED LINE IS DOWN, VALVES ARE CLOSED. ACCORDING TO THE REPORTING PARTY THERE IS A DISCHARGE OF 500 BARRELS OF CRUDE OIL ONTO THE GROUND. NO WATERWAYS IMPACTED. THE NEW NRC REPORT NUMBER IS 1 148268. 05/21/2016 02:40:43 PM Per RP the spill is in Alameda County PERSON NOTIFYING Cal OES OF SPILL UPDATE: NAME: AGENCY: Ext: Shell Pipeline Measure 84lal 03cl 10/25/2016 Hazardous Materials Spill Update 16-2999 Page 2 of 2 UPDATE QUANTITY Amount 1. Bbl.(s) 2. 3. 4. KNOWN IMPACT: lL UPDATE CAUSE: SITUATION UPDATE: Per RP the spill is in Alameda County FAX NOTIFICATION LIST: Exist/Claims DTSC, US EPA, COASTAL COM, DWP-DO, DOG, EB PARKS, LANDS, PARKS REC, SFM, USCG, 0H ti, -- In ADMINISTERING AGENCY: San Joaquin County Environmental Health SECONDARY AGENCY: ADDITIONAL COUNTIES: Alameda County, Contra Costa County ADDITIONAL ADMIN. Alameda County Environmental Health, Contra Costa County Health Services Department AGENCY: OTHER NOTIFIED: Unit: SB CONFIRMATION REQUEST: FAX NOTIFICATION LIST: ADMINISTERIN AGENCY: ADDITIONAL ADMIN. AGENCY: SECONDARY AGENCY: ADDITIONAL COUNTIES: DOG Unit: Unit: Created by: Warning Center on: 05/21/2016 02:40:43 PM Last Modi?ed by: Warning Center on: 05/21/2016 02:43:54 PM 10/25/2016 Hazardous Materials Spill Update 16-2999 Page 1 of 2 PrevDoc NextDoc Governor's Of?ce of Emergency Services Hazardous Material Spill Update 16-2999 NOTIFY RECEIVED BY: AREA: 05/20/2016 0221 OCCURENCE Tracy/San Joaquin County 05/20/2016/0205 SAN JOAQUIN VALLEY UNIFIED APCD 1.a. PERSON NOTIFYING Cal OES: Shell Pipeline - Lb. PERSON REPORTING SPILL (If different from above): IAGENCY: ?1 SUBSTANCE TYPE: 3. SUBSTANCE: b. QTY: Measure c. TYPE: (1. OTHER: 9_ PIPELINE f_ VESSEL Amount 300 TOIIS 1.Crude Oil Unknown Bbl-(S) PETROLEUM Yes Orignal Description:POTENTIAL RELEASE RP States: Drop in pressure in the pipeline that connects from Martinez to Coalinga, possibly in the Tracy area per his supervisor. Unknown on any release, though pressure would indicate that a release is occurring somewhere on the line. The line has been isolated, shutdown from Houston, Texas. Update(s): 05/20/2016 03:04:37 AM Per the NRC Report: SCADA SYSTEM NOTICED A COMPLETE LOSS OF PRESSURE ON A 24? PIPELINE. THE LINE WAS AND COULD HAVE POTENTIALLY DISCHARGED PETROLEUM CRUDE. BELOW GROUND PIPELINE. REMEDIAL ACTIONS CREWS ENROUTE FOR ASSESSMENT, NOTIFIED LINE IS DOWN, VALVES ARE 05/20/2016 04:03:39 AM - RP States: NO waterways impacted. Location: .75 miles NNW of West Patterson Past Road and I 580 in San Joaquin County. 500 barrels is equivalent to 21,000 gallons of crude oil released. 05/20/2016 04:24:53 AM - Per NRC TO THE REPORTING PARTY THERE IS A DISCHARGE OF 500 BARRELS OF CRUDE OIL ONTO THE GROUND. NO WATERWAYS IMPACTED. REMEDIAL ACTIONS CREWS ENROUTE FOR ASSESSMENT, NOTIFIED LINE IS DOWN, VALVES ARE CLOSED. ACCORDING TO THE REPORTING PARTY THERE IS A DISCHARGE OF 500 BARRELS OF CRUDE OIL ONTO THE GROUND. NO WATERWAYS IMPACTED. THE NEW NRC REPORT NUMBER IS 1148268. 11/28/2016 Hazardous Materials Spill Update - 16-2999 Page 2 of 2 05/21/2016 02:40:43 PM - Per RP the spill is in Alameda County PERSON NOTIFYING Cal OES OF SPILL UPDATE: NAME: AGENCY: Ext: Shell Pipeline UPDATE Measure QUANTITY Amount 1. Bb1.(s) 2. 3. 4. UPDATE KNOWN IMPACT: UPDATE CAUSE: 1T SITUATION UPDATE: Per RP the spill is in Alameda County FAX NOTIFICATION LIST: DTSC, US EPA, USFWS, COASTAL COM, DOG, EB PARKS, LANDS, PARKS REC, SFM, USCG, 1th, Co/E?Hlth ADMINISTERING San Joaquin County Environmental Health AGENCY: SECONDARY AGENCY: ADDITIONAL COUNTIES: Alameda County, Contra Costa County ADDITIONAL ADMIN. Alameda County Environmental Health, Contra Costa County Health Services AGENCY: Department OTHER NOTIFIED: Unit: 5B CONFIRMATION REQUEST: FAX NOTIFICATION LIST: ADMINISTERING AGENCY: . ADDITIONAL ADMIN. AGENCY: SECONDARY AGENCY: ADDITIONAL COUNTIES: DOG Unit: Unit: Created by: Warning Center on: 05/21/2016 02:40:43 PM Last Modi?ed by: Warning Center on: 05/21/2016 02:43:54 PM 11/28/2016 W: 148267: Pipeline - Tracy, CA (55 miles of San Francisco, CA), unknown Page 1 of 5 FW: Pipeline - Tracy, CA (55 miles of San Francisco, CA), unknown amount of crude oil spill Katchmar, Peter (PHMSA) [Peter.Katchmar@dot.gov] Sent: Wednesday, December 21, 2016 8:37 AM To: MacDonald, Thank you, Peter Katchmar Western Region, PHMSA Accident Coordinator From: Katchmar, Peter (PHMSA) Sent: Friday, May 20, 2016 4:33 AM To: State-CSFM?Bob Gorham State?CSFM-Doug Allen State-CSFM-Linda Zigler Cc: PHMSA PHPSOO Response Subject: FW: Pipeline - Tracy, CA (55 miles of San Francisco, CA), unknown amount of crude oil spill Please provide a report on this event when possible. Thank you, Peter J. Katehmar Sent with Good From: CIVIC-01 (OST) Sent: Friday, May 20, 2016 4:11:52 AM To: PHMSA PHP8O Response; PHMSA PHPSOO Response Subject: Pipeline - Tracy, CA (55 miles of San Francisco, CA), unknown amount of crude oil spill This report is forwarded for your situational awareness. CMC 6-1863 NATIONAL RESPONSE CENTER 1-800-424?8802 USE USE 12/21/2016 FW: Pipeline Tracy, CA (55 miles of San Francisco, CA), unknown Information released to a third party shall comply with any applicable federal and/or state Freedom of Information and Privacy Laws Incident Report 1 148267 INCIDENT DESCRIPTION THIS IS A POTENTIAL RELEASE *Report taken by: CIV ANTONAY GREER at 05 :44 on 20-MAY-16 Incident Type: PIPELINE Incident Cause: UNKNOWN Affected Area: UNKNOWN Incident occurred on 1 6 at 02:05 local incident time. Affected Medium: UNKNOWN POTENTIAL REPORTING PARTY Name: ROBERT MARSHALL Organization: SHELL PIPELINE Address: 1801 PETROL RD BAKERSFIELD, CA 93308 - PRIMARY Phone: (661)9795275 Type of Organization: PRIVATE ENTERPRISE SUSPECTED RESPONSIBLE PARTY Name: Organization: SHELL PIPELINE Address: 1801 PETROL RD BAKERSFIELD, CA 93308 PRIMARY Phone: (661)9795275 INCIDENT LOCATION County: ALAMEDA City: TRACY State: CA BETWEEN ALAMEDA AND SAN JUAQIN COUNTIES POSITION OR LEGALS PROVIDED POTENTIALLY RELEASED CHRIS Code: OIL Official Material Name: OIL: CRUDE Also Known As: Qty Released: 0 UNKNOWN AMOUNT Qty in Water: 0 UNKNOWN AMOUNT DESCRIPTION OF INCIDENT THE SCADA SYSTEM NOTICED A COMPLETE LOSS OF PRESSURE ON A 24? PIPELINE. THE LINE WAS SHUT-DOWN AND COULD HAVE POT ENTIALLY PETROLEUM CRUDE. SENSITIVE INFORMATION ://mail. ces.ca. .. Page 2 of 5 12/21/2016 PW: Pipeline Tracy, CA (55 miles of San Francisco, CA), unknown Page 3 of 5 INCIDENT DETAILS Pipeline Type: FLOW DOT Regulated: YES Pipeline Above/Below Ground: BELOW Exposed or Under Water: NO Pipeline Covered: UNKNOWN INF ORMATI Body of Water: UNKNOWN Tributary of: Nearest River Mile Marker: Water Supply Contaminated: UNKNOWN IMPACT Fire Involved: NO Fire Extinguished: UNKNOWN INJURIES: NO Hospitalized: Empl/Crew: Passenger: Empl/Crew: Passenger: Occupant: EVACUATIONSNO Who Evacuated: Radius/Area: Damages: NO Hours Direction of Closure Type Description of Closure - Closed Closure Air: Maj or Road: Artery Waterway: Track: Environmental Impact: UNKNOWN Media Interest: UNKNOWN Community Impact due to Material: REMEDIAL ACTIONS CREWS ENROUTE FOR ASSESSMENT, NOTIFIED LINE IS DOWN, VALVES ARE CLOSED. Release Secured: UNKNOWN Release Rate: Estimated Release Duration: WEATHER Weather: UNKNOWN, 0F ://mail.ces. ca. 12/21/2016 PW: Pipeline - Tracy, CA (55 miles of San Francisco, CA), unknown Page 4 of 5 . ADDITIONAL AGENCIES NOTIFIED Federal: State/Local: CA-OES State/Local On Scene: State Agency Number: 16-2999 NOTIFICATIONS BY NRC CA U.S. ATTORNEYS OFFICE NORTH (MAIN OFFICE) 05:56 (415)4367077 CA DEPT OF FISH AND GAME (OFFICE OF SPILL PREVENTION AND RESPONSE) 20-MAY-16 05:56 (916) CENTERS FOR DISEASE CONTROL (GRASP) 20-MAY-16 05:56 (770)4887100 CONTRA COSTA OFC OF SHERIFF (HOMELAND SECURITY UNIT) 20 MAY 16 05: 56 (925)3139612 DHS PROTECTIVE SECURITY ADVISOR (PSA DESK) 20 MAY 16 05: 56 (703)2355724 DOT CRISIS MANAGEMENT CENTER (MAIN OFFICE) 05:56 (202)3661863 US. EPA IX (MAIN OFFICE) (415)2279500 FEMA REGION 09 (SITUATION AWARENESS UNIT) 05:56 (510)6277802 NORTHERN CA REG INTELLIGENCE CENTER (COMMAND CENTER SAN FRANCISCO) 16 05: 56 (415)5752788 NATIONAL INFRASTRUCTURE COORD CTR (MAIN OFFICE) 20 MAY 16 05: 56 (202)2829201 NOAA RPTS FOR CA (MAIN OFFICE) 05:56 (206)5264911 NATIONAL RESPONSE CENTER (AUTOMATIC REPORTS) 05:56 (202)2671136 NTSE PIPELINE (MAIN OFFICE) 20 MAY 16 05 56 (202)3146293 PIPELINE HAZMAT SAFETY ADMIN (OFFICE OF PIPELINE SAFETY 20 MAY 16 05: 56 (202)3660568 SECTOR SAN FRANCISCO (MAIN OFFICE) (415)3993547 CA STATE EMERGENCY SERVICES (MAIN OFFICE) 05:56 (916)2621621 STATE TERRORISM THREAT ASSESS CTR (COMMAND CENTER SACRAMENTO) 05:56 (916)8741100 ADDITIONAL INFORMATION END INCIDENT REPORT #1148267 Report any problems by calling 1-800-424-8802 PLEASE VISIT OUR WEB SITE AT 12/21/2016 FW: 148267: Pipeline - Tracy, CA (55 miles of San Francisco, CA), unknown Page 5 of 5 The information contained in this communication from the Department of Transportation?s Crisis Management Center (CIVIC) Watch may be sensitive or privileged and is intended for the sole use of persons or entities named. If you are not an intended recipient of this transmission, you are prohibited from disseminating, distributing, copying or using the information. If you have received this communication in error, please immediately contact the CMC Watch at (202) 366-1863 to arrange for the return of this information. 12/21/2016 -LID-LII . -, In .I .- . 0709 I II I II - 2 4.13431 ?3:1 . Ml (.IID bb - 0708 F'zrk ?a - - - DaklandGustIne to Tracy L'i?l?ldl'?- . I r1313Ll?'l?fll?l'l'fl I, .?ni - .x . J. - Fremcnl I I I I 0796 . - HH-J I - - \IrSan Butts Rd. to Gustlne -. - -.- MIN-zed PrEi .. ".IILII. - ?r-Iale'Prsl . - -Laji a. m, . - Bang- Panoche to Butts Rd. . . ?Huncure?,- ?z . . 4 . . bag-ink-J.II . I I g! 0705 his?. V..- . (.7) II Sam-as. I . I Mack to Panache . {Ina-Inn .I-JGE Bis0401 I .II . . December 14, 2016 - Salad CoaIInga Tank Farm - . Mack . . Sources: Esn?. HERE, DeLcrme. Inletmap. increment Corp? GEBCO. 3 . . - - uscs, FAD. NPS, NRCAN, ceonase. IGN. Kadasler NL. Ordnance 0704 Survey. Esd Japan. METI. Ear? China (Hong Kong}. swisstupc. 5. I OpenStreelMap contributors, and the GIS User - a SEC-I IT . A I Please be aware H?Iat BY ACCEPTING THIS FILE YOU AGREETO THE I 3 FOLLOWING: I understand that any and 5H datannfonnation cbIaI?ned l? II from the Of?ce of the State Fire Marshal's Pipa?ns Mapping System Is I -, sensitive secunYy information and I agree to: resbict disclosure of and 'l '3 access to this dafa?nfanna?an to persons with of?cial! state and face! -. government responsbe?I?r?m' to not redistribute the data/information; and I0 -. refer requests by other persons for such Information to the Mapping .. .. .. .- Coordinator for OSFM. I aiso agree to maintain a ?st of those.- persons . 34141175 If 6" unaware beenprovr'ded accessfofhfsinformalfon Fo? Hunt-er I run all . Shell Oil Spill Incident May 20, 2016 f. ff" Alamed .. 3? -. It?- CSFM LINE ID: 0708 f. COMPANY: Shell Pipeline Company LP it it li- True. ?if-f; lie. Liliqum I'Sn-eJoe Sources: Esrl, DeLorme, Intern-lap, increment Caro. GEBCO, USGS, FAD, NPS, NRCAN, GeoBese, IGN. Kadaster NL, Ordnance Survey, Esrl Japan, METI, Esrt China {Hong Kong), swisstopo, OpenStreetMap contributors. and the GIS User May 31, 2016 ,3 Spill Location CSFM Pipeline 0708 County Line 0.3 0.6 mi 0 0.15 I I I Please be aware that BY ACCEPTING THIS FILE YOU AGREE TO THE FOLLOWING: understand that any end all detennt?ormetion obtained from the Of?ce of the State Fire Marshal's Pipeline Mapping System is sensitive secun?ty lnl'om'latton and i agree to: restrict disciosure of and access to this data-information to persons with ottior'at state and toast government to not redistribute the dete?ntormetton; and to refer requests by other persons for such Information to the Mapping Coordinator for OSFM. i also agree to maintain a list of those persons that have been provided access to this information. Pipeline Failure Investigation Report Pipeline System: SJV North Heavy Crude Oil System Operator: Shell Pipeline Company LP Operator ID: 31 174 Unit Number: 0560A Activity Number: 20160520TMW1 Location: Date of Occurrence: May 20, 2016 Material Released: Crude oil Quantity: 500 barrels PHMSA Arrival Time Date: 1 May 20, 2016 Total Damages S: $4,540,000 Investigation Responsibility: State PHMSA NTSB __Other Cause: Sub-Cause PHMSA Form 7000-1/71 Corrosion Natural Force Excavation Other Outside Force Material Failure Joint, We Pipe Fatigue crack Equipment Failure incorrect ion Other Accident/Incident Resaited in (check all that qupbv): Comm: Rupture Leak ire Explosion Evacuation Number of Persons: Area: Narrative Sammy Short summary oi?thc Incident/Accident scenario At 0035 hours (PST) May 20, 2016, Shell Pipeline Company?s Control Center in Houston, TX detected a drop in operating pressure on the North San Joaquin Valley 24? Tracy to Avon crude oil pipeline (CSFM #0708). The Tracy pumps station immediately shut down on low suction pressure and the control center immediately shut down the entire pipeline system and immediately isolated the leaking section of pipe by closing the main line block valves. The failure occurred in an open ?eld approximately of a mile of the Tracy pump station. No waterways were impacted, no ?re, injuries or death occurred. A 79.8? section of pipe containing the seam failure was cut out and replaced. Metallurgical examination of the failed pipe was conducted by Det Norske Veritas of Dublin, Ohio. After repairs were made, the entire line was hydrostatically tested and the line resumed operation on July 19, 2016 Region/State: Western - California Reviewed by: 6/11/11, Principal Investigator: Thomas M. Williams 1V Title: 5&9? Date: .5174! Date: Kile )70/7 I I Page 1 of 14 Pipeline Failure Investigation Report .. 63mm (City, Township, Range, . . County/Parish): (Acquire Map) Outside of Tracy, Alameda County, California Address or MP. on Pipeline: ?3 Type of Area (Rural, City): iliP 13 6. 7 Rural Coordinates of failure location (Latitude): - (Longitude): - Date: May 20, 2016 Time of Failure: 0035 PST Time Detected: 0035 PST Time Located: 6217 PST How Located: Ground Patrol . . Reported by: Bob Marshall, NRC Report 114826 7 Time Reported to NRC. 0244 PST 5/20/16 Si: Pipe I ine Company Type of Pipeline: Gas Distribution Gas Transmission Hazardous Liquid LNG LP - Interstate Gas Interstate Liquid Municipai Intrastate Gas intrastate Liquid Public Utility Gas Gathering O?shore Liquid Master Meter Offshore Gas Liquid Gathering Offshore Gas - High H23 Low Stress Liquid HVL Pipeline Con?guration (Regulator Station, Pump Station, Pipeline, etc.): 24 Pipeline from Tracy Station to Windmil! (mm CSFM ID 0798 if}, i (do (-331.15? Shell Pipeline Compan Address: 910 Louisiana Street Houston, Texas 77002 Company Of?cial: Greg Smith, President Company l' Gm Smith, President Phone No.: ax No.: MA Phone No. Fax No. MA . Owner: San Pablo Boy Address: 9M Louisiana Street Houston, ?mu 7 7002 Drug and Alcohol Testing Program Contacts Drug Program Contact Phone: Michael Courville, Operations Support Specialist, 713~241?0740 Alcohol Program Contact 8: Phone: Michael Com-ville, Operations Support Speciaiist, 713-241-0740 1 Photo documentation Page 2 of 14 Pipeline Failure investigation Report Product/Gas Loss or Spill (2) Estimated Property Damage 3 500 barrels $25,000 Amount Recovered 400 Associated Damages (3) barrels $2,030,000 Description of Property Damage: $20,000 in property damage; $1,330,000 in Operators?propeny damage and repairs; $1,585,000 in operatois? emeigeacy reaponse; $i,600,000 in eaviroamentei remediation. Customers out of Service: Yes No Number: Suppliers out ofService: . Yes No Number: Fatalities: Yes No Company: Contractor: Public: Injuries - Hospitalization: Yes No Company: Contractor: Public: Injuries - Non-Hospitalization: Yes No Company: ContractOr: Public: Total Injuries (including Non?Hospitalization): Company: Contractor: Public: I I Yrs. w/ Yrs. Name . Job Function Comp- EXP- lype of Injury Were all employees that Could haVe contributed to the incident, post?accident tested Within the 2~hour time frame for alcohol or the 32?hour time ?ame for all other drugs? Yes No Results Job Function Test Date Time - Location Type of Drug Pos Neg bescribe site bpei'aior?s siege: San Pablo Bey 9? North '20, Coaltnga-ioyivon 20/24-inciz I Transports Crude eiifrom the San Joaquin Vaiiey Gratis axing to re?neries in tile Martinez Bay Area, Length of Failure (inches, feet, miles): Rapture, Fish Month, 45 imitate by 45.2 inches . . . . . . Position (Top, Bottom, include position on pipe, 6 O'clock): (13? I Description of Failure (Corrosion Gouge, Seam Split): (1) 2 initial volume lost or spilled 3 Including cleanup cost Page 3 of14 Pipeline Failure Investigation Report 3 . tartar" Laboratory Analysis: I Yes __No (not yet completed). Performed by: Bret Norsice Veriias (U. A .), inc. P1 eservatlon of Failed Section or Component: Yes Wrapped in piasiic and er aiedfor If Yes Method: shipment to Bet Nerske Veriios Irie ,Dobiin, Ohio In Custody of: Der Nersire Veriias (U. S: A J, Inc. Develop a sketch of the area including distances from roads houses stress inducing factors pipe con?gurations direction of ?ow, etc. Bar Hole Test Survey Plot if included should be outlined with concentl ations at test points Component Failed; Manufacturer: Pressure Rating: Other reakout Und and Material: Carbon Sieei I Wall Thickness/SDR: 0,26 Diameter 24. Installation Date: 1989 SMYS: 6 0 Manufacturer: Arman Longitudinal Seam: BSA Type of Coating: Swiayer .Poiyo Pipe Speci?cations (API 5L, ASTM A53, etc.) 51. Premature: Type .. . . . . NDT Method: - I Inspected: I_#Yes No Pressure Failure Site: 694psi Elevation Failure Site: Pressure Readings VariOus- Locations: Direction from Failure Site Location/M.P./ Station ii Pressure ?(psig) Elevation. (it msl) Upstream Tracy Kick off discharge 694 psig 5 88 fr. I Marsh Creek section 365 psig 4.22}? Type of Producti Crude API Gravity: 15.2 Speci?c Gravity: Flow Rate: 6,126 B.Pii. Pressure Time of Failure (4) 6941M Distance to Failure Site: 1 risiie High Pressure Set Point: 95 7 psi . Low Pressure Set Point: 25' psi 4 Obtain event logs and pressure recording charts Page 4 of' 1.4 Pipeline Failure Investigation Report Speci?c GravityIIFIOWII Rate: Pres-sure Time of Failure (4) I Distance to Failale Site: HighIPressure Set Point: I I I Low Pressure Set Point: Max. Allowable Operating Pressure: 9 36 mg I II Determination of MAOP: Pipe pressure and 80% of - - - hydrates! Actual Operating Pressure: 694ps1? Method of I Over Pressure Protection: relief valve . Relief Valve sesame arrest Capacity Adequate? Yes No Pressure test conducted in place? (Conducted on Failed Components or Associated Piping): Yes If No, tested after removal? Yes No Method: 8 mhonr Hydrotest and a 10-- minute Spike Hydrotest Describe any failures during the test. None Condition of andIszpe of 8011 around Fallure Site (Color, Wet;I Dry, Frost Depth): $011 conditions ?Dry, Pasture W?h Vegetation. Type of Back?li (Size and Description): local backfilifmnr inndownefpmperngw . Type of Watel (Salt, Brackish) No Water 111 area Water Analysisw Yes XNO External Corrosion? mYes No Coating Condition (Disbended, Non-existent): (1) Description of Corrosion: Description ofIFaiiure Surface I(Gouges, Arc Burns,IWrinkle Bends, Cracks, Stress Cracks, Chevrons, Fracture Mode, Point of OriginAbove Ground: Yes I No I Buried: Yes II No I (1) Stress Inducing Factors: I (1) Depth of 01115er .- . . . (1) P/SIIiSurface): I II II (Interface): Soil Resistivitjz: pH: Date of installation: Method of PrdteCtionII: I II I Did the Operator have knowledge of Ceirosion before the Incident? Yes No How Discovered? (Close Interval Instrumented Pig, Annual Survey, Recti?ei Readings ECDA, etc): Internal Corros1on: Yes (1) Injected Inhibitors: __Yes No Type of Inhibitors: I I Testing: Yes No I 5 Attach copy of water analysis report Page 5 of 1:4 Pipeline Failure Investigation Report Results (Coupon Test, Corrosion Resistance Probe)" Description of Failure Surface (MIC, Fitting, Wall Thinning, Chevrons, Fracture Mode, Point of Origin): Cleaning Pig Program: _I_Yes I No Gas and/ or Liquid Analysis: Yes No Results of Gas and/or Liquid Analysis (6) I I Internal Inspection Survey: Yes No Results (7) Did the Operator have knowledge'of Corrosion before the Incident? Yes I No How Discovered? Pig, Coupon Testing, ICDA, etc.): Responsible my; . Telephone No: Address: Work Being Performed: Equipment Involved: - (1) I Called One Call System? Yes No One Call Name: One Call Report Notice Date: II Time: Response Date: Time: Details of- Response: . Was Location Marked Accelding to Procedures? Yes No Pipeline Marking Type: (1) Location: (1) State Law Damage Prevention Program Followed? I Yes No mNo State Law Notice. Required: #No. I Response Required? Yes No Was Operator Meinber of State One Call? Yes No Was Operator on Site? Yes I No- Did a de?ciency in the Public Awareness Program contribute to the accident? I No Is OSHA Noti?cation Required? Yes No I Squeeze Off/Stopple Location and Method: Valve Closed Upstream I i 1.135.: Tracy Station .6 Attach copy of gas and/or liquid analysis report 7 Attach copy of internal inspection survey report 8 Attach copy of one?call report Page 6 of 14 Pipeline Failure Investigation Report Time: adsdlirs. Paci?c ?me Valve Closed I.D.: Marsh Creek Time: 023811rs. Paci?c Time MP: 156 Pipeline Shutdown Method: Manual Automatic SCADA Controller ESD Failed Section Bypassed or Isolated: Irritated Performed By: Derek Ferraro Valve Spacing: 20 trailer Gas 'Cdorized: wiles No Concentration of Odorant (Post Incident at Failure Site): Method of Determination: Yes No LEL: Yes I No Gas In Air: Yes No Time Taken: Yes No I Was Odorizer working Prior to the Incident? I Type of Odorizer (Wick, By?Pass): Yes No Odorant Manufacturer: Type of Odorant: Model: Amount Injected: Monitoring Interval (Weekly): Odorization History (Leaks Complaints, Low Odorant Levels, Monitoring Lecations, Distances?om Failure Site): Temperature: 55 Wind (Direction Speed) ?ls Climate (Snow, Rain): Weather: Clear, Visibility: 10 Miles. Humidity: 62% Barometer: 29. 71"Hg, Was Incident preceded by a rapid weather change? Yes Wind 13 mph, Barometer Visibility Miles. Weather Conditions Prior to Incident (Cloud Cover, Ceiling Heights, Snow, Rain, Fog): Temp - 8i} ?Fl57 Weather Clear, Equipment Used: by the medium loss): No impacted Water or wi1d1?fe Location (Nearest Rivers, Body of Water, Marshlands, Wildlife Refuge, City Witter Supplies that could be or were affected (1) I OPA Contingency Plan Available? Yes No I Followed? Yes ?No Class Location: 2 3 4 Determination: PICA Area? Yes Ne Determination: Drinking Water Ecological 9 Plot on site description page . Page 7 of14 Pipeline Failure anestigation Report Odorization Required? Yes No Pressure Duration (10) Reg Assessment Test Date Test Medium Deadline Date (psig) (hrs) Installation I 11/20/1000 11/0101 1200 0 I 023% Next I I I I I Next . Most Recent Describe any problems experienced (1111' mg the pressure tests. None Req?d Assessment Assessment Type of 1L1 Other Assessment indicated Anomahi I Deadline Date Date Tool (11) Method If yes, describe below 11111101 I 0/3/2000 111 Yes No I Next I 0/3/2007 0/1/2007 . 111 I . X1105 No 010 I 0/1/2000 I 0/7/2009 MFL 111 I IX Yes Na Next I 0/7/2011 0/20/2011 I I I 1131 . __Yes Next I 4/20/2010 0/27/2013 MFLI 111 I I ?Yes II Next I 0/27/2010 I 0/0/2015 II I 11.1 I I __Yes Nee I I 12/0/2010 II MFDC . 1L1 ?No 010001100001 I I I 12/4/2015 U110 11.1 I was wNe I 11/11 10/0 Describe any previously indicated anomalies at the failed pipe, and any subsequent pipe inspections (anomaly digs) and remedial actions. 3 preventative digs 5/7/2009 21113001131120 digs performed, 12/2015 - 2 digs performed. Was there a known condition requiring (10) the operator to schedule evaluation and lemediation? Yes (describe below or on attachment) No If there was such a knewn pie- -failure condition, had the operator established and adhered to a required evaluation and remediation schedule? Deseribe below or on attachment Yes _No Prior to the failure, had the operator performed the required actions to address the threats that are now known to be related to the cause ofthis failure? Yes No List below or on an attachment such Operatolsidenti?ed threats, and operator actions taken prior to the accident Describe any previously indicated anomalies at the failed pipe, and any subsequent pipe inspections (anomaly digs) and remedial actions. 10 As required of Pipeline Integrity Management regulations in 49CFR Parts 192 and 195 ll MFL, TF1, UT, Combination, Geometry, etc. 12 ECDA, ICDA, SCCDA, ?other technology,? etc. Page 8 of14 Pipeline Failure Investigation Report Are Maps and Records Current? (13) Yes No Comments: Leak Survey History (Trend Analysis, Leak Plots): Description (Repair or Leak Reports, Exposed Pipe Reports): Did a Safety Related Condition Exist Prior to Failure? Yes Reported? Yes Unaccounted For Gas: Over Short/Line Balance (24 1111., Name: Job Function: Title: - Years of Experience: Tlaining (Type of Training, Background): Was the person ?Operator Qualified? as applicable to a precursor abnormal operating condition? _'Yes No Was quali?ed individual suspended from pe1 formmg covered Yes Ne Type of En or (Inadvertent Operation of a Valve): Procedures that are required: Actions that weie taken: Pie?Job Meeting (Construction, Maintenance, Blow Down, Purging, Isolation} PreVention of Accidental Ignition (Tag Look Out, Hot Weld Permit): Procedures conducted for Accidental Ignition: Was a Company Inspector on the Job? Yes I No 'Was an Inspection conducted on this portion of the job7m Yes No Additional Actions (Contributing factors may include number of hours at'work prior to failure or time of day work being conducted): Training Precedin'es: Operation Procedures: Controller Activities: Name Title . Yet? 0? [duty Shin Experience Prior to Fa1lu1'e 13 Obtain copies of maps and records Page 9 of 14 Pipeline Failure Investigation Report u- - Aiarm Parameters: High/Low Pressure Shutdown: Flow Rate: Procedures for Clearing'Alarms: Type of Alarm: Company Response Procedures for Abnormal Operations: Over/ Short Line Balance Procedures: Frequency of Over/Short Line BalaHCe: Additional Actions: Make notes regarding the emergency and Failure Investigation Procedures (Pressure reduction, Reinforced Squeeze Off Clean Up, Use of Evacuators Line Purging, closing Additional Valves, Double Block and Bleed Continue Operating Demetreain Pumps): Line was shat dawn. Uader redaeed operating pressure the was started up to push the heavy crude eat attire with a tighter trade oil to aa extended shutdown. Crack teal iogs were reevaiaated by the vendor and additional repair and investigation digs were caadaeted 0a the titree segments of the bigger system that ceataia the same time of pipe. Pressure tests wide a spike test were eeadaeted an all three segmeats of tire iiae. Overall Area from best possible View. Pictures done the four points of the compass. Failed Component Operator Action Damages 111 Area, Address Markings, etc. I Photo . Photo NO- Description N0. . Description . '2Page 10 of14 Pipeline Failure Investigation Report Camera Type: Agency Phone Number Police: Fire Dept: State Fire Marshal: State Agency: NTSB: EPA: USCG: FBI: ATF: OSHA: Insurance (30.: FRA: MS: 'l?ele-vision: Newspaper: Other: Name Title Phone Number Emergency Response/Public Awareness Robert C. Marshall Michael Bringham Facilities Manager, SJV Crude Gary McNatt SJV Operations Supervisor Dave Harder SJV Maintenance Supervisor Alan Elliott Western Region Asset Integrity Bryce Brown Rosen Global Strategy Management Page 11 of 14 Form ~11 Pipeline Failure Investigation Report (Rev. 03/17/2011 through Amdt. 192-116 195-95). Pipeline Failure Investigation Report Sequence of events prior, during, and after the incident by time. (Consider the events of all parties involved in the incident, Fire ent and Police rts, and other overnment agencies.) Time Date Event Page 12 of 14 Pipeline Failure Investigation Report Description . Operator: Unit . Date: Appendix . Date 01A Documentation Desemp?on Number Received Yes No Page 13 of 14 Pipeline Failure Investigation Report Provide a sketch of the area including distances ?rom roads, houses, stress inducing factors, pipe con?gurations, etc. Bar Hole Test Survey Plot should be outlined with concentrations at test points. Photos should be taken from all angles with each photo documented. Additional areas may be needed in any area of this guideline. Page 14 ef14 penalty shall not exceed 51.000.000 as provided in 49 USC 6012. NOTICE: This report is required by 49 CFR Part 195. Falure to report can result in a civil penalty not to exceed $100,000 for each violation tor each day that such violation persists except that the maximum civil OMB NO: 2137-0047 EXPIRATION DATE: 12131l2016 Original Report 0? Date, 06/15l2016 US Department of Transportation . 20160184 - 21575 Pipeline and Hazardous Matenals Safety Administration (001 ACCIDENT REPORT - HAZARDOUS LIQUID PIPELINE SYSTEMS INSTRUCTIONS A 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 with a collection of information subject to the requirements oi the Paperwork Reduction Act unless that collection of inlonnation displays a current valid OMB Control Number. The OMB Control Nimber for this information collection is 2137-0047. All responses to the collection of information are mandatory. Send comments regarding this burden or any other aspect of this collection of information, including suggestions tor reducing the burden to: Information Collection Clearance Of?cer. PHMSA. Of?ce of Pipeline Salety 1200 New Jersey Avenue. SE. Washington. DC. 20590. ran-7km. h. Important: Please read the separate instructions for completing this lonn before you begin. They clarify the information requested and provide speci?c examples. It you do not have a copy of the you can obtain one from the PHMSA Pipeline Safety Community Web Page at PART A - KEY REPORT INFORMATION . (Moat Supplemental: Final: Report Type. (select all that apply) Yes Yes Last Revision Date: 08/05/2016 1. Operator's OPS-Issued Operator Identi?cation Number (OPID): 31174 2. Nmof Operator SHELL PIPELINE L.P. 3. Address of Operator: 3a. Street Address 910 LOUISIANA STREET 42ND FLOOR 3b. City HOUSTON SC. State Texas 3d. Zip Code 77002 4. Local time (24-hr clock) and date of the Accident: 05l20l2016 00:35 5. Location of Accident: Latitude: Longitude: 6. National Response Center Report Number (if applicable): 1148267 7. Local time {24-hr clock) and date of initial telephonic report to the National Response Center (if applicable): 05/20/2016 02'? 8. Commodity released: (select only one, based on predominant Crude Oil volume released) - Specify Commodity Subtype: - If "Other" Subtype, Describe: - lt Fuel and Commodity Subtype is Ethanol Blend. then Ethanol Blend: - If BlofuellAltemative Fuel and Commodity Subtype is Biodiesel. then Biodlesel Blend e.g. 32. 820. B100 9. Estimated volume of commodity released unintentionally (Barrels): 500.00 10. Estimated volume of intentional and/or controlled release/blowdown (Barrels): 11. Estimated volume of commodity recovered (Barrels): 400.00 12. Were there fatalities? No - If Yes, specify the number in each category: 128. Operator employees 12b. Contractor employees working for the Operator 12c. Non-Operator emergency responders 12d. Workers working on the right-of-way, but NOT associated with this Operator 12e. General public 12f. Total fatalities (sum of above) 13. Were there iry?uries requiring Inpatient hospitalization? No - if Yes, specify the number in each mtegory: 13a. Operator employees 13b. Contractor employees working for the Operator 13c Non-Operator emergency responders 13d. Workers working on the right-of-way, but NOT associated with this Operator 139. General public Form PHMSA 7000.1 13f. Total injuries {sum of above) 14. Was the shut down due to the Accident? Yes If No. Explain: - if Yes, complete Questions 14a and 14b: (use local time. 24hr clear) 14a. Local tlme and date of shutdown: osrzcoms 00:37 14b. Local time pipelinelfacitity restarted: 052232016 13:00 Still shutdown? Supplemental Report Required) 15. Did the commodity ignite? No '16. Did the commodity explode? No 17. Number of general public evacuated: 0 18. Time sequence (use local time, 24-hour clock): I 18a. Localtlme Operator Identi?ed Accident- effective 7-2014 . changed to "Loos! time Operator identi?ed failure": 0512019016 00'35 1813. Local time Operator resources arrived on site: . 05i20l2016 92:17 PART - LOCATEQN 1. Was the origin of the Accident onshore? - Yes if Yes. Complete Questions (2-12) it No', Complete Questions (13?15) if Qnshore: - 2. State: California -, 3. Zip Code: 95304 4. City Tracy 5. County or Parish Alameda 6. Operator-designated location: MiteposWelve Stattoo Specify: 1313 7. PipelinelFacility name: North20 8. Segment nemefiD; Tracy to Windmill Farms 24"_ 9. Was Accident on Federal land, other than the Outer Continental Shelf {088}? N0 '10. Location of Accident; Pipeline RIght?of?wey 11. Area of Accident (as found): Underground Specify: Under soil - if other. Deco ibe: De pth-of-Cover 84 '12. Did Accideotoccur in a crossing? No if Yes, specify type below: - If Bridge crossing Cased! Unoased: If Railroad crossing Casedi Uncaeedf lf Road crossing-m Casedl Uncasedl Boredldriiled - If Water crossing Casedl Uncased - Name of body of water, if commonly known: Approx. water depth (ft) at the point of the Accident: - Se ect: - thOffs here: 13. Approximate water depth (ft) at the point of the Accident: ?14. Origin of Accident: in State waters Speoity: - State: Area: Biockl'i'ract ff: - Nearest - on the Outer Continental Shelf (ODS) Specify: - Areal: - Block 15. Area of Accident: PART cu- AeetTIoNaL FACHLETY ENFORMATEDM 1. Its the pipeline or facility: intrastate 2. Part of system involved in Accident: Onshore Pipeline, including Valve Sites I - If Onshore Breakout Tank or Storage Vesset. including Attach Appurtenanoes. specify: ed I 3. Item involved in Accident: Pipe - If Pipe, specify: Pipe Body 33. Nominal diameter of pipe 24 Form PHMSA 7000.1 3b. 3c. SMYS 3d. -3e. Seam . If Other 3f. . . Year of manufacture: 3h. at of . it Other Describe: - it Weld, including heat-affected zone. specify. if Pipe Girth Weld, 3a 3h above are uired: - If if . it'Mainiine Other Describe: 3t. Year of . If Tanth - .. it Other - Desaribe: - if describe: . Year involved in 5. - it other than 6. of if Mechanical Puncture - in. If Leak - Select if Describe: - if Select if - size: in. widest 4.5 in. or 45.2 - it Other Describe: PART ADDITIONAL CONSEQEJENCE INFORMATIQM Wildlife - - ?Ia. eli that - Fishlaquatic - Birds Terrestrial 2. Soil 3. easessment 4. Antici it - Surface - Soil - tation all that Surface - Groundwater - . Safest one or both - Private Well - intake Estimated in or 5c. Name of of water it known: 6. At the location of this Accident. had the pipeline segment or tactitty been identi?ed as one that "could affect" a High Consequence Area Yes as in '3 T. the released commodity reach or occur in one or more High Area 8. if at! that Yes Was this HCA identi?ed in the "could affec for site in the Form PHMSA 7000.1 integrity Management Program?,_ - High Population Area: Was this HCA identi?ed in the "could affec determination for this Accident site in the Operator's Integrity Management Program? - Other Populated Area I Was this HCA identi?ed In the "could affect" determination for this Accident site In the Operator's Integrity Management Program? - Unusually Sensitive Area Drinking water . Yes Was this HCA identi?ed' In the "could affect" determination for this Accident site in the Operator?s Integrity Yes Management Program? unusually sensitive Area Ecclogicai Yes Was this l-lCA Identlt? ed In the "could affec determine ion for this Accident site in the Operator?s Integrity Yes Management Program? 8. Estimated cost to Operator~ effective ?12- 2012 changed to ?Estimated Property Damage": 8a. Estimated cost of public and non?Operator private property damage paidrreimbursed by the Operator effective 12- 2012 25,000 "paidfreimbursed bythe Operator" removed .- 8b. Estimated cost of commodity lost i 5 0 '8c. Estimated cost of Operator's property damage_& repairs 1,330,000 8d. Estimated cost of "Operators emergency response in 1,585,000 8a. Estimated cost of Operators environmental remediation ii 1,600,000 8f Estimated other costs ES 0 Describe: 8g. Estimated total costs {sum of above) effective 12?2012, 4 540 000 changed to ?Total estimated property damage (sum of above)" PART - GPERATWG 1N FQRMATIQN 1. Estimated at the point and time of the Accident (pslg): 694.00 2. Maximum Operating Pressure (MOP) at the point and time of the 036 OD Accident (psig): 3. Describe the pressure on the system or feeliity'reiating to the Accident (psig): Pressure did not exceed MOP 4. Not including pressure reductions required by PHMSA regulations (such as for repairs and pipe movement) was the system or facility relating to the Accident operating under an established pressure - No restriction with pressure limits below those normally allowed by the it Yes, Complete 4 a and 4. below: 4a. Did the pressure exceed this established pressure restriction? . 4b Was this pressure restriction mandated by or the . State? 5. Was ?Onshore Pipeline moulding Valve Sites" 0R "Offshore Pipeline, including iRiser and Riser Bend" selected in PART Quest (Complete 5a. - ?fbeiow) effective 12?2012, changed to Complete 5a 5.e below)" 5a. Type of upstream valve used to initially isolate release Remotely Controlled source: . . 50. Type of valve used to initially isolate relea-?se source: . . . . . Remotely Controlled 5c. Length of segment isolated betwaen values 16,125 501. lathe pipeline con?gured to accommodate internal Yes inspection tools? it no, Which physical features llr'nit tool accommoda ion? select all that apply) . Changes in line pipe diameter - Presence of unsuitable mainline valves Tidht or tattered pipe bends - Other passage restrictions (is. unbarred trio's, projecting instrumentation, etc Extra thick pipe wall (applicable only for magnetic flux leakage internal inspection tools) Other - .-. Ir Other .. 5e. For this pipeline are there operational factors which i signi?cantly complicate the execution of an internal inspection-t - at run? N0 it Yes, Which operational factors complicate execution? (select all mat apply} Form PHMSA 7000.1 ?ma? - Excessive debris or Scale,t wax, or other well buildup Low operating pressurels} - Low flow or absence of flow ~inoornpatibie commodity - Other- it Other, Describe: 5f. Function of pipeline system: 20% SMYS Regulated Trunklineffransmis'sion 6. Was a' Supervisory Control and Data Acquisition -based system In place on the pipeline or facility involved' In the Accident-operating at the time otthc Accident? Yes- Bb. Was it fully functional at the time Of the Accident? Yes 6c. Did SCADA?basted informatiOn (such as alarrn(s). alert(s), event(s), andlor volume calculations) assist with Yes the detection of the Accident? 6d. Did SCADA?based information (such as alarm(s). alertEs), event(s). andlor volume calculations) assist with No the con?rmation of the Accident? Was a 0PM leak detection system in place on the pipeline or facility Yes involved in the Accident? - If Yes: 78. Was it operating at the time of the Accident? Yes 7b. Was it fully functional at the time of the Accident? ?es 7c. Did 0PM leak detection system information (such as alarm(s). alert(s). event(s}, )andlor volume calculations) assist Yes with the detection of the Accident? . 7d. Did 0PM leak detection system information (such as -,alarm(s) alert(s} event(s} anler volume calculations) assist No with the con?rmation of the Accident? 8. How was the Accident initially identi?ed for the Operator? - 0PM leak detection system or SCADA-based information . (such as alarm(s), alert(s), event(s), andior volume calculations) ItOther. Specify: Be. it "Controller", ?Local Operating Personnel", including contractors? "Air Patrol" or "Ground Patrol by Operator or ils contractor" I5 selected in Question 8 specify: 9. Was an investigation initiated into whether or not the controller(s or control room issues were the cause of or a contributing factor to the Accident? Yes, specify investigation result(s): (select all that apply) ?If No- the Operator did not ?nd that an investigation of the controller(s) actions or control room issues was necessary due to: explanation for why the operator did not investigate) If Yes. specify investigation (select at! that apply) investigation reviewed work schedule rotations, continuous hours of service (while working for the Operator}, and other factors associated with fatigue a investigation did NOT review work schedule rotations, continuous hours of service (while working for the Operator), endother factors associated with fatigue Yes Provide an explanation for why not: The Controllers response was compliant and effective. The size and consequence otthe release was minimized as required by procedure. Notification "to ?eld personnel was compliant to noti?cation to the Console Supervisor. There Were no issues. to note in regards to Control Center response. There were no fatigue related issues. No drug testing was required. Investigation identi?ed no control room issues Yes lnvestigation identi?ed no Controller issues Yes - investigation identi?ed incorrect controller action or' Controller error ?lhvesttgation identi?ed that fatigue may have affected. the controlleds) involved or impacted the involved controllerts] response investigation identi?ed incorrect procedures ?lnvestig_ation identi?ed incorrect control room equipment operation -lnvestigation identi?ed maintenance activities that affected control room operations procedures andlor controller responsa Investigation identified areas otherthan those above: Describe: Form PHMSA "(000.1 PART - issue a smaller. ?rashes InsoaMArIoN 1. Asa result of this Accident, were any Operator employees tested under the post-accident drug and alcohol testing requirements of 901" Drug Alcohol Testing regulations? a} No - it Yes: 'ia Specify how many were tested: 1b Specify how many failed: 2. As a result of this Accident were any Operator contractor employees tested under the post-accident drug and alcohol testing requirements or DOT's Drug Alcohol Testing regulations? No - If Yes: 2a. Specify how many were tested: 2b. Specify how sear Assassfm cease select ohiy one box from PART in shaded column on left representing the APPARENT Cease of the Achde?f, and answer the questions on the rightg?esorihe secondary, contributing or root cair'ses ofthe Accident in the narrative H) Apparent Cause: es Materlai Failure of Pipe or Weld {3?31 .. CorroSion Failure - only one sub-canes canine picked from shadedleft?hand column Corrosion Failure Stab-Eatise: if External Corrosion: Results of visual examination: If Other: Describe: 2. Type of corrosion: (select alt that apply} 5 - Galvanic - Atmospheric - Stray Current - Selective Seam . Other; ?if Other Describe: 3. The typeis} of corrosion selected In Question 2 Is based on the fol owing (seiectali . Field examination - Determined by metallurgical analysis Other: if Other, Describe: Was the failed item bolted under the ground? -lers: 1343. Was tailed item considered to be under cathodic protection at the time of the Accident? it Yes Year prote?tiori started: 4b. Was shielding, tenting, or dishonding of coating evident at the point of the Accident? 4c. Has one or more Cathodic Protection Survey been conducted at the point of the Accident? it"?fes. Annuai Survey" Most recent year conducted: if "Yes, Close'lntervai Survey" Most resent year conducted: if "Yes, Other GP Survey" Most recent year conducted: I ?ItNo:" 4d. was the failed item externally coated or painted? 5. Was there observable damage to the coating or'paint in the vicinity of the corrosion? if internal Corrosion:- t3. Resuits of visual examination: - Other: 7 Type oicorrosion (seiectalithatapply): - - Corrosive Commodity - Water drop- -outiAcid - Microbioioglca]. - Erosion Other: If Other. Descr be: - 8. The causais} of corrosion selected' In Question 7' is based on the following (seiect all that apply}: . FlGid examlnetlon Form PHMSA 7000.1 Detennined by Metallurgical analysis - Other: - If Other, Describe: 9. Location of corrosion (select all that apply): Low point in pipe - Elbow ~Otner: - it Other. Describe: 10. Was the commodity treated with corrosion inhibitors or biocides? 11. Was the interior coated or lined with protective coating? 12. Were cleaninglciewatering pigs (or other operations} routinely utilized? 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, Question 3} is TankNessel. 14'. List the year of the most recent inspections: 14a. 653 Qui?of?Service inspection .. No Outeot?wService inspection completed 14b. 653 ln?Service inspection No Inspection completed Complete the following it'any Corrosion Failure sub?canes is selected AND the "item Involved in PART C. Question is Pipe'o'r weld. . 15. Has one or more internal inspection tool collected data at the point of the Accident? 15a. for each tool used. select type of internal inspection tool and indicate rnost recent year run: - Magnetic Flux Leakage Tool Most recent year: - 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 Fieldfi?riaxiat Most recent year: - Other Most recent year: Desoribe: 16. Has one or more 'hydrotest orother presaure test been conducted since original. construction at the point of the Accident? . if Yes Most recent year tested: Test pressure: 17. Has one or more Direct Assessment been conducted on this segment? -ii Yes and an investigative dig was conducted at the point of the Accident: Most recent year conducted: i. If Yes but the point of the Accident was not identi?ed as a dig site: Most recent year conduoted: 18. Has one or more non-destructive examination been conducted atthe point of the Accident since January 1 2002? 18a If Yes. for each examination conducted since January 1 2002, select type of non destructive examination and indiCate roost recent yearthe examination was conducted: Radiography . Most recent year conduoteti: - Guided Wave Ultrasonic Most recent year cond ucteci: Handheld Ultrasonic Tool . Most recent year conducted: Wet Magnetic Particle Test . Meat recent year conducted: .. Dry Magnetic Particie Test Most recent year conducted: - Other Most recent year conducted: Form PHMSA 7000.1 Describe: I I G2 - Natural Farce 'Damage only one e-ubwceuse can be picket from shaded left-handed coiumn' Natural Force Damsge? Sub-Cause: I .. if Earth Movement. NOT due to Heavy RainsiFloods: 1. Specify: -- if Other. Desci be: . x-if Heavy RainsiFiocds: 2. Specify: it Oihen Deco "ice: - if Lightning: 3. Specify: .. if Temperature:? 4. Specify: . i - if Other? 'Desciihef .. it Other Natural Force Damage: 5. Describe: Complete the following ifieny Natural Force Damage euhwcause-is selected. 6. Were the natural forces causing the Accident generated in conjunction with an extreme weather event? 5e. it Yes, specify: (select elf that sppiy) - Hurricane - Tropical Storm . .. Tornado Other if Other Describe: E53- Excavation Damage- only one cuh~ceuse can be picked freer shaded left-hand coiumn _-Excevation Damagem martini-Cause: if Previous Damage. clue to Excevetimi Activity: Corn'piete the ?item-'involveci in Accident" {from PART (3, Question 3} is Pipe or Weld. 1. Has one or more interns! inspection tool collected data at the point o= the Accident? 1a. it Yes, for each idol Used of interns: inspection tool and indicate most recent year run: - - Magnetic Fiux Leakage Most recent year conducted: Uitresonic most recent year conducted: Qeometry Most recent year conducted: Caliper . Most recent year conducted: Crack Meetreneni'yearconduCted: - Herd Spot Most recent year conducted: Combination Tool Most recent year conducted: - Transverse FieldiTriaxiei ?Moet recent year conducted: - Other Most recent year conducted: Describe: 2. Do youheve reeson to believe that the internal inspection was completed the damage was sustained? 3. Has one or more-hydrotest or other pressure test been conducted since original construction at the point of the Accident? 1f Yes; Most recent year tested: Test pressure (psig): 4 Has one or Inore Direct Accessment been conducted on the pipeline. segment? it Yes; and an investigative dig was 'contiuCted at the point of the Accident: Most recent year canduoted: -if Yes, but the paint of the Accident was not identi?ed as a dig a rte: . Most recent year conduetedi 5. Has one or more non?destructive examination been conducted at the Form PHMSA 7000.1 ?Nun-d" ?mm/II point of the Accident since January 1 2002'? So it Yes, for each examination, conducted since January 1 2002 select type of non? -dectructive examination and indicate most recent year the examination was conducted: - Radiography Most recent year conducted: - Guided Wave Uitraaonic ?Most recent year conducted: Handheld Ultrasonic Tool Most recent year conducted: no cases Isaac Test Most recent year conducted: I Dry Magnetic Particle Test Most recent year conducted: - Other Most recent year canducted: Describe: Compiete the following if Excavation Damage by Third IPart'y' to selected as the sub-cause. 6. Did the operator get prior noti?cation of the excavation activity? I Be. it Yes. Noti?cation received from: (seiect?aii that apply) - - One-Cali System - Excavator - Contractor - Landowner Complete the feiiI'Jwing mandatory DIRT Program queetiona if any Excavation Damage auh-cauee' Ia selected. 7 Do you want PH MSA to upioad the following information to OSA- DIRT ego-dirt. corn)? 8 Rightwof-Way where event occurred (seiect at! that appiyi- Public if "Public", Specify: - Private - if "Private?. Specify: Pipeline PropertyiEasement PowerfTransmission LlneI - Railroad Dedicated Public Utility Easement - Fedora! Land - Data not collected - UnknowniOther 9. Type of exaavator: 10. Type of excavation equipment: . 11. Type of work performed: 12. Was the One?Cali Center noti?ed? 12a, if,Yea, specify ticket nomher: 12b. it this is a State where more than a single One-Cali Center exists list the name of the One-Gail Center noti?ed: I 13. Type of Locator: 14. Were facility locate marks vieibie' In the area of excavation? 15 Were facilities marked correctly? 16. Did the damage cause an interruption in service? 165, If Yes specify duration of the interruption (hours) 17. Description of the CGA-DIRT Root Cause (select oniy the one predominant first {evei Root Cause and then, where avaiiabie as a choice, the one predominant second level CGA DiRTRoot Cause as wait): Root Cauae: if One-Cali Noti?cation Practices Not Suf?cient, specify: - if Locating Practices Not Suf?cient, specify: - if Excavation Practices Not Sufficient. specify: - if Othen?None of the Above, explain: ?34 - Other Outside Farce. Damage 4 .0th one sob-cause can be Selected. foam the shaded i?it?hano? coiumn Other Outside Force 'Damage Sub-Cause: .. If Damage by Car, Track, or Other Motorized NOT Engaged in ExcaVation: Vehicle-{Equipment operated by: - if Damage by Boats, Barges Drilling Rigs or Other Maritime Equipment or Vessels Set Adrift or Which Have chemiee Loet' - Their mooring: 2 Select one or more of the foiiowing iF an extreme weather event was a factor: Hurricane - Tropical Storm Form PHMSA ?000.?i - Tornado Heavy RalneiFicocl other if Other, Describe: - If Previous Mechanical Damage NOT Related to Excavation: Cfmpiete Questions ONLY IF the "item involved in. Accident".ifrom PART 0, Question 3) is Pipe or'Weld. 3. Has one or more internal inspection tool cciiacted data at the point of the Accident? Se. if Yes, for each too! used, select type of intemai inspection tool and indicate most recent year run: - Magnetic Flux Leakage Most recent year conducted: 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 I Most recent year conducted: - Transverse FieldiTriaxial Most recent year concocted: Other Mast recent year conducted: Desori be: 4. Do you have reason to believe that the internal inspection was completed BEFORE the damage was sustained? 5. Has one or more hydrotest or other pressure test been conducted since original construction at the point of the Accident? - if Yes: Most recent year tes .ed: Test pressure {psig}; 6. Has one or more Direct Assessment been Conducted on the pipeline segment? ?if Yes. and an investigative dig was conducted at the point of the Accident: I Most recent year conducted: Yes but the point of the Ascident was not identi?ed as a dig site: Most recent year conducted: Has one or more non-destructive examination. been conducted at th a point of the Accident since January 1, 2092? 7a. it Yes, for each examination conducted since January 1, 2002, select type of non-destructiveexamination and indicate most recent year the examination was conducted: - Radiography Most recent year condocted: - Guided Wave Ultrasonic Most recent year conducted; Handheld Ultrasonic Toot Most recent year conducted: Wet Magnetic Particle Test Most recent. year conducted: I Dry Magnetic Particle Test Most recent year conductetii . I. .c Most-Irecent year conducted: Descr be: - If Intentional Damage: 8. Specify: - if Other. Outside Force Damage: it Other, Describe: 9. Describe: GE - Material Failure of Fine or. Weid - only one sch?cause can be selected from the column Use this section to report material failures ONLY IF the ?Item lny cured in Accident?_ {from PART-C, Question It); is "Pipe" or "Weld. Material Failure ofEipc or Weld Sub-Cause: Original Manufacturing-related (NOT girth weld or other welds formed' In the field} Forrn PHMSA 7000.1 1. The sub-muse eeiect cit Field Examination Other - - if Sub-cause is Tentative or Suspected; Stilt rider Investigation if Construction or factors: that . - or Yes - . Specify: Mechanicaily?induced Fatigue poor to ineteiietion {such as it Other Describe: It Describe: -"lf - 3. . - if Describe: Complete the foitowing if any Material Failure cf Pipe or Weld sub-cause is selected. 4. . at! Dent - Bend - Burn - Cre?cit of ueion Burnt - if Describe: 5. one or more internal! inspection tool collected data at the point of the Accident? 58. If for each tool select of on and - Flux Yee Most recent 5 - Ultrasonic Yes Most 5 Yee recent 3 Yes recent a Greek Hard _.Moet recent. - Combination Toot Transverse Most recent - Other Most recent Describe: one or more hydroteet or other pressure test been conducted since at the - If Yes: tested; est . Has one or more Direct Assessment been conducted on the pipeline If and an was at the conducted: - if the the Accident not as a site Most recent conducted: 8. Has one or more non-destructive examinaticn{s) been conducted at the No of the Accident 1 2002? Form PHMSA 17000.1 8a If Yes. for each examination conducted since January 1, 20 recent year the examination was conducted: 02, select type of non- -destructive examination and indicate most 7 Radiography Most recent year conducted: Guided Wave Ultrasonic Most recent year conducted: - Handheld Ultrasonic Tool Meet-recent year conducted: - Wet Magnetic Particle Test Most recent year conducted: Dry Magnetic Particle Test Most recent year conducted: Other . Most recent year conducted: 5 Describe: i 86 E-quiprnent Failure - only one auhucause can. be selected ?are the shaded left?hand column Equipment Failure? SubuCauee: it Malfuncticn of ContrciiRelief Equipment: 1 Specify: (seiect ail that apply) - - Control Valve (instrumentation SCADA ?'Gommunlcaticns Block valve .. Check Valve Relief Valve - Power Failure - Fitting - ESD System" Failure . Other . . - If Other Descr ibe: - lf Pump or Pump?related Equipment: 2. Specify: if Other Describe: - if Threaded Ccnnecticnii?icupling Failure: 5 3. Specify; i . - If Other_ Describe: 4h? Nun?threaded Connection Failure: . . i 4. Specify: i - it Other Describe: it Other Equipment Failure: . i 5. Describe: Complete the following if any Equipment Failure sub-cause is selected 6. Additional factors that contributed to the equipment failure: (select; Excessive vibration that apply) i Overpressurization - No Support or loss of support - Manufacturing defect Loss of electricity installation 3 - Mismatched items (different manufacturer for tubing and tubing ?ttings} Dissimiiar metals - Breakdown of soft gccde due to compatibility issues with transported cammcdity Vaive vault or valve can contributed to the release Alarmistatus faiiure - Misaiignment Thermal stress - Other - If Other, Descr? be: $7 incorreci: Speraticn only one sub-cause can'be selected trem'the. shaded left-hand column Form PHMSA 7000.1 i . m/ Incorrect Operation - Sub -Cause: - if Tank, Vessel, or SumpISeparator Allowed or Caused to Overflil or Over?ow repeciry; - If Other. Describe - if Other incanect Operation 2. Describe: Complete the following if any Incorrect Operation sub-cause is eeleetad. . 3; Was this Accident related to (select all that apply): - - inadequate procedure - No procedtrre established - Failure to follow procedure - Other: .. If Other, Describe: 4. What category type was the activity that caused the Accident? 5. Was the taek(s) that led to the Accident identi?ed as a covered task in your Operator Quali?cation Program? 5a. If Yes, were the individuals performing the taskls) quali?ed for the taskts)? 68 Other Accident Cause - only one sub-Gauge can be Selected from the shaded left-hand column Other Accident Cause? SubaCaHuse: - If Miscellaneous: 1. DesonbeUnknown: .2 Specify: PART - NARRATIVE DESCRIPTION OF THE ACCIDENT 5t20l16 00:35hre PT the 2 pipe segment from Tracy to Windmi? Farms ruptured. The pipeline Houston Controi Center SCADA detected an increase In flow rate. and drop in rilechnrue pressure. The Pump Station immediately on law suction. The Controller took action to shutdown the entire pipeline system and isolate the pipeline. Noli?cailms were made to the ?eld supervisor. the Control Center Supervisor. Personnel were sentlo the area of the pump stailun to locate the exact location of the release. Following the replacement of the failed pipe ioint the CSFM gave permission to displace the heavy crude oil from the pipeline with light nude oil before an agreed plan of action on the vintage pipe which failed. inspections and repairs were initiated. along with pressure testing of affected segments. The pipetlno was restarted with the approval of the CSFM on July 19. 2016. ?i?he felled pipe was examined at a metallurgical laboratory. SP LC's Subject Matter Ewart (SME) reviewed the analysis. PART - PREPARER AND AUTHORIZED SIGNATURE Preparers Name I Richard Klasen Preparers lltle Preparer's Telephone Number Preparer?s E-mall Address Preparer? Facsimile Number Authorized Signer Name. Deborah Price Authonzed Signer Title Pipeline Ops Regulatory Manager Authorized Signer Telephone Number Authorized Signer Email - Date A 03l0512016 Form PHMSA 7000.1 NOTICE: This report is required by 49 CFR Part 195. Failure to report can result in a civil penalty not to OMB 2137004? exceed $100,000 for each violation for each day that such violation persists except that the maximum civil EXPIRATION 12l31l2016 penalty shall not exceed $1,000,000 as provided in 49 USC 60122. Orlginal Report 06/15/2016 Date: (V US Department of Transportation No. 20160184 21442 Pipeline and Hazardous Materials Safety Administration (DOT Use Only) ACCIDENT REPORT - HAZARDOUS LIQUID PIPELINE SYSTEMS A 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 with a collection of information subject to the requirements of the Paperwork Reduction Act unless that collection of Information displays a current valid OMB Control Number. The OMB Control Number for this information collection is 2137-0047. All responses to the collection of information are mandatory. Send comments regarding this burden or any other aspect of this collection of information. including suggestions for reducing the burden to: Information Collection Clearance Of?cer. PHMSA. Of?ce of Pipeline Safety (PHP-30) 1200 New Jersey Avenue, SE, Washington. DC. 20590. INSTRUCTIONS Important: Please read the separate instructions for completing this form before you begin. They clarify the information requested and provide specific examples. it you do not have a copy of the instructions, you can obtain one from the PHMSA Pipeline Safety Community Web Page at PART A - KEY REPORT INFORMATION Report Type: (select all that apply) @328]. Supplemental. Final. Last Revision Date: 1. Operator?s OPS-issued Operator Identi?cation Number (OPID): 31174 2. Name of Operator SHELL PIPELINE LP. 3. Address of Operator: 3a. Street Address 910 LOUISIANA STREET. 42ND FLOOR 3b. City HOUSTON 30. State Texas 3d. Zip Code 77002 4. Local time (24-hr clock) and date of the Accident: 05/20/2016 00:35 5. Location of Accident: Latitude: Longhude: 6. National Response Center Report Number (if applicable): 1148267 7. Local time (24-hr clock) and date of initial telephonic report to the . National Response Center (if applicable): 05/20/2016 02'? 8. Commodity released: (select only one, based on predominant Crude Oil volume released) - Specify Commodity Subtype: - If "Other" Subtype, Describe: - If Biofuel/Alternative Fuel and Commodity Subtype is Ethanol Blend, then Ethanol Blend: - If BiofueI/Alternative Fuel and Commodity Subtype is Biodiesel. then Biodiesel Blend 3.9. 82, B20. B100 9. Estimated volume of commodity released unintentionally (Barrels): 500.00 10. Estimated volume of intentional and/or controlled release/blowdown (Barrels): 11. Estimated volume of commodity recovered (Barrels): 400.00 12. Were there fatalities? No - If Yes. specify the number in each category: 12a. Operator employees 12b. Contractor employees working for the Operator 120. Non-Operator emergency responders 12d. Workers working on the right-of-way, but NOT associated with this Operator 12a. General public 12f. Total fatalities (sum of above) 13. Were there injuries requiring inpatient hospitalization? No - If Yes. specify the number in each category: 13a. Operator employees 13b. Contractor employees working for the Operator 13c. Non-Operator emergency responders 13d. Workers working on the right-of-way, but NOT associated with this Operator 13e. General public Form PHMSA 7000.1 131?. Total injuries (sum of above) 14. Was the pipelineifacility shut down due to the Accident? Yes If No, Explain: If Yes. complete Questions 14a and 14b: {use local time, 24-hr clock) 14a. Local time and date of shutdown: 05!20!2016 00:37 14b. Local time pipeline!facility restarted: 05!23!2016 13:00 Still shutdown? Supplemental Report Required) 15. Did the commodity ignite? No 16. Did the commodity explode? No 17. Number of general public evacuated: 0 18. Time sequence (use focal time. 24-hour clock): 18a. Local time Operator identified Acoldent effectlve 7? 2014 05!20!2016 00:35 changed to "Local time Operator identified failure": 18b. Local time Operator resources arrived on site: 05!20!2016 02:17 PART 3- ADDITIONAL LOCATION INFORMATION 1. was the origin of the Accident onshore? Yes if Yes, Compiete Questions {2?12) if No, Complete Questions (13-15) If OriSho?re: -- . - 2. State: California 3. Zip Code: 95304 4. City Tracy 5. County or Parish Alameda 6. Operator-designated location: MileposWalve Station . Specify: 137.3 7. Pipeline!Facility name: North 20 8. Segment nameilD: Tracy to Windmill Farms 24" 9. Was Accident on Federal lend. other than the Outer Continental Shelf No (008)? 10. Location of Accident: Pipeline Right?of~way 11. Area of Accident (as found): Underground Specify: Under soil - If Other. Describe: Depth-of?Cover 84 12. Did Accident occur in a crossing? No If Yes, specify type below: ?If Bridge crossing Cased! Uncased: - lf Railroad crossing Cased! Uncased! Bored!drilled - If Road crossing Cased! Uncased! Bored!drilled - If water crossing Cased! Uncased - Name of body of water. if commonly known: - Approx. water depth (it) at the point of the Accident: - Select: .- If_ Offshore: 13. Approximate water depth (ft) at the point of the Accident: 14. Origin of Accident. - In State waters - Specify: State: Area: - Block!Tract it: - Nearest County!Parish: On the Outer Continental Shelf (OCS) - Specify: Area: - Block 15. Area of ACCIdent PART C- ADDITIONAL FACILITY INFORMATION . 1. Is the pipeline or facil lity: intrastate 2. Part of system involved in Accident: Onshore Pipeline Including Valve Sites lf Onshore Breakout Tank or Storage Vessel, Including Attached Appurtenances, specify: 3. Item involved in Accident: Pipe - If Pipe, specify: Pipe Body 3a. Nominal diameter of pipe 24 Form PHMSA 7000.1 3b. Wall thickness .260 3c. SMYS (Specified Minimum Yield Strength) of pipe (psi): 60,000 3d. Pipe specification: 5LX 3e. Pipe Seam specify: DSAW it Other, Describe: 3f. Pipe manufacturer: ARMCO 3g. Year of manufacture: 1982 3h. Pipeline coating type at point of Accident, specify: Polyolefin If Other, Describe: If Weld, including heat?affected zone, specify. If Pipe Girth Weld, 3a through 3h above are required: - If Other. Describe: If Valve, specify: - If Mainline, specify: - If Other, Describe: 3i. Manufactured by: 3j. Year of manufacture: - If TankNesseI, specify: it Other Describe: If Other, describe: 4. Year item involved in Accident was installed: 1989 5. Material involved in Accident: Carbon Steel If Material other than Carbon Steel, specify: 6. Type of Accident Involved: Rupture - if Mechanical Puncture Specify Approx. size: - in. (axial) by in. (circumferential) - if Leak - Select Type: - If Other, Describe: - lf Ru pture - Select Orientation: Longitudinal - lf Other, Describe: ?Approx. size: in. (widest opening) by 4.5 in. (length circumferentially or axially) 56.4 - If Other - Describe: PART CONSEQUENCE. INFORMATION 1. Wildlife impact: i No ?is. If Yes, specify all that apply: - Fishlaquatic Birds - Terrestrial 2. Soil contamination: Yes 3. Long term impact assessment performed or planned: No 4. Anticipated remediation: No 4a. it Yes, specify all that apply: - Surface water - Groundwater Soil Vegetation - Wildlife 5. Water contamination: No 5a. If Yes, specify all that apply: OceanfSeawater - Surface - Groundwater Drinking water: {Select one or both) - Private Well Public Water Intake 5b. Estimated amount released in or reaching water (Barrels): 5c. Name of body of water, if commonly known: 6. At the location of this Accident, had the pipeline segment or facility been identified as one that "could affect" a High Consequence Area Yes (HCA) as determined in the Operator's Integrity Management Program? 7. Did the released commodity reach or occur in one or more High Yes Consequence Area 7a. If Yes, specify HCA type(s): {Select all that appfy) - Commercially Navigable Waterway: Was this HCA identi?ed in the "could affect" determination for this Accident site in the Operator's Form PHMSA 7000.1 integrity Management-Program? High Population Area: Was this HCA identified in the "could affect" determination for this Accident site in the Operator's integrity Management Program? Other Populated Area Was this HCA identi?ed in the "could affect" determination for this Accident site in the Operator's Integrity Management Program? Unusually Sensitive Area (USA) Drinking Water Yes Was this HCA identi?ed in the "could affect" determination for this Accident site in the Operator's Integrity Yes Management Program? - Unusually Sensitive Area (USA) - Ecological Yes Was this HCA identified in the "could affec determination for this Accident site in the Operator's Integrity Yes Management Program? 8. Estimated cost to Operator" effective 12-2012, changed to "Estimated Property Damage": 8a. Estimated cost of pubiic and non-Operator private property damage paidireimbursed by the Operator effective 12?2012, 250.000 "paidireimbursed by the Operator" removed 8b. Estimated cost of commodity iost 0 8c. Estimated cost of Operator's property damage repairs 1,500,000 8d. Estimated cost of Operator's emergency response 8 1,050,000 8e. Estimated cost of Operator's environmental remediation 8 1,000,000 8f. Estimated other costs 0 Describe: 8g. Estimated total costs (sum of above) effective 12-2012, 3 800 000 changed to "Total estimated property damage (sum of above)" PART ADDITIONAL OPERATING INFORMATION 1. Estimated pressure at the point and time of the Accident (psig): 694.00 2. Maximum Operating Pressure (MOP) at the point and time of the 936 00 Accident (psig): 3. Describe the pressure on the system or facility relating to the Accident (psig): Pressure did not exceed MOP 4. Not including pressure reductions required by PHMSA regulations (such as for repairs and pipe movement), was the system or facility relating to the Accident operating under an established pressure No restriction with pressure limits below those normally allowed by the if Yes, Complete 4.a and 4b below: 4a. Did the pressure exceed this established pressure restriction? 4b. Was this pressure restriction mandated by PHMSA or the State? 5. Was "Onshore Pipeline, including Valve Sites" OR "Offshore Pipeline, Including Riser and Riser Bend" selected in PART C, Question Yes 2? if Yes (Compiete 5a. - 5fbeiow) effective 12-2012, changed to Complete 5.6 5.e beiow)" 5a. Type of upstream valve used to initially isolate release Remotely Controlled source: giggles of valve used to initialiy isolate release Remoteiy Controlled 5c. Length of segment isolated between valves 16,125 5d. Is the pipeline con?gured to accommodate internal inspection tools? es - if No, Which physical features limit tool accommodation? seiect that appiy) - Changes in line pipe diameter Presence of unsuitable mainline valves Tight or mitered pipe bends - Other passage restrictions unbarred tee's, projecting instrumentation. etc.) Extra thick pipe wall (applicable only for magnetic flux leakage internal inspection tools) - Other - if Other, Describe: 5e. For this pipeline, are there operational factors which significantly complicate the execution of an internal inspection tool No run? - If Yes, Which operational factors complicate execution? (seieci?aia' that appiy) Form PHIVISA 7000.1 Excessive debris or scale, wax, or other wall buildup - Low operating pressure(s) Low flow or absence of flow Incompatible commodity Other - - If Other, Describe: 5f. Function of pipeline system: 20% SMYS Regulated TrunklineiTransmission 6. Was a Supervisory Control and Data Acquisition (SCADA)?based system in place on the pipeline or facility involved in the Accidentoperating at the time of the Accident? Yes Was it fully functional at the time of the Accident? Yes 60. Did SCADA-based information (such as alarm(s), alert(s), event(s), andior volume calculations) assist with Yes the detection of the Accident? 6d. Did SCADA?based information (such as alarm(s), alert(s), event(s). and/or volume calculations) assist with No the confirmation of the Accident? 7. Was a CPM leak detection system in place on the pipeline or facility Yes involved in the. Accident? - If Yesf 7a. Was it operating at the time of the Accident? Yes 7b. Was it fully functional at the time of the Accident? Yes 70. Did CPM leak detection system (such as alarm(s), alert(s), event(s), andior volume calculations) assist Yes with the detection of the Accident? Td. Did CPIVI leak detection system information (such as alarm(s), alert(s), event(s), andi?or volume calculations) assist No with the confirmation of the Accident? 8. How was the Accident initially identified for the Operator? CPM leak detection system or SCADAubased information (such as aiarm(s), alert(s), event(s), andior volume calculations) If Other, Specify: 8a. If "Controller", "Local Operating Personnel", including contractors", "Air Patrol", or "Ground Patrol by Operator or its contractor" is selected in Question 8, specify: 9. Was an investigation initiated into whether or not the controller(s) or centroi room issues were the cause of or a contributing factor to the Accident? Yes, specify investigation resuit(s): (select all that apply) - if No, the Operator did not find that an investigation of the controller(s) actions or control room issues was necessary due to: (provide an expianation for why the operator did not investigate) - If Yes, specify investigation result(s): (seiectaii that appiy) - Investigation reviewed work schedule rotations, continuous hours of service (while working for the Operator), and other factors associated with fatigue - investigation did NOT review work schedule rotations, continuous hours of service (while working for the Operator), and other factors associated with fatigue Yes Provide an explanation for why not: The Controllers response was compliant and effective. The size and consequence of the release was minimized as required by procedure. Notification to field perSOnnel was compliant to notification to the Console Supervisor. There were no issues to note in regards to Control Center response. There were no fatigue related issues. No drug testing was required. - Investigation identified no control room issues Yes - Investigation identi?ed no controller issues Yes - Investigation identified incorrect controller action or controller error investigation identi?ed that fatigue may have affected the controller(s) involved or impacted the involved controller(s) response - Investigation identi?ed incorrect procedures - Investigation identified incorrect control room equipment operation - Investigation identified maintenance activities that affected control room operations, procedures, andfor controller response - Investigation identified areas other than those above: Describe: Form PHMSA 7000.1 PART I5- oRuc reanc I 1. As a result of this Accident. were any operator employees tested I under the post?accident drug and alcohol testing requirements of DOT's No Drug Alcohol Testing regulations? - [f Yes: 1a. Specify how many were tested: 1b. Specify how many failed: 2. As a result of this Accident, were any Operator contractor employees tested under the post-accident drug and alcohol testing requirements of No DOT's Drug Alcohol Testing regulations? If Yes: 2a?. Specify how many were tested: 2b. Specify how many failed: PART APPARENT CAUSE Select only one box from PART ln shaded column on left the APPAREN cause of the Aeoldenf and anSWer' the questions on the right. Describe secondary, contributing or root as uses of the Acho'ent the narraflVe (PART H). Apparent Cause: (35- Material Failure of Pipe or Weld G1- CoerSIon Fallure only one sub-cause can he picked from shaded left- hand column Corr05Ion Failure Sub- Cause . . I I -If External Corrosmn 1. Results of visual examination: - If Other, Describe: 2. Type of corrosion: (select all that apply) - Galvanic - Atmospheric Stray Current - Microbiological Selective Seam - Other: - If Other, Describe: 3. The typels) of corrosion selected in Question 2 is based on the following: {select all that apply) - Field examination - Determined by metallurgical analysis Other: If Other, Describe: 4. Was the failed item buried under the ground? - ers: D4a. Was failed item considered to be under cathodic protection at the time of the Accident? If Yes - Year protection started: 4b. Was shielding, tenting, or disbonding of coating evident at the point of the Accident? 40. Has one or more Cathodic Protection Survey been conducted at the point of the Accident? If "Yes, CP Annual Survey" Most recent year conducted: If "Yes. Close Interval Survey" - Most recent year conducted: If "Yes, Other CP Survey" Most recent year conducted: . -lfNo: 4d. Was the failed item externally coated or painted? 5. Was there observable damage to the coating or paint in the vicinity of the corrosion? - if Internal _Corrosion:-_ 6. Results of visual examination: - Other: 7. Type of corrosion (select all that apply):- - Corrosive Commodity - Water drop-outlAcid Microbiological - Erosion Other: - If Other, Describe: 8. The cause(s) of corrosion selected. in Question 7 is based on the following (select all that apply): Field examination Form PHMSA 7000.1 - Determined by metallurgical analysis - Other: - If Other, Describe: 9. Location of corrosion (seiectaiithatappiy):- - Low point in pipe - Elbow - Other: 4 if Other, Describe: 10. Was the commodity treated with corrosion. inhibitors or biocides? 11. Was the interior coated or lined with protective coating? 12. Were cleaningidewatering pigs (or other operations} routinely utilized? 13. Were corrosion coupons routinely utilized? Complete the following if any Corrosion Failure sub-cause' [3 selected AND QUeStion Is TankNessel. the "Item involved' In Accident" (from PART C, 14. List the year of the most recent inspections. 14a API 653 Out-of? Service inspection No Out-of?Service Inspection completed 14b. API 653 In- Service Inspection No In-Service Inspection completed Complete the. following if any Corrosion Failure subZ-cause' Is selected AND Question Is Pipe or Weld.- - the? T'item InVoIved in Accident? (from PART 15. Has one or more internal inspection too] collected data at the point of the Accident? 15a. If Yes, for each tool used, select type of internal inspection tool and i ndicate most recent year run: - - Magnetic Flux Leakage Tool Most recent year: Ultrasonic Most recent year: Geometry Most recent year: - Caliper Most recent year: Crack Most recent year: - Hard Spot Most recent year: Combination Too! Most recent year: Transverse FieldiTriaxial Most recent year: - Other Most recent year: Describe: 16. Has one or more hydrotest or other pressure test been conducted since original construction at the point of the Accident? lers Most recent year tested: Test pressure: 17'. Has one or more Direct Assessment been conducted on this segment? ~lf Yes, and an investigative dig was conducted at the point of the Accident: Most recent year conducted: - If Yes, but the point of the Accident was not identi?ed as a dig site: Most recent year conducted: 18. Has one or more non?destructive examination been conducted at the point of the Accident since January 1. 2002? 18a. it Yes, for each examination conducted since January 1, 2002, select type of non-destructive examination and indicate most recent year the examination was conducted: - Radiography Most recent year conducted: - 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: Form PHMSA 7000.1 Describe: I G2 Natural Force Damage - only one Sub-cause caribe picked from shadedleft?handed column Natural Force Damage -- Sub- Cause: If Earth Movement, NOT due to Heavy RainsiFioods: - Specify: - If Other, Describe: - if Heanyain'SI?Floodsr 2. Specify: - If Other, Describe: ?LightningSpecify: I I - lfTemp'eratureSpecify: - If Other, Describe: 3- if Other Natural Force Damage: - 5. Describe: I. complete the folio-tying if any Natural Force Damage sub-causeis selected. 6. Were the natural forces causing the Accident generated in conjunction with an extreme weather event? 6a. If Yes, specify: {seiect at that appiy) - Hurricane - Tropical Storm - Tornado - Other ?lf Other Describe. G3 Excavatlon Damage .Ionly one sub- -oause can be plcked from shaded leftahand column. Excavatlon Damage Sub-Cause If Previous Damage clue to Excavatlon ActIVIty Complete Questions 1 -5 ONLY IF the f'ltem Involved' In Accident" (from PART C, Question 3) is Pipe or Weldmore internal inspection tool collected data at the point of the Accident? 1a. it Yes for each tool used select type ofInternal Inspectlon tool and indicate most recent year run - Magnetic Flux Leakage Most recent year conducted: - Uitras?onic 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 FieldI?Triaxial Most recent year conducted: - Other Most recent year conducted: Describe: 2. Do you have reason to believe that the internal inspection was completed BEFORE the damage was sustained? . 3. Has one or more hydrotest or other pressure test been conducted since original construction at the point of the Accident? If Yes: Most recent year tested: Test pressure {pslg): 4. Has one or more Direct Assessment been conducted on the pipeline segment? - If Yes, and an investigative dig was conducted at the point of the Accident: Most recent year conducted: I If Yes, but the point of the Accident was not identi?ed as a dig site: Most recent year conducted: 5. Has one or more non-destructive examination been conducted at the Form PHMSA 7000.1 point of the Accident since January 1, 2002??- 5a. If Yes, for each examination, conducted since January 1, 2002, select type of non-destructive examination and indicate most recent year the examination was conducted: Radiography Most recent year conducted: 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: Describe: the if Excavatlon Damage by Third Party is selected as the sub-cause 6. Did the operator get prior noti?cation of the excavation activity? 6a If Yes Noti?cation received from: (seiectaiithatappiyl- - One~Call System - Excavator - Contractor Landowner Complete the followmg mandatory Program questlons if any Excavatlon Damage sub-cause' Is selected. 7. Do you want to upload the following information to DIRT cga? ?dirt. com)? 8. Right-of?Way where event occurred: (seiect that appiy)- - Public - If "Public". Specify: Private -Ilf "Private", Specify: Pipeline PropertyiEasement PoweriTransmission Line - Railroad - Dedicated Public Utility Easement - Federal Land Data not collected - UnknowniOther 9. Type of excavator: 10. Type of excavation equipment: 11. Type of work performed: 12. Was the One-Call Center notified? 12a. If Yes. specify ticket number: 12b. If this is a State where more than a singie One?Catt Center exists list the name of the One-Cali Center notified: 13. Type of Locator: 14. Were facility locate marks visible In the area of excavation? 15. Were facilities marked correctly? 16. Did the damage cause an interruption in service? 16a. lf Yes specify duration of the interruption (hours) 17. Description of the CGA- DIRT Root Cause (select oniy the one predominant first ievei CGA- Root Cause and than Where avaiiabie as a choice, the one predominant second iavei CGA- Root Cause as Weii): Root Cause: - If One?Call Notification Practices Not Sufficient, specify: If Locating Practices Not Suf?cient, specify: Excavation Practices Not Sufficient specify: -lf Other/None of the Above, explain. G4- Other OutSIde Force Damage" - 'oniy one sub-cause; canbes?iected mama spacecraft?hand COiUmi?i I other OutSIde Force Dam. get} SUb-Cause .. -- lf Damage by Trtick, iorI Other Motorlzed VehicleiEqurpment NOT Engaged' In Excavation: 1. VehicleiEquipment operated by: I Damage by Beats, Barges, ngs, or Other MarItIme EqUIpment or Vessels Set Adrift or Which Otherwise Lost Their Moormg . . . . 2 Select one or more of the following 1F an extreme weather event was a factor: - Hurricane - Tropical Storm Form PHMSA 7000.1 - Tornado - Heavy RainsiFlood - Other if Other, Describe: l-f Previous mechanical Damage NOT Related to Excavation:- Complete Questions 3-7 ONLY lF the "Item Involved in Accident"- (froII'm PART C, Question 3) Is Pipe or Weld. 3. Has one or more internal inspection tool collected data at the point of the Accident? 3a. If Yes, for each tool used, select type of internal inspection tooi and-indicate most recent year run: Magnetic Flux Leakage Most recent year conducted: 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 FieIdITriaxial Most recent year conducted: Other Most recent year conducted: Describe: 4. Do you have reason to believe that the Internal inspection was completed BEFORE the damage was sustained? 5. Has one or more hydrotest or other pressure test been conducted since original construction at the point of the Accident? if Yes: Most recent year tested: Test pressure (psig): 6. Has one or more Direct Assessment been conducted on the pipeline segment? - If Yes, and an investigative dig was conducted at the point of the Accident: Most recent year conducted: 1 If Yes, but the point of the Accident was not identi?ed as a dig site: ivlost recent year conducted: 7. Has one or more non?destructive examination been conducted at the point of the Accident since January 1,2002? 7a. If Yes for each examination conducted since January 1 2002II select type of non?destructive examination and indicate most recent year the examination was conducted: Radiography Most recent year conducted: - 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: . Describe: If Intentional Damage: -- .- 8. Specify: -_lf Other, Describe: Other Outside Force Damage: - 3 9. I I IG5I.- Materlal of or Weld -_oInIin one sub-cause can be selected from the shaded left? hand column use this sectIon to report materlal faIlures IONLIY theI "Item Involved Accident? I(IfromI PARTI Questlon Is "Pipe" or "WeldIOIrIiginaIi Manufacturing ?related (NOT girth weld or other Materlal _FaIiIluIrIeI ofI oIrI WeldI? Sub-Cause welds formed in the ?eld) Form PHMSA 7000.1 1. The sub-cause shown above is based on the following: (select all! that appiy) - Field Examination Determined by Metallurgical Analysis Yes Other Analysis - if ?Other Analysis", Describe: - Sub-cause is Tentative or Suspected; Still Under investigation (Supplementai Report required) .. If Construction, thtaIla'tiOn, or Fabrication-"related 0r If Original manufacturing-related: 2. List contributing factors: (select at! that apply) Fatigue or Vibration-related Yes Specify: Mechanically-induced Fatigue prior to installation (such as during transport of pipe) if Other. Describe: Mechanical Stress: Other If Envirohmentai Cracking-related: If Other, Describe: 3. Specify: - it Other Describe: Campiete'the fotlowmg if any material Failure Of Pipeor Weld-subscl'auSe is Selected. 4. Additional factors: (seiect ail that apply): Dent - Gouge - Pipe Bend - Arc Burn Crack Yes - Lack of Fusion - Lamination Buckle Wrinkle. iviisaiignment Burnt Steel - Other: If Other, Describe: 5. Has one or more internal inspection tool collected data at the point of . es the Accrdent? 5a. If Yes, for each tool used, select type of internal inspection tool and indicate most recent year run: Magnetic Flux Leakage Yes Most recent year run: 2015 - Ultrasonic Yes Most recent year run: 2015 Geometry Yes Most recent year run: 2013 - Caliper Most recent year run: - Crack Yes Most recent year run: 2015 - Hard Spot Most recent-year run: Combination Tool Most recent year run: - Transverse FieldiTriaxial Yes Most recent year run: 2015 Other Most recent year run: Describe: 6. Has one or more hydrotest or other pressure test been conducted since Yes original construction at the point of the Accident? - If Yes: Most recent year tested: 1989 Test pressure (psig): 1,190.00 7. Has one or more Direct Assessment been conducted on the pipeline No segment? - it Yes, and an investigative dig was conducted at the point of the Accident - Most recent year conducted: I - If Yes, but the point of the Accident was not identified as a dig site - Most recent year conducted: 8. Has one or more non-destructive examination(s) been conducted at the No point of the Accident since January 1, 2002? Form PHMSA 7000.1 8a. it Yes, for each examination conducted since January 2002, select type of non?destructive examination and indicate most recent year the examination was conducted: - Radiography Most recent year conducted: 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: Describe: (56 Equipment Failure only One Sub-cause can be Selected from-the shadedleft-hand cinmn Eqmpment Failure Sub-Cause Alf MalfUnction of ControllRelief Equipment: 1. Specify: {select all that apply)- - Control Valve Instrumentation - SCADA Communications - Block Valve Check Valve - Relief Valve Power Failure StopplefControl Fitting - ESD System Failure Other - lf Other Describe: If Pump or Pump-Arelated' Equipment: 2. Specify: - it Other Describe: - Threaded Co'nnectlonlCOUplin'g Failure: 3. Specify: - if Other Describe: If Nomthreaded ConneCtion' Failure: . 4. Specify: - If Other-u Describe: Other Equipment Failure: I :3 5. Describe. I I Complete the following if any Eqmpment Failure s'ub- -cause is selected 6. Additional factors that contributed to the eqUIpment failure (safect all that apply) Excessive vibration Overpressurization - No support or loss of support Manufacturing defect Loss of electricity - Improper installation - Mismatched items (different manufacturerfor tubing and tubing fittings) - Dissimilar metals - Breakdown of soft goods due to compatibility issues with transported commodity Valve vault or valve can contributed to the release a failure - ivlisalignment - Thermal stress - Other if Other, Describe G7- _lncorrect Operation- only one sub-cause Can be selected from the shaded left- hand column Form PHMSA 7000.1 Incorrect Operation? --Su:b-Cause - If Tank, Vessel, or Sump/SeparatorAilowed or Caused to Ior Overflow 1. Specify: - If Other. Desdribe: If Other Incorrect Operation 2. Describe: I Complete the following If any incorrect operation Sub-cause Is selected. 3, Was this Accident related to (select all that apply): - - inadequate procedure . No procedure established - Failure to follow procedure - Other: - If Other. Describe: 4. What category type was the activity that caused the Accident? 5. Was the taek(s) that led to the Accident identified as a covered task in your Operator Quali?cation Program? 58. If Yes. were the individuals performing the tasl<(s) queii?ed for the task(e)? GB - Other Accidentlcause - only one sub-cause can be selected from the shaded left-hand column - I0__th er IAcIcicIle nt Cause sub-Cause: .-if Miscellaneous: 1.Describe: I I if Unknown: 3. 2. Specify: . IPART H- NARRATIVE DESCRIPTION OF THE ACCIDENT 5/20116 00:35hrs PT the 24' pipe segment from Tracy to Windmill Farms ruptured. The pipeline Houston Control Center SCADA detected an increase in ?ow rate and drop In discharge pressure. The Pump Station immediately shutdown on low suction. The Controller took action to shutdown the entire pipeline system and isolate the pipeline. Noti?cations were made to the ?eld supervisor. the Control Center Supervisor. Personnel were eentto the area of the pump station to locate the exact location of the release. PART I- PREPARER AND AUTHORIZED SIGNATURE Preparer? 3 Name Richard Klasen Preparers Title Re uiator ecialist Preparer?s Telephone Number Preparer's E-mail Address Preparer's Facsimile Number Authorized Signer Name Deborah Price Authorized Signer Title Pi eline ulato Manager Authorized Signer Telephone Number Authonzed Signer Email Date 06/15/2016 Form PHMSA 7000.1 .3 Fmal Report Metallurgical Analysis of May 20, 2016 Rupture on Tracy to Windmill Portion of . San Pablo Bay Pipeline System Pipeline Company Houston, Texas Report No.: (PP158491) November 7, 2016 Shell Pipeline Company Metallurgical Analysis of May 20 2016 Rupture on Tracy to Windmill Portion of San Pablo Bay Pipeline System Project Name: Metallurgical Analysis of May 20 DET NORSKE VERITAS (U.S.A.), INC. (DNV GL) 2016 Rupture on Tracy to Materials Corrosion Technology Center Windmill Portion of San Pablo Bay Incident Investigation Pipeline System 5777 Frantz Road . . Dublin, OH 43017-1886 Customer. Shell Pipeline Company United States Contact Person: Taylor Shie (614) 761'1214 Fax: (614) 761?1633 Date of Issue. November 7, 2016 Project No.: PP158491 Organization Unit: Incident Investigation Report No.: OAPUS311MPHB (PP158491) Task and Objective: Please see Executive Summary. Prepared by Verified by Approved by x/p?fsg, 7-7" H. 91A [6.2mm f??m . Michiel ohn A. Beavers, FNACE David M. Norfleet, P.E. Principal Engineer Senior Principal Engineer Head of Section Incident Investigation El Unrestricted Distribution (internal and external) Keywords Unrestricted Distribution Within DNV GL Rupturef seam weld, HAZ, ID surface, fatigue, Limited Distribution within DNV GL after 3 years environmental cracking No Distribution within DNV GL (confidential) El Secret Copyright DNV GL 2016. All rights reserved. 33 ?as 1 10/25/2016 Second Issue MB JB DN 2 10/27/2016 Third Issue MB 18 DN . 3 11/07/2016 Final Report MB JB DN OAPUS311MPHB November 7, 2016 - - ii Shell Pipeline Company Metallurgical Analysis of May 20, 2016 Rupture on Tracy to Windmill Portion of San Pablo Bay Pipeline System Executive Summary Shell Pipeline Company, LP (SPLC) retained Det Norske Veritas (U.S.A.), Inc. (DNV GL) to perform a metallurgical analysis of a rupture that occurred on the Tracy to Windmill portion of the San Pablo Bay Pipeline System. The failure occurred on May 20, 2015 in Tracy, California, approximately 4,068 feet from the nearest upstream pump station; the Tracy Pump Station. Tracy to Windmill is part of a 177.77 mile long segment of the San Pablo Bay Pipeline System consisting of 20?inch and 24?inch diameter pipe that originates at the Coalinga Station in Coalinga, CA and terminates at the Shell Martinez Refinery in Avon, CA. The Coalinga to Avon segment was originally installed in 1967. In 1989, three portions, totaling 12.55 miles, of the pipeline were replaced with 24?inch diameter by 0.260 inch wail, API 5LX Grade X60 double submerged arc?welded (DSAW) line pipe manufactured by Armco Steel in Houston, TX. The Tracy to Windmill portion, which is where the failure occurred, consists of 3.05 miles of the 12.55 miles of Armco line pipe installed in 1989. Historical information indicates that the Armco line pipe used to construct the 12.55 miles of pipeline was stored for approximately 7years following manufacturing and then was shipped from the northeastern United States to Coalinga, California for construction. The 12.55 miles of the replaced pipeline were externally coated with a 3?layer coating, comprised of fusion-bonded epoxy (FBE) on the pipe surface, a mastic coating, and an external polyolefin wrap. The pipeline has an impressed current cathodic protection (CP) system. The pipeline operates in heavy crude service, with temperatures up to On the day of the failure, the maximum allowable operating pressure (MAOP) of the pipeline was 936 psig, which corresponds to 72.0% of the specified minimum yield strength (SMYS). The segment operated with aggressive pressure cycling in the period leading up to the failure. The pressure at the time and location of the failure was estimated to be 665 psig, which corresponds to 51.2% of SMYS. The most recent hydrostatic pressure test prior to the failure was performed in 1990. A minimum pressure of 1181 psig (90% of SMYS) was held for four hours. The most recent in?line inspections (ILIs), using a circumferential magnetic flux leakage (CMFL) tool and an ultrasonic testing crack detection tool, were performed on 12/03/2015 and 12/04/2015, respectively. No anomalies in the failed joint were reported in the CMFL final report issued on 03/07/2016 or in the final report issued on 05/02/2016. DNV GL - (PP158491) November 7, 2016 Shell Pipeline Company Metallurgical Analysis of May 20, 2016 Rupture on Tracy to Windmill Portion of San Pablo Bay Pipeline System A pipe section that contained the rupture was delivered to DNV GL for metallurgical analysis. The objectives of the analysis were to determine the metallurgical cause of the failure and identify any contributing factors. The results of the metallurgical analysis indicate that the pipe joint ruptured at a fatigue crack that initiated at the toe of the DSAW seam weld on the inside surface of the pipe. Likely contributing factors include the peaked geometry of the failed pipe joint at the seam weld that introduced a bending stress, corrosion micro-pits on the ID surface that provided initiation sites, aggressive pressure cycling of the pipeline, and possibly an environmental effect on crack growth. The fatigue crack initiation and propagation most likely occurred while in service. However, transit fatigue during transportation of the pipe cannot be ruled out as a contributing factor. Shell reported to have records of rail transportation per API 5L1 for the first portion of the journey, from Houston Texas to the northeast of the U.S. For the second portion of the journey, from the northeast to Coalinga California, verbal information indicates that API 5L1 would have been specified per industry norms, but written records have not been located. The following steps were performed for this analysis: . Visual inspection and photography, . Removal of remnant coating still adhered to the pipe, . Dimensional measurements, . Magnetic particle inspection (MP1), . - Removal, cleaning and visual inspection of samples, . Light microscopy and scanning electron microscopy of fracture surfaces (SEM), . Examination of metallographically prepared cross-sections, - Energy dispersive spectroscopy (EDS), . Mechanical testing (duplicate tensile tests and full Charpy anotch curves), . Chemical analysis of steel samples, and - Failure pressure calculations using DNV GL OAPUS311MPHB (PP158491) iv November 7, 2016 Shell Pipeline Company . . Metallurgical Analysis of May 20, 2016 Rupture on Tracy to Windmill Portion of San Pablo Bay Pipeline System Summary of observations: The pipe joint that ruptured contained several types of mill anomalies at the long seam weld, including peaking, weld overlap, and weld undercut. The fatigue crack at the rupture origin was 6.96 inches long and initiated from small (50?100 micron) pits along the internal toe of the DSAW. There was no evidence of a pre?existing weld?type defect at this location. The long-seam weld was located at the 3:26 o?clock orientation. MPI testing revealed other crack-like flaws on the pipe joint that failed, at approximately 2.7 feet and 7.7 feet of the rupture origin along the internal surface of the DSAW. The largest feature (MPI Indication 1a) was 4.25 inches in length and 0.125 inches depth (48.1% of 0.260 inches nominal wall thickness) at the deepest location. Qualitative spot testing indicated the presence of sulfides on the fracture surface at the failure origin, which is not uncommon in crude oil pipelines. Cross?sections showed that cracks at weld toes at locations away from the rupture were filled with sulfur~containing products, which is not uncommon in crude oil pipelines. There was no evidence of external corrosion on the pipe section. No MPI indications were identified on portions of the longitudinal seam weld of the or joints that were examined; 1.58 feet of the joint and 1.79 feet of the joint. The tensile properties of the failed joint and the joints and of the failed joint meet the tensile requirements for API 5LX Grade X60 line pipe steel for the estimated vintage of the pipe (1980). The Charpy V?notch (CVN) properties of the base metal of the failed joint are typical for the vintage and grade of line pipe steel. The seam weld HAZ had better fracture toughness properties than the base metal, with a higher upper shelf impact energy and lower 85% temperature. The composition of the base metal of the failed joint and the joints and of the failed joint meets requirements for API 5LX Grade X60 line pipe steel for the estimated vintage of the pipe (1980). The microstructures of the pipe joints are typical for the vintage and grade of line pipe steel. The estimated failure pressure using mechanical properties of the heat affected zone and the flaw profile that ruptured is 664 psig, which is close to the calculated pressure at the failure location and time of failure (665 psig). DNV GL (PP158491) November 7, 2016 Shell Pipeline Company Metallurgical Analysis of May 20, 2016 Rupture on Tracy to Windmill Portion of San Pablo Bay Pipeline System Table of Contents 1.0 BACKGROUND 1 2.0 TECHNICAL APPROACH 2 3.0 RESULTS AND DISCUSSION 3 3.1 Optical Examination 3 3.2 Magnetic Particle Inspection 5 3.3 Fractographic 5 3.3.1 Rupture Location 5 3.3.2 Testing for Sulfides and Carbonates Primary Fracture Surface 7 3.3.3 MPI Indications 7 3.3.4 Testing for Sulfides and Carbonates MPI Indication 1a 8 3.4 Metallographic Examination 8 3.4.1 Rupture Origin 8 3.4.2 Reference Locations 10 3.4.3 MPI Indications - 1 0 3.4.4 EDS Analysis of Cracks and Corrosion Products 11 3.4.5 Hardness Testing 12 3.4.6 DSAW Measurements 13 3.5 Mechanical Testing 14 3.6 Chemical Analysis 15 3.7 Failure Pressure Analysis 15 4.0 CONCLUSIONS 16 Appendices Appendix A DSAW Measurements Appendix Analysis DNV GL OAPUS311MPHB (PP158491) vi November 7, 2016 Shell Pipeline Company Metallurgical Analysis of May 20, 2016 Rupture on Tracy to Windmill Portion of San Pablo Bay Pipeline System List of Tables Table 1. Table 2. Table 3. Table 4. Table 5. Table 6. Table 7. Table 8. Table 9. Table 10. Table 11. Table 12. Table 13. Results of diameter measurements performed on the and joints, adjacent to the failed pipe joint. 18 Results of wall thickness measurements performed on the and failed pipe joints in areas with negligible corrosion and no coating. 18 Summary of locations of metallurgical mounts and other features on the received pipe section 19 Summary of the locations and dimensions of indications identified on the internal surface of failed joint by magnetic particle inspection.. 20 Results of EDS analyses (in performed on corrosion products remaining within corrosion pits at weld toe on the internal pipe surface of Mount M2. Refer to Figure 47 for analysis locations 20 Results of measurements performed on Mounts to determine the angle between the plate edges on the CCW and CW sides of the seam weld. Refer to Appendix A for additional details. 21 Results of tensile tests performed on transverse base metal and weld (HAZ) specimens from the joint that ruptured compared with requirements for API SLX Grade X60 line pipe steel.2 22 Results of tensile tests performed on transverse base metal specimens from the and joints compared with requirements for API 5LX Grade X60 line pipe steel.2 22 Results of Charpy V-notch impact tests performed on transverse base metal specimens removed from the joint that ruptured. 23 Results of Charpy V?notch impact tests performed on transverse seam weld (HAZ) specimens removed from the joint that ruptured 23 Results of analyses of the Charpy V?notch impact energy and percent shear plots for base metal and seam weld (HAZ) specimens removed from the joint that ruptured. 24 Results of chemical analyses performed on samples removed from the joint that ruptured and the and joints compared with composition requirements for API SLX Grade X60 line pipe steel.l 25 Results of failure pressure analyses using The pressure at the failure site was estimated to be 665 psig 26 DNV GL (PP158491) vii November 7, 2015 Shell Pipeline Company Metallurgical Analysis of May 20, 2016 Rupture on Tracy to Windmill Portion of San Pablo Bay Pipeline System List of Figures Figure 1. Schematic of Pipe Section showing the location of the rupture, MPI indications, and where samples were removed for mechanical testing, chemistry, and metallography (Mounts M1, M2, M3, M4, M5, M6, M7). 27 Figure 2. Photograph of Pipe Section in the as-received condition at DNV GL. 28 Figure 3. Photographs of Pipe Section showing the rupture location following removal of the protective plastic wrappings 29 Figure 4. Photograph of the internal pipe surface showing MPI Indication 1a and MPI Indication 1b along the - clockwise (CW) and counterclockwise (CCW) side of the seam weld, approximately 2.7 feet of the rupture location (18.62 19.12 ft from GW), and location where Mount M1 was removed. 30 Figure 5. Photograph of the internal pipe surface showing MPI Indication 2 along the clockwise (CW) side of the seam weld, approximately 7. 7 feet of the rupture location (23. 83 ft from (SW), and location where Mount M2 was removed. 31 Figure 6. Photograph of the fracture surface (clockwise side) at the suspected rupture origin before cleaning. Light gray area is pre?existing flaw that initiated from the pipe inside surface. 32 Figure 7. Photo?collage of the fracture surface (clockwise side) at the suspected rupture origin after cleaning in a degreaser and methanol. Light gray area is the pre-existing flaw that initiated from the pipe inside surface. 32 Figure 8. Photomicrograph showing a portion of the fracture surface from the rupture, clockwise (CW) side of the seam Weld, after cleaning with a degreaser and methanol. Area indicated in Figure 7. 33 Figure 9. Photomicrograph showing close?up view of pits at ID pipe surface; area indicated in Figure 8. 33 Figure 10. SEM photomicrograph showing three distinct morphologies on fracture surface from rupture, area indicated in Figure 7 34 Figure 11. SEM photomicrograph showing Region 1 of fracture surface from rupture, 100x; area indicated in Figure 10. 34 Figure 12. SEM photomicrograph showing pit at ID surface 500x; area indicated in Figure 11. 35 DNV GL November 7, 2016 Shell Pipeline Company Metallurgical Analysis of May 20, 2016 Rupture on Tracy to Windmill Portion of San Pablo Bay Pipeline System List of Figures (continued) Figure 13. Figure 14. Figure 15. Figure 16. Figure 17. Figure 18. Figure 19. Figure 20. Figure 21. Figure 22. Figure 23. Figure 24. Figure 25. SEM photomicrograph showing fatigue striations in Region 1, area indicated in Figure 11. 35 SEM photomicrograph showing secondary cracking within Region 2, 500x; area indicated in Figure 10. 36 SEM photomicrograph showing small cracks on corrosion product? covered fracture surface in Region 2, area indicated in Figure 14. 36 SEM photomicrograph showing duCtile fracture morphology in Region 3, 500x; area indicated in Figure 10. 37 SEM photomicrograph showing ductile fracture morphology in Region 3, area indicated in Figure 16. 37 Photo?collage of the fracture surface (clockwise side), showing depth measurements (red) of Region 1 of the pre?existing flaw. 38 Photo?collage of the fracture surface (clockwise side), showing depth measurements (green) of Region 1 and Region 2 of the pre?existing flaw, together with wall thickness measurements (blue). 38 Flaw depth versus distance from the (SW for Region 1 and Region 2 identified on the fracture surface. The locations of Mount M5 and Mount M6 are indicated by dashed lines 39 Photograph of the clockwise (CW) side of the fracture surface associated with MP1 Indication 1a, and location of Mount M1. 4O Stereo?photograph showing a portion of the fracture surface associated with broken open MPI Indication 1a, without cleaning. Area indicated in Figure 21. 40 Stereo?photograph showing a close?up view of the fracture surface associated with broken open MPI Indication 1a, without cleaning. Area indicated in Figure 22. 41 Photograph of the mounted cross?section (Mount M5) removed from the likely ruptureorigin; 16.13 feet from the GW. Flow direction is into the page. Location indicated in Figure 1. 4% Nital Etch 42 Photograph of the mounted cross?section (Mount M6) removed from the ruptured joint, just from the likely rupture origin; 16.33 feet from the GW. Flow direction is into the page. Location indicated in Figure 1. 4% Nital Etch. 42 DNV GL (PP158491) ix November 7, 2016 Shell Pipeline Company Metallurgical Analysis of May 20, 2016 Rupture on Tracy to Windmill Portion of San Pablo Bay Pipeline System List of Figures (continued) Figure 26. Photomicrographs of Mount M5, showing microstructure of base . metal, weld fusion metal near ID, HAZ metal near ID weld toe, and HAZ metal near mid?wall. Locations indicated in Figure 25. 4% Nital Etch. 43 Figure 27. Photomicrograph of Mount M5, clockwise (CW) side of the weld, showing the fracture path in cross-section; area indicated in Figure 24. 4% Nital Etch. 44 Figure 28. Photomicrograph of Mount M6, clockwise (CW) side of the weld, showing the fracture path in cross?section; area indicated in Figure 25. 4% Nital Etch. 45 Figure 29. Photomicrograph of Mount M5 showing the microstructure and the fracture profile within Region 1 near the internal pipe surface; area indicated in Figure 27. 4% Nital Etch 46 Figure 30. Photomicrograph of Mount M5 showing the microstructure and the fracture profile within Region 2; area indicated in Figure 27. 4% Nital Etch. 46 Figure 31. Photomicrograph of Mount M5 showing the microstructure and the fracture profile within Region 3 near the external pipe surface; area indicated Figure 27. 4% Nital Etch. 47 Figure 32. Photomicrographs of Mount M5 showing round and elongated inclusions in the base metal and corrosion product in a micro-pit on the ID surface of the pipe; area indicated in Figure 24. 47 Figure 33. Photomicrograph of Mount M6, counterclockwise (CCW) side of the weld, showing a small crack at the weld toe; area indicated in Figure 25. 4% Nital Etch. 48 Figure 34. Photomicrographs of Mount M5 (top, refer to Figure 24) and Mount M6 (bottom, refer to Figure 25, showing cracks at weld toe with pits and corrosion products on ID pipe surface; counterc'loCkwise (CCW) side of the seam weld. 49 Figure 35. Photograph of the mounted cross?section (Mount M7) removed from the ruptured joint, away from the failure; 21.16 feet from the GW. Flow direction is into the page. Location indicated in Figure 1. 4% Nital Etch. 50 Figure 36. Photograph of the mounted cross?section (Mount M3) removed from joint; 28.19 feet from the GW (of the ruptured joint). Flow direction is into the page. Location indicated in Figure 1. 4% Nital Etch. 50 DNV GL (PP158491) November 7, 2016 Shell Pipeline Company Metallurgical Analysis of May 20, 2016 Rupture on Tracy to Windmill Portion of San Pablo Bay Pipeline System List Of Figures (continued) Figure 37. Photograph of the mounted cross?section (Mount M4) removed from joint; ?1.54 feet from the GW (of the ruptured joint). Flow direction is into the page. Location indicated in Figure 1. 4% Nital Etch. 50 Figure 38. Photograph of the mounted (Mount M1) removed from MPI Indication 1a (CW) and MP1 Indication 1b (CCW) of the ruptured joint, away from the rupture; 18.81 feet from the GW. Flow direction is into the page. Location indicated in Figure 1. 4% Nital Etch. 51 Figure 39. Photograph of the mounted cross?section (Mount M2) removed from MPI Indications 2 (CW) of the ruptured joint, away from the rupture; 23.83 feet from the GW. Flow direction is into the page. Location indicated in Figure 1. 4% Nital Etch. 51 Figure 40. Photomicrograph of Mount M1 (MPI Indication 1a) showing crack at weld toe from ID surface on clockwise (CW) side of the seam weld; mirror image of area indicated in Figure 38. 4% Nital Etch. 52 Figure 41. Photomicrograph of Mount M1 (MPI Indication 1a) showing crack tip on clockwise (CW) side of the seam weld; area indicated in Figure 40. 4% Nital Etch. Inset photo shows close?up of transgran'ular morphology at crack tip. . 53 Figure 42. Photomicrograph of Mount M1 (MPI Indication 1b) showing overlap of weld bead on ID surface, counterclockwise (CCW) side of the seam weld; mirror image of area indicated in Figure 38. 4% Nital Etch. 54 Figure 43. Photomicrograph of Mount M2 (MPI Indication 2), clockwise (CW) side of the weld, showing a notch from undercut at the weld toe; mirror image of area indicated in Figure 39. 4% Nital Etch. 55 Figure 44. Photomicrographs of Mount M2 (MPI Indication 2) showing crack at - weld toe from ID surface on clockwise (CW) side of the seam weld; mirror images of area indicated in Figure 39. 56 Figure 45. EDS map of Mount M1 (MPI Indication 1a) at crack shown in Figure 40, showing presence of sulfur at tip of the crack that started at weld toe from ID surface on clockwise (CW) side of the seam weld. 56 Figure 46. EDS map of Mount M1 (MPI Indication 1a) at crack shown in Figure 40, showing distribution the crack that started at weld toe from ID surface on clockwise (CW) side of the seam weld. 57 DNV GL OAPUS311MPHB (PP158491) xi November 7, 2016 Shell Pipeline Company Metallurgical Analysis of May 20, 2016 Rupture on Tracy to Windmill Portion of San Pablo Bay Pipeline System List of Figures (continued) Figure 47. EDS measurement locations on Mount M2 (results shown in Table 5; also refer back to Figure 44), at weld toe crack with pit and corrosion product, from ID surface on counterclockwise (CCW) side of the seam weld 58 Figure 48. EDS map of Mount M2 (MPI Indication 2) at crack shown in Figure 47, showing distribution of sulfur 58 Figure 49. EDS map of Mount M2 (MPI Indication 2) at crack shown in Figure 47, showing distribution Figure 50. Results of hardness measurements at various locations on Mount M5 (Figure 24) and Mount M6 (Figure 25). Mount M5 shown above; measurements performed at similar locations on Mount M6. 60 Figure 51. Results of hardness measurements taken at representative locations on Mount M3 (Figure 36), Mount M4 (Figure 37), and Mount M7 (Figure 35). Mount M3 shown above; measurements performed at . similar locations on Mount M4 and Mount M7 61 Figure 52. Results of hardness measurements at various locations on Mount 62 Figure 53. Results of hardness measurements at various locations on Mount M2. 63 Figure 54. Percent shear from Charpy V?notch tests as a function of temperature for transverse base metal specimens removed from the pipe joint that ruptured 64 Figure 55. Charpy V?notch impact energy as a function of temperature for transverse base metal specimens removed from the pipe joint that ruptured. 64 Figure 56. Percent shear from Charpy V-notch tests as a function of temperature for transverse seam weld (HAZ) specimens removed from the pipe joint that ruptured. 65 Figure 57. Charpy notch impact energy as a function of temperature for transverse seam weld (HAZ) specimens removed from the pipe joint that ruptured 65 DNV GL xii November 7, 2016 Shell Pipeline Company Metallurgical Analysis of May 20, 2016 Rupture on Tracy to Windmill Portion of San Pablo Bay Pipeline System List of Acronyms Battelle Drop Weight Tear Test CCW Counter Clockwise (orientation) CMFL Circumferential Magnetic Flux Leakage (tool) CP Cathodic Protection CVN Charpy V?Notch (impact testing) CW Clockwise (orientation) DSAW Double Submerged Arc?Welded (pipe) EDS Energy Dispersive Spectroscopy ERW Electric Resistance Welded (pipe) FATT Failure Appearance Transition Temperature FBE Fusion?Bonded Epoxy GW Girth Weld HAZ Heat Affected Zone HV Vickers Hardness ID Inside Diameter (surface) ILI In?Line Inspection MAOP Maximum Allowable Operating Pressure MPI Magnetic Particle Inspection OD Outside Diameter (surface) SEM Scanning Electron Microscope SMYS Specified Minimum Yield Strength SSC Sulfide Stress Cracking Upstream Ultrasonic Testing Crack Detection (tool) UTS Ultimate Tensile Strength wt Wall Thickness YS Yield Strength DNV GL November 7, 2016 Shell Pipeline Company Metallurgical Analysis of May 20, 2016 Rupture on Tracy to Windmill Portion of San Pablo Bay Pipeline System 1.0 BACKGROUND Shell Pipeline Company, LP (SPLC) retained Det Norske Veritas (U.S.A.), Inc. (DNV GL) to perform a metallurgical analysis of a rupture that occurred on the Tracy to Windmill portion of the San Pablo Bay Pipeline System. The failure occurred on May 20, 2015 in Tracy, California, approximately 4,068 feet from the nearest upstream pump station; the Tracy Pump Station. Tracy to Windmill is part of a 177.77 mile long segment of the San Pablo Bay Pipeline System consisting of 20?inch and 24?inch diameter pipe that originates at the Coalinga Station in Coalinga, CA and terminates at the Shell Martinez Refinery in Avon, CA. The Coalinga to Avon segment was originally installed in 1967.. In 1989, three portions, totaling 12.55 miles, of the pipeline were replaced with 24?inch diameter by 0.260 inch wall, API 5LX Grade X60 double submerged arc?welded (DSAW) line pipe manufactured by Armco Steel in Houston, TX. The Tracy to Windmill portion, which is where the failure occurred, consists of 3.05 miles of the 12.55 miles of Armco line pipe installed in 1989. Historical information indicates that the Armco line pipe used to construct the 12.55 miles of pipeline was stored for approximately 7years following manufacturing and then was shipped from the northeastern United States to Coalinga, California for construction. The 12.55 miles of the replaced pipeline were externally coated with a 3?layer coating, comprised of fusion?bonded epoxy (FBE) on the pipe surface, a mastic coating, and an external polyolefin wrap. The pipeline has an impressed current cathodic protection (CP) system. The pipeline operates in heavy crude service, with temperatures up to On the day of the failure, the maximum allowable operating pressure (MAOP) of the pipeline was 936 psig, which corresponds to 72.0% of the specified minimum yield strength (SMYS). The segment operated with aggressive pressure cycling in the period leading up to the failure. The pressure at the time and location of the failure was estimated to be 665 psig, which corresponds to 51.2% of SMYS. The most recent hydrostatic pressure test prior to the failure was performed in 1990. A minimum pressure of 1181 psig (90% of SMYS) was held for four hours. The most recent in?line inspections (ILIs), using a circumferential magnetic flux leakage (CMFL) tool and an ultrasonic testing crack detection tool, were performed on 12/03/2015 and 12/04/2015, reSpectively. No anomalies in the failed joint were reported in the CMFL final report issued on 03/07/2016 or in the final report issued on 05/02/2016. DNV GL OAPUS311MPHB (PP158491) 1 November 7, 2016 Shell Pipeline Company Metallurgical Analysis of May 20, 2016 Rupture on Tracy to Windmill Portion of San Pablo Bay Pipeline System A pipe section that contained the rupture was delivered to DNV GL for metallurgical analysis: . a 29.81 foot long pipe section that contains the 26.44 feet long failed joint, 1.58 feet of the upstream joint, and 1.79 feet of the joint. The objectives of the analysis were to determine the metallurgical cause of the failure and identify any contributing factors. 2.0 TECHNICAL APPROACH The procedures used in the analysis werein accordance with industry?accepted standards. Five of the general standards governing terminology, specific metallographic procedures, mechanical testing, and chemical analysis used are as follows: . ASTM E7, ?Standard Terminology Relating to Metallography.? . ASTM E3, ?Standard Methods of Preparation of Metallographic Specimens." . ASTM E8, ?Test Methods for Tension Testing of Metallic Materials." . ASTM E23, ?Standard Test Methods for Notched Bar Impact Testing of Metallic Materials.? - ASTM A751, ?Standard Test Methods, Practices, and Terminology for Chemical Analysis of Steel Products.? The following steps were performed for this analysis. The pipe section was visually inspected and photographed. Wall thicknesses and diameters were measured on the ends of the pipe section where coating was removed and there was no measurable corrosion. Remnant coating, which still adhered to the pipe, adjacent to the failure location, was removed. Magnetic particle inspection (MPI) was performed on the internal pipe surfaces at areas adjacent to the rupture location, as well as along the internal surface of the longitudinal seam welds associated with the pipe joints. No MPI was deemed necessary on the external pipe surfaces because the failure initiated from the inside. Prior to MP1, the regions examined were cleaned with a degreaser (PreSolve?). I The fracture surfaces were cleaned with a degreaser and optically examined, and photographed. The length and depths of a pre?existing flaw 0n the fracture surface were measured to produce a flaw profile. Fracture surface samples were removed from the suspected rupture origin on the clockwise (CW) fracture surface, cleaned with a degreaser and methanol, and examined at high magnifications in a scanning electron microscope (SEM) to document the fracture morphology. Transverse cross?sections were removed from two areas at the suspected rupture origin and from two linear indications identified approximately 2.7 feet and approximately 7.7 feet of the rupture origin by MPI. DNV GL OAPUS311MPHB (PP158491) 2 November 7, 2016 Shell Pipeline Company Metallurgical Analysis of May 20, 2016 Rupture on Tracy to Windmill Portion of San Pablo Bay Pipeline System In addition, transverse cross?sections were removed from the longitudinal seam weld of the ruptured joint and and joints at areas away from the rupture or other MPI indications. The cross?sections were mounted, polished, and etched; see Figure 1 for locations. Light photomicrographs were taken to document the fracture morphology and steel microstructure. SEM with energy dispersive spectroscopy (EDS) was performed on metallographically prepared cross?sections of the MPI?indications, to analyze for the presence of sulfur and other elements. Micro?hardness testing (Vickers 500 9 load) was performed on the metallographic mounts to determine hardness. Mechanical (duplicate tensile tests and full Charpy V?notch curves) testing was performed on specimens removed from the base metal and seam weld of the pipe joint that ruptured to determine the tensile and fracture toughness properties. The Charpy specimens across the seam weld were notched in the heat?affected zone (HAZ) of the same weld toe associated with the rupture. Mechanical (duplicate tensile tests) testing was also performed on specimens removed from the base metal of the and joints to determine tensile properties. Chemical analyses were performed on steel samples removed from the pipe joint that ruptured and the and joints to determine the compositions. calculations were performed to estimate the failure pressure of the pipe joint that ruptured based on the pipe geometry, measured mechanical properties, and the measured flaw profile.1 These values were compared with the calculated pressure at the failure location at the time of the failure. 3.0 RESULTS AND DISCUSSION 3.1 Optical Examination Figure 2 shows a photograph of the pipe section in the as?received condition. The pipe section was wrapped with plastic and duct tape, with the failure location facing up during transit. Figure 3 is a photograph of the pipe section near the rupture after removal of the protective wrappings. The pipe section was 29.81 feet in length and contained reference markings identifying flow direction and clock orientation.- It contained the 26.44 feet long failed joint, 1.58 feet of the joint, and 1.79 feet of the joint. A stencil on the external surface of the polyolefin wrap 24 OD .260? WT towards the end of the failed joint, suggests that the pipe section is comprised of 24?inch diameter by 0.260?inch wall line pipe steel with a longitudinal electric resistance 1 is a computer program developed by CC Technologies Systems, Inc., which is now Det Norske Veriias (USA). Inc., to evaluate crack-like flaws in pipelines based on inelastic fracture mechanics. DNV GL OAPUS311MPHB (PP158491) I 3 November 7, 2016 Shell Pipeline Company Metallurgical Analysis of May 20, 2016 Rupture on Tracy to Windmill Portion of San Pablo Bay Pipeline System welded (ERW) seam. However, the morphology of the longitudinal seam weld on the failed pipe section is consistent with a DSAW seam, not an ERW seam. Diameters and wall thicknesses were measured on the and ends of the pipe section and joints). The diameter measurements were made after locally removing the three-layer coating. The diameter of the joint was 24.2 inches between the 12 and 6 o?clock orientations, and 23.9 inches between 3 and 9 o?clock orientations, indicating some ovality. The diameters of the joint were both 24.1 inches, indicating no measurable ovality, as shown in Table 1. The diameters meet API 5LX tolerances2 for 24-inch nominal diameter pipe. Wall thicknesses were measured o?clock orientations at areas with negligible corrosion and no coating near the failure location, at the and ends of the failed joint, on the joint, and on the joint; see Table 2 for details. The wall thickness values ranged between 0.272 inches and 0.296 inches, with the exception of the area immediately adjacent to the failure at the 3 o?clock orientation, where the wall thickness was 0.251 inches due to local yielding (necking) at the rupture area. The average wall thickness of the ruptured joint, joint, and joint are 0.276 inches (excluding the failure area), 0.288 inches, and 0.282 inches, respectively. The average wall thickness values and the individual wall thickness values away from the rupture area meet API 5LX tolerances for a nominal wall thickness of 0.260 inches. Table 3 contains a summary listing of the various features found on the pipe section, as described further in the text below, together with the locations from which cross?section samples (?Mounts?) were prepared, as described in Sections 3.3 and 3.4. The rupture was 3.77 feet in length, consisting of a symmetric fish?mouth failure that initiated at or near the toe of the DSAW at the 3:26 o?clock orientation, on the clockwise (CW) side of the seam weld. The and ends of the rupture were located at 14.17 feet and 17.94 feet, respectively, from the GW as shown in Figure 3. The maximum opening was 4.5 inches (0.38 feet), approximately 16.13 feet from the GW. The crack path was relatively smooth in appearance, located at the toe of the DSAW for approximately 7 inches (15.88 16.46 feet from GW) of the rupture length, and then transitioning off of the toe in either direction, upstream and The coating on either side of the fracture, within 1?3 inches, was locally disbonded; however, the coating on the remaining portions of the pipe section was in good condition and well adhered to the pipe steel. There was no evidence of external corrosion along the areas of disbonded 2 API 5LX (23rd Ed., March 1980): "Out~of?Roundness. For pipe larger than 20 in., and for a distance of 4 in. (101.6 mm) from the ends of the pipe, the maximum outside diameter shall not be more than 1 per cent larger than speci?ed, and the minimum outside diameter shall not be more than 1 per cent smaller than Speci?ed." DNV GL OAPUS311MPHB (PP158491) 4 November 7, 2016 Shell Pipeline Company Metallurgical Analysis of May 20, 2016 Rupture on Tracy to Windmill Portion of San Pablo Bay Pipeline System coating, suggesting that the local disbondment was a result of plastic deformation of the pipe material during the rupture event. 3.2 Magnetic Particle Inspection The pipe section was cut longitudinally to facilitate examination of the internal surfaces and MP1 of the longitudinal seam welds of the failed joint and and D/S-joints. There was no evidence of internal corrosion. Two areas with indications were identified along the internal surface of the failed joint at the toe of the seam weld. A summary of the locations and dimensions of these indications is presented in Table 4. Area 1 included MPI Indication 1a (CW) and MPI Indication 1b (CCW), both located approximately 2.7 feet of the rupture origin (~18.8 feet from GW), see photograph in Figure 4. The indications appear as crack?like features along the toe of the seam weld. MPI Indication 1a appears as a crack?like feature between 18.62-19.05 feet from the GW, at the weld toe on the CW side of the seam weld. MPI Indication 1b also appears as a crack?like feature, and is located between 18.70?19.12 feet from the GW, at the weld toe on the CCW side of the seam weld. Two 3/8 inch long areas of weld overlap are also apparent 18.8 ft from the GW. Area 2 contains MPI Indication 2 (CW), located 7.7 feet of the rupture (23.83 feet from the GW), see photograph in Figure 5. The indication appears as a small (0.25 inch long) dimple of missing weld metal (undercut), resulting in a notch at the toe of the seam weld. 3.3 Fractographic Examination 3.3.1 Rupture Location Figure 6 is a photograph of the CW side of the fracture surface of the rupture before cleaning. A flaw originating from the pipe inside (ID) surface is evident on the fracture surface 15.88?16.46 ft from the GW. That area (CW side only) was cut out and cleaned .with a degreaser and methanol. Figure 7 shows a photo?collage of the suspected rupture origin after cleaning. The surface is dull and gray in color, with lighter areas near the internal surface. The pre-existing flaw at the ID surface has a semi?elliptical shape, with the suspected rupture origin located at approximately 16.13 ft from the WEB GW. The origin location was identified based on the overall flaw shape and fracture surface coloration. The fracture surface was categorized into three regions: Region 1 flat, lighter gray in appearance, located near the internal surface, and perpendicular to the internal and DNV GL OAPUS311MPHB (PP158491) 5 November 7, 2016 Shell Pipeline Company Metallurgical Analysis of May 20, 2016 Rupture on Tracy to Windmill Portion of San Pablo Bay Pipeline System external surfaces; Region 2 rough in texture, darker gray in appearance, located near mid?wall, and perpendicular to the internal and external surfaces; Region 3 rough in texture, darkest gray in appearance, located near the external surface, and at an oblique angle with respect to the internal and external surfaces. The pre?existing (prior to failure) flaw consists of Region 1 and Region 2. These three regions are shown in the optical photomicrograph in Figure 8, taken approximately 16.1 feet from the GW. Region 1 contains multiple crack fronts on various planes that are separated by ratchet marks3. This macro?scale morphology is consistent with multiple crack initiation sites. At higher magnification, Figure 9, small pits can be seen along the internal surface, possibly serving as crack initiation sites. These pits might have formed during the long storage period of the line pipe prior to construction or could have formed in service. Region 2 and Region 3 are macroscopically rougher than Region 1. The oblique angle of Region 3 with respect to the internal and external pipe surfaces is consistent with a shearlip, indicative of ductile overload. Except for the discoloration in the described regions, the fracture surface did not have distinct beach marks?, which are commonly associated with the growth of a fatigue crack. Figure 10 is an SEM image of an area of the fracture surface from within the suspected failure origin, approximately 16.1 feet from the GW. The orange dashed lines indicate the interfaces between Regions 1/Region 2, and Region Z/Region 3. Note the rough woody morphology of Region 2. Figure 11 is an SEM image of the fracture surface within Region 1. Large steps and cracks are visible parallel to the ID pipe surface. Figure 12 is a higher magnification SEM image of the fracture surface immediately adjacent to the ID pipe surface, where a pit of approximately 100 microns wide by 50 microns deep is visible, similar to the pits discussed in the optical photomicrograph in Figure 9. Figure 13 shows another high magnification SEM photomicrograph taken within Region 1 adjacent to the internal surface. The image shows fatigue striationsS that emanate from the internal surface. Figure 14 is an SEM image of the fracture surface within Region 2. A stair-stepped, ?woody? topography with little evidence of ductility was evident through much of Region 2, which can be indicative of 3 Ratchet marks: Macroscopic features that originate when multiple cracks, nucleated at different points, join together, creating steps on the fracture surface. 4 Beach marks: Macroscopic concentric marks that are a result of successive arrests or decrease in the rate of fatigue crack growth due to a temporary load drop, or due to an overload that introduces a compressive residual stress ?eld ahead of the crack tip. 5 Fatigue striations: Microscopic features (that may be) visible with the aid of a scanning electron microscope, resulting from the successive blunting and re?sharpening of the crack tip in ductile materials, and that appear as ?ne, parallel lines perpendicular to the direction of crack growth. DNV GL OAPUS311MPHB (PP158491) 6 November 7, 2016 Shell Pipeline Company Metallurgical Analysis of May 20, 2016 Rupture on Tracy to Windmill Portion of San Pablo Bay Pipeline System intermittent crack growth. Some secondary cracking is also visible, possibly related to the different microstructure of the weld HAZ near mid?wall, or related to an environmental effect on crack growth that caused crack branching. At higher magnification, the morphology consisted of bands of ductile overload separated by bands that exhibited little to no cohesion with the surrounding material, and secondary cracking; refer to Figure 15. Figure 16 and Figure 17 are SEM images confirming ductile overload failure in Region 3. Figure 18 and Figure 19 show detailed flaw depth measurements taken of Region 1 and Region 2 on the CW side fracture surface. Wall thickness measurements were also taken along the fracture surface, and the measurements ranged between 0.226 and 0.251 inches, showing that the metal in the rupture area yielded from its nominal wall thickness of 0.260 inches. Figure 20 is a plot of flaw depth versus distance from the GW. The measured flaw associated with Region 1 is indicated by the red line, while Region 2 is indicated by the green line. The figure shows that the pre?existing (prior to rupture) flaw length was approximately 7.0 inches, and that the maximum depth of Region 1 is 0.097 inches and the maximum depth of the combined flaw (Region 1 Region 2) is 0.210 inches; 37.3% and 80.8% of the 0.260 inches nominal wall thickness, respectively. 3.3.2 Testing for Sulfides and Carbonates Primary Fracture Surface Spot testing, using a 1M HCI solution, was performed on the CCW side of the fracture surface (no cleaning) to test for the presence of sulfides and carbonates. A color change from white to brown in lead?acetate test paper is a positive indicator of sulfides, while vigorous bubbling is a positive indicator for carbonates. The fracture surface tested positive for the presence of sulfides and negative for carbonates. The sulfides likely deposited on the fracture surface by a corrosion mechanism and might have played a role in the fatigue crack growth. The absence of carbonates indicates that C02 likely did not play a role in the corrosion process. 3.3.3 MPI Indications Prior to breaking open MPI Indication 1a, a piece was removed from its center for cross?section metallography (Mount 1), which is described later. After that, the remaining and portions of the pipe piece containing MPI Indication 1a were submerged in liquid nitrogen and struck with a brass mallet to break open the flaw for fractographic examination. The created fracture was not cleaned. Figure 21 is a photograph of the flaw that (after removing the metallographic section) measured approximately 4.25 inches in length. Figure 22 is a close?up view of the center portion of the flaw, showing the maximum depth is approximately 0.125 inches (48.1% of 0.260 inches nominal wall DNV GL OAPUS311MPHB (PP158491) 7 November 7, 2016 Shell Pipeline Company Metallurgical Analysis of May 20, 2016 Rupture on Tracy to Windmill Portion of San Pablo Bay Pipeline System thickness). The flaw has a dark appearance and a staggered fracture path on multiple parallel planes. Figure 23 is a close?up view of the flaw, which has two distinct colored regions, a black region (Region 1) adjacent to the pipe ID surface and a brown region (Region 2) near mid?wall. The black Region 1 is located adjacent to the internal surface and resembles Region 1 of the pre?existing flaw located at the rupture origin, as described above, with an overall relatively flat appearance and ratchet marks along the ID to indicate multiple initiation planes. White residue from the MPI testing is present in Region 1, indicating that the crack was open to the ID surface of the pipe prior to fracture. The brown Region 2 resembles Region 2, with a stair?stepped, ?woody? fracture appearance. Oily residue is present in both Regions A and B, showing that both regions were present during service when crude oil could leach in. MPI Indication 1b and MPI Indication 2 were not broken open, because the metallographic cross?sections showed no cracks were present, as will be discussed in Section 3.4.3. 3.3.4 Testing for Sulfides and Carbonates MPI Indication 1a Spot testing, using a 1M solution, was performed on the CCW side of the fracture surface (no cleaning) to test for the presence of sulfides and carbonates. The fracture surface tested positive for the presence of sulfides and negative for carbonates. 3.4 Metallographic Examination This section describes the observations from metallographic cross?section samples taken from the rupture origin location (Mount M5 and Mount M6), from reference locations (Mount M7, Mount M3, and Mount M4), and from MPI Indications (Mount M1 and Mount M2), as summarized in Table 6 and shown in Figure 1. 3.4.1 Rupture Origin Figure 24 and Figure 25 are photographs of transverse metallographic sections, (Mount M5 and Mount M6) that were removed from across the fracture surface at approximately 16.13 feet and 16.33 feet from the WEB GW, respectively. Mount M5 was removed from the likely rupture origin, and Mount M6 was removed 2.4 inches (0.2 feet) of the likely rupture origin. The locations are shown in Figure 1 and Figure 6. The morphology of the weld is consistent with DSAW with the final pass at the OD pipe surface. Figure 26 shows typical examples of the microstructures of the base metal (Figure 26a), the weld fusion metal near the ID surface (Figure 26b), the HAZ metal near the ID weld toe that failed (Figure 26c), and the HAZ metal near mid?wall (Figure 26d). The base metal consists DNV GL (PP158491) 8 November 7, 2016 Shell Pipeline Company Metallurgical Analysis of May 20, 2016 Rupture on Tracy to Windmill Portion of San Pablo Bay Pipeline System of equi?axed ferrite (white grains) and pearlite (black grains) and, within that structure, some rounded and elongated inclusions are present. This microstructure is consistent with the vintage and grade of the steel. The weld fusion metal of the weld bead at the ID pipe surface also has equi?axed grains, but contains visually more ferrite than the pipe base metal. The microstructure of the HAZ near the ID weld toe shows angular grain morphology, known as Widmanstatten structure. At the mid?wall of the pipe wall thickness, the HAZ consists of ferrite and pearlite with a finer grain size than the base metal. These microstructures are all typical of DSAW welds in carbon steel line pipe. Both mounts appear very similar, with the inside and outside weld passes located on the center of the bond line (not offset laterally6 from one another), and with the primary crack extending from the CW toe on the internal surface through the HAZ of the weld to the OD pipe surface near the weld toe. Note that the crack at the OD pipe surface in both mounts is at an oblique angle with respect to the pipe surface, which is consistent with final failure by ductile shear. In both mounts, the weld appears to be peaked or tented as a result of the approach angle between the CW and CCW plate edges; further discussion is provided in Section 3.4.6. Figure 27 and Figure 28 are montages of photomicrographs showing the cross?section through the fracture surfaces on the CW side of the seam weld of Mount M5 (failure origin) and Mount M6, respectively. Mount M6 revealed similar features as Mount M5, and is therefore not separately discussed further here. Both cross?sections show that the fracture plane is radial7 through 70%-80% of the wall thickness and then transitions to a 45 degrees angle near the OD pipe surface. The 45 degree angle is consistent with a shear lip, associated with ductile overload, and correlates with Region 3 previously defined above. Region 2 is rougher than Region 1 or Region 3 and some secondary cracks are present in Region 2. As mentioned earlier, crack branching at the pipe mid?wall (rougher Region 2) may be a result of microstructural differences in the weld and/or an environmental effect. Figure 29 is a photomicrograph showing the location of fracture initiation at the immediate edge of the internal weld bead and the HAZ. The fracture path is straight, consistent with fatigue identified in Region 1 in the SEM examination. Figure 30 is a photomicrograph showing the rough fracture path consistent with the step? wise characteristics of Region 2 identified during the SEM examination. Secondary cracks are present along the fracture surface in this region. The secondary cracks are relatively straight. 6 "Out~of line weld bead (off-seam weld) shall not be cause for rejection provided complete penetration and complete fusion have been achieved as indicated by nondestructive examination.? API 5LX, 23rd Edition, 1980. 7 Approximately perpendicular to the pipe walls. DNV GL OAPUS311MPHB (PP158491) 9 November 7, 2016 Shell Pipeline Company Metallurgical Analysis of May 20, 2016 Rupture on Tracy to Windmill Portion of San Pablo Bay Pipeline System Figure 31 is a photomicrograph'from the area identified as Region 3, showing elongated and deformed grains in the 45 degree plane, which is consistent with shear ductile overload. Figure 32 shows photomicrographs in the as?polished and as?etched conditions of an area on the ID surface of Mount M5, in the base metal away from the rupture area. A micro?pit (100?200 micron size) filled with corrosion product is visible. This particular corrosion product was not analyzed for composition, but EDS analyses of other scales indicate it is likely a compound; refer to Section 3.4.4. This image is a typical example of several micro?pits that were observed in the cross?sections. No cracking was associated with this or other micro-pits visible in the base metal areas of the cross-sections. Figure 33 is a montage of photomicrographs of the CCW side of the weld in Mount M6 (opposite side of the weld at the rupture location). A small crack is apparent from the weld toe into the HAZ. Two similar cracks are present at the toe of the seam weld on the CCW side in Mount M5, and Figure 34 shows photographs of these cracks in the as?polished and as?etched conditions. The cracks in Mounts M5 and M6 are approximately 200 microns deep, which is consistent with them being continuous along the seam weld and being only 2.4 inches apart. The cracks originate from the pipe ID surface, each in an area with a micro?pit that is filled with corrosion product. As previously discussed, these pits might have formed during the long storage period of the line pipe prior to construction or could have formed in service. Both cracks are branched and have a transgranular crack path into the HAZ. The presence of corrosion products and crack branching are characteristics that may be associated with an environmental degradation mechanism. 3.4.2 Reference Locations Metallurgical cross-sections were removed from across the seam weld of the failed pipe joint (away from the rupture; Mount M7), the joint (Mount M4), the joint (Mount M3). Photographs of the mounted cross-sections are presented in Figure 35, Figure 36, and Figure 37, respectively. There was no evidence of cracking in the welds or base metal in any of these reference mounts. 3.4.3 MPI Indications Figure 38 and Figure 39 are photographs of the metallographic cross?sections, Mount M1 and Mount M2, respectively, removed from the locations marked in Figure 4 (MP1 Indications la/lb and Figure 5 (MP1 Indication 2). Figure 40 is a photomicrograph of the area associated with MP1 Indication 1a. At this location, a crack from the ID pipe surface, at the CW side of the seam weld, is present with DNV GL OAPUS311MPHB (PP158491) 10 November 7, 2016 Shell Pipeline Company Metallurgical Analysis of May 20,2016 Rupture on Tracy to Windmill Portion of San Pablo Bay Pipeline System a depth of approximately 0.119 inches (45.8% of 0.260 inches nominal wall thickness). The crack path close to the ID surface is straight without crack branching (refer back to Region 1 in Figure 23), and, further into the metal, transitions to a tortuous path where crack branching is apparent (refer back to Region 2 in Figure 23). Figure 41 shows a higher magnification photomicrograph of the crack tip, where extensive crack branching is apparent in the fine?grain microstructure of the HAZ. The inset photo in this figure shows a close?up view of the transgranular morphology (red circles) at the crack tip. Figure 42 is a photomicrograph of the area associated with MP1 Indication 1b. At this location, weld overlap is apparent. The filler metal of the weld bead extends approximately 3 mm (3000 microns) over the pipe ID surface on the CCW side of the seam weld. While the overlap creates a sharp transition at the weld toe, no cracking is apparent at? the tip of that transition. Figure 43 is a montage of photomicrographs of the area associate with MPI Indication 2. A notch of approximately 0.060 inches depth (23.1% of 0.260 inches) nominal wall thickness) is present where weld undercut has occurred. Figure 44 shows photomicrographs, in the as?polished and as?etched condition, of a 0.012 inches deep crack of 0.260 inches nominal wall thickness) that initiated from this notch. Similar to the cracks found at the seam weld toe on the CCW side of Mount M5 and Mount M6 at the rupture location, the crack at MPI Indication 2 initiated from a micro?pit that is filled with corrosion product (which was not removed during the cleaning process of the. sample preparation). The crack morphology is transgranular and branching that extends into the HAZ microstructure suggests an environmental damage mechanism. 3.4.4 EDS Analysis of Cracks and Corrosion Products Scanning electron microscopy with EDS was performed on the metallographically prepared cross?sections of the crack associated with MPI Indication 1a (Mount M1) and the crack and pit with corrosion products associated with MPI Indication 2 (Mount M2), to analyze for the presence of sulfur and other elements. Figure 45 shows a composition image of the crack tip associated with MPI Indication 1a, where the green color indicates areas where sulfur was detected. In this figure, approximately one?third of the crack depth is visible. The imaged crack tip is approximately 0.043 inches (1100 microns) of the overall crack depth of 0.119 inches. On Mount M1, no EDS analysis was performed in the area of the crack mouth near the inside pipe surface. DNV GL OAPUS311MPHB (PP158491) 11 November 7, 2016 Shell Pipeline Company Metallurgical Analysis of May 20, 2016 Rupture on Tracy to Windmill Portion of San Pablo Bay Pipeline System Figure 46 shows EDS elemental maps for the elements iron oxygen (0), manganese sulfur (S), silicon and carbon (C). These images reveal that oxygen~ and sulfur? containing corrosion products are present within the crackthe crack. The likely source of the elements sulfur and oxygen is the crude oil in the pipeline. Other detected sulfur within the HAZ metal coincides with inclusions visible in the cross? section and also with manganese in the elemental maps, thus indicating that those inclusions are most likely compounds. Figure 47 shows the locations where EDS analyses were performed of the corrosion product and base metal at the ID surface of MPI Indication 2. The results are summarized in Table 5, revealing that the corrosion product has high concentrations of sulfur (27?32 some oxygen with the balance predominantly iron (55?65 (EDS EDS and EDS when compared with the base metal Figure 48 shows a composition image and Figure 49 shows EDS elemental maps of the corrosion?filled pit at the notch and the crack located at the CCW toe of the weld at the ID pipe surface. Sulfur was detected in the corrosion product, inside the crack along the entire crack path, and inclusions were located within the metal. As with the previous MPI indication, the presence of sulfur suggests an environmental component to the damage mechanism. 3.4.5 Hardness Testing Vickers micro?hardness testing was performed, using a 500 load, on Mounts M5 and M6 (rupture), Mounts M3, M4 and M7 and failed joints), Mount M1 (MPI Indications 1a/1b) and Mount M2 (MPI Indication 2). The test locations and results are summarized in Figure 50, in Figure 51, Figure 52, and Figure 53, respectively. For the ruptured area of the failed joint, the hardnesses in the HAZ on the CW side of the seam weld, adjacent to Region 1 and Region 2 (Locations 1, 2, 3, 4, 5, 8) were measured. The hardness values ranged between 190.3 and 218.1 HV (Mount M5) and 183.4 and 218.8 HV (Mount M6). The maximum hardness measured was in the base metal of Mount M5, 227.8 HV. 225.0 HV (HAZ in Mount M7), 235.1 HV (weld metal, Mount M4), 213.5 HV (weld metal, Mount M3), were the maximum values measured for the three joints. The range of hardness measured on the failed side of the weld was very similar to those measured on the unfailed side of the weld. The hardness values measured on the unfailed welds were similar to those measured in the failed welds. The hardness values near the DNV GL OAPUS311MPHB (PP158491) 12 November 7, 2016 Shell Pipeline Company Metallurgical Analysis of May 20, 2016 Rupture on Tracy to Windmill Portion of San Pablo Bay Pipeline System MPI Indications were similar to those in weld areas without MPI Indications. All these observations show that hardness was not a contributing factor to the failure. International standards8 provide guidance for the application of materials exposed to service conditions that promote sulfide stress cracking (SSC). All of the measured values are less than the maximum allowable hardness of 250 HV for weld roots, base metal, and HAZ. Therefore, any environmental component to crack growth is more likely related to corrosion fatigue than SSC. 3.4.6 DSAW Measurements The cross?sections removed from the ruptured joint exhibited a more peaked appearance than those in the and joints. This is a local discontinuity to the roundness of the pipe that can not only affect how the sensors of an ILI tool contact the pipe, but also how stresSes in the pipe developwhen it is pressurized. Under normal operation, the internal pressure of the pipe will strain the pipe to a rounded condition, generating an additional tensile bending stress at the internal surface. This, in combination with the geometry of the weld toe, can produce locally high stresses. Measurements were made on Mounts to quantify the angle between the plate edges on the CW and CCW sides of the seam weld. The lower the angle (farther away from the ideal 180?), the higher the tensile bending stress when the pipe is pressurized. The results are summarized in Table 6, with additional photographs provided in Appendix A. To visualize any peaking at the weld, the inside and outside pipe diameters for a perfectly round cylinder are drawn in the Figures A1 through A7. API SLX (1980) does not include requirements for the allowable angle between plate edges. To estimate the original geometry for Mount M5 and Mount M6 prior to rupture, the CW fracture surface for each mount was rotated until the fatigue regions (Region 1) of the mating faces were parallel. The angles measured on the failed joint ranged between 161 degrees at the rupture origin (Mount M5) and 165'degrees at MPI Indication 2 (Mount M2) with the other mounts having values in between. The angle at the reference locations on the adjacent joints was higher with 167 degrees on the joint (Mount M3), and 169 degrees on the joint (Mount M4). 8 ANSIKNACE MR0175IISO 15156-22015, Petroleum. petrochemical and natural gas industries ?iViaterials for use in HZS-containing environments in oil and gas production Part 2: Cracking-resistant carbon and low-alloy steels, and the use of cast irons. oNv GL (PP158491) 13 November 7, 2016 Shell Pipeline Company . Metallurgical Analysis of May 20, 2016 Rupture on Tracy to Windmill Portion of San Pablo Bay Pipeline System 3.5 Mechanical Testing The results of tensile testing of duplicate, transverse base metal and seam weld speCimens removed from the pipe joint that ruptured are shown in Table 7. The average yield strength (YS) and ultimate tensile strength (UTS) of the base metal were 70.3 ksi and 87.8 ksi, respectively. The average YS and UTS of the base metal samples meet the minimum YS and UTS requirements for API 5LX Grade X60 linepipe steel of 60.0 ksi and 75.0 ksi, respectively.9 The average UTS of duplicate transverse samples removed from the longitudinal seam weld was 85.7 ksi, which exceeds the minimum UTS requirement for API 5LX Grade X60 line pipe steel of 75.0 ksi. YS values across welds are not specified in API 5LX. The results of tensile testing of transverse base metal specimens removed from the and joints are shown in Table 8. The specimens meet the minimum YS and UTS requirements for API 5LX Grade X60 line pipe steel of 60 ksi and 75.0 ksi, respectively. Table 9 and Table 10 summarize the results of the Charpy testing for the transverse base metal and seam weld samples removed from the failure joint while Figure 54 through Figure 57 show the Charpy percent shear and impact energy curves. An analysis of the data for the base metal specimens indicates that the 85% fracture appearance transition temperature (FATT) is and the upper shelf Charpy energy is full size. These results are typical for this vintage and grade of line pipe steel. The CVN test results can be adjusted to determine the 85% FATT that would be expected for full?scale pipe by applying temperature shifts to the data. This method (full?scale) adjusts the 85% obtained from the Charpy tests to a predicted from the Battelle Drop?Weight Tear Test The predicted 85% from the test most closely represents the expected FATT for full-scale pipe wall material.10 The full?scale brittle to ductile transition temperatures for the samples, based on a nominal pipe wall thickness of 0.260 inches, are shown in'TabIe 11. The base metal is expected to exhibit ductile fracture behavior above Similarly, the data for the seam weld (HAZ) specimens indicates that the 85% FATT is and the upper shelf Charpy energy is 34.0 ft-Ibs, full size. The seam weld (HAZ) is expected to exhibit ductile fracture behavior above refer to Table 11. 9 API 51.x. 23rd Edition, 1980. 10 W. A. Maxey, J. F. Kiefner, R. J. Eiber. Brittle Fracture Arrest in Gas Pipelines,? Report No. 135, AGA. Catalog No. L51436. April 1983, Battelle Columbus Laboratories. 11 Rosenfeld, M.J., Simple Procedure for Charpy impact Energy Transition Curves from Limited Teleata,?lnternational Pipeline Conference, Volume 1, ASME, 1996, Equation 1. DNV GL (PP158491) 14 November 7, 2016 Shell Pipeline Company Metallurgical Analysis of May 20, 2016 Rupture on Tracy to Windmill Portion of San Pablo Bay Pipeline System 3.6 Chemical Analysis The results of the chemical analysis performed on samples removed from the pipe joint that ruptured and the and joints are shown in Table 12. All three joints meet the composition requirements for API 5LX Grade X60 for this vintage. 3.7 Failure Pressure Analysis was used to estimate the failure pressure for the following cases: . Case 1: Measured mechanical base?metal properties, measured pipe dimensions, and the as?measured flaw profile of Region 1 (Fatigue). . Case 2: Measured mechanical base?metal properties, measured pipe dimensions, and the as-measured flaw profile of Region 1 (Fatigue) Region 2 (Possible Environmental Cracking). . Case 3: Measured mechanical HAZ properties, measured dimensions, and the as?measured flaw profile of Region 1 (Fatigue). . Case 4: Measured mechanical HAZ properties, measured dimensions, and the as?measured flaw profile of Region 1 (Fatigue) Region 2 (Possible Environmental Cracking). The results of the analyses are shown in Table 13. The calculated failure pressure, incorporating the base?metal properties, for Case 1 and Case 2 are 1413 psig and 658 psig, respectively. Similar results were obtained using the mechanical properties of the HAZ, which resulted in calculated failure pressures of 1394 psig and 664 psig for Case 3 and Case 4, respectively. Additional details of the analyses, and a description of are summarized in Appendix B. Using the provided discharge pressure at Tracy pump station (694 psig) and suction pressure at Marsh Creek pump station (364.6 psig) at the time of failure, the pressure at the failure location was calculated from provided elevation data.- The elevation of the failure location was estimated to be 365 feet, resulting in a calculated pressure of 665 psig.12 By incorporating the flaw profile of RegionZ (Case2 and Case 4), the estimated failure pressure is in good agreement with the calculated pressure at the location and time of failure. 12 Stationing data was not available, so the failure location was estimated to be 0.5 miles of the Tracy pump station. DNV GL OAPUS311MPHB (PP158491) 15 November 7, 2016 Shell Pipeline Company Metallurgical Analysis of May 20, 2016 Rupture on Tracy to Windmill Portion of San Pablo Bay Pipeline System 4.0 CONCLUSIONS The results of the metallurgical analysis indicate that the pipe joint ruptured at a fatigue crack that initiated at the toe of the DSAW seam weld on the inside surface of the pipe. Likely contributing factors include the peaked geometry of the failed pipe joint at the seam weld that introduced a bending stress, corrosion micro-pits on the ID surface that provided initiation sites, aggressive pressure cycling of the pipeline, and possibly an environmental effect on crack growth. The fatigue crack initiation and propagation most likely occurred while in service. However, transit fatigue during transportation of the pipe cannot be ruled out as a contributing factor. Shell reported to have records of rail transportation per API for the first portion of the journey, from Houston Texas to the northeast of the U.S. For the second portion of the journey, from the northeast to Coalinga California, verbal information indicates that API 5L1 would have been specified per industry norms, but written records have not been located. Summary of observations: . The?pipe joint that ruptured contained several types of mill anomalies at the long seam weld, including peaking, weld overlap?, and weld undercut?. . The fatigue crack at the rupture origin was 6.96 inches long and initiated from small (50-100 micron) pits along the internal toe of the DSAW. There was no evidence of a pre-existing weld?type defect at this location. The long-seam weld was located at the 3:26 o?clock orientation. . The fracture surfaces consisted of three regions: Region 1 a crack region at the internal surface with a maximum depth of 0.097 inches (37.3% of 0.260 inches nominal wall thickness) caused by fatigue; 0 Region 2 a crack region with a stair?stepped appearance, beginning at the end of Region 1, resulting from higher stress intensity factor at the crack tip as the crack propagated deeper into the material and possibly an environmental component. The maximum depth of this region is 0.210 inches (80.8% of 0.260 inches nominal wall thickness); 0 Region 3 the remaining ligament that overloaded during the rupture event. . MPI testing revealed other crack?like flaws on the pipe joint that failed, at approximately 2.7 feet and 7.7 feet of the rupture origin along the internal 13 RP 5L1, Recommended Practice for Railroad Transportation of Line Pipe. 14 Weld overlap is an imperfectiOn at the toe or root of a weld caused by metal flowing onto the surface of the parent metal without fusing to it. it may occur in both fillet and butt welds. 15 Weld undercut is an irregular groove at the toe of a weld run in the parent metal. A common cause of undercut is - a wide spreading arc (high are voltage) with insuf?cient fill (low current or high travel speed). DNV GL OAPUS311MPHB (PP158491) 16 November 7, 2016 Shell Pipeline Company Metallurgical Analysis of May 20, 2016 Rupture on Tracy to Windmill Portion of San Pablo Bay Pipeline System surface of the DSAW. The largest feature (MPI Indication 1a) was 4.25 inches in length and 0.125 inches depth (48.1% of 0.260 inches nominal wall thickness) at the deepest location. . Qualitative spot testing indicated the presence of sulfides on the fracture surface at the failure origin, which is not uncommon in crude oil pipelines. . Cross?sections showed that cracks at weld toes at locations away from the rupture were filled with sulfur?containing products, which is not uncommon in crude oil pipelines. . There was no evidence of external corrosion on the pipe section. . No MP1 indications were identified on portions of the longitudinal seam weld of the or joints that were examined; 1.58 feet of the joint and 1.79 feet of the joint. . The tensile properties of the failed joint and the joints and of the failed joint meet the tensile requirements for API 5LX Grade X60 line pipe steel for the estimated vintage of the pipe (1980). . The Charpy V-notch (CVN) properties of the base metal of the failed joint are typical for the vintage and grade of line pipe steel. The seam weld HAZ had better fracture toughness properties than the base metal, with a higher upper shelf impact energy and lower 85% FATT temperature. . The composition of the base metal of the failed joint and the joints and of the failed joint meets requirements for API 5LX Grade X60 line pipe steel for the estimated vintage of the pipe (1980). . The microstructures of the pipe joints are typical for the vintage and grade of line pipe steel. . The estimated failure pressure using mechanical properties of the heat affected zone and the flaw profile that ruptured for Region 1 Region 2 is 664 psig, which is close to the calculated pressure at the failure location and time of failure (665 psig). OAPUS311MPHB (PP158491) 17 November 7, 2016 Shell Pipeline Company Metallurgical Analysis of May 20, 2016 Rupture on Tracy to Windmill Portion of San Pablo Bay Pipeline System 1 Measurements taken near Mount M5 location, CCW side of the seam weld. 2 Measurement average near Mount M2 and Mount M7, CCW side of the seam weld. 3 Average not applicable, because of yielding near rupture opening. 4 This is 1.58 feet of the end of the joint. Table 1. Results of diameter measurements performed on the and joints, adjacent to the failed pipe joint. Diameter (inches) Location 12 to 6 3 to 9 o?clock 1 o?clock 1 end of Joint 24.2 23.9 end of Joint 24.1 24.1 1 Measurements exclude coating thickness. Table 2. Results of wall thickness measurements performed on the and failed pipe joints in areas with negligible corrosion and no coating. Wall Thickness (inches) Near Failure UIS End of Location in DIS End of O?clock U13 End 0; Ruptured Ruptured Ruptured DIS End of Orientations UIS Joint Joint Joint Joint DIS Joint 12:00 0.279 0.277 0.278 0.278 0.295 3:00 0.296 0.274 0.251 1 0.273 2 0.295 6:00 0.289 0.272 0.278 0.278 0.267 9:00 0.289 0.273 0.276 0.276 0.272 Average 0.288 0.274 3 0.276 0.282 DNV GL OAPUS311MPHB (PP158491) November 7, 2016 18 Shell Pipeline Company Metallurgical Analysis of May 20, 2016 Rupture on Tracy to Windmill Portion of San Pablo Bay Pipeline System Table 3. received pipe section. Distance from UIS GW Location Cross-Section (feet) End of UIS Pipe Section -1.58 UIS Girth Weld 0.00 UIS Joint Mount M4 -1.54 UIS End of Rupture Opening 14.17 UIS End of Pre?Existing lD Flaw 15.88 Section through Rupture Origin Mount M5 1613 Section through Rupture Mount M6 16.33 DIS End of Pre-Existing ID Flaw 16.46 DIS End of Rupture Opening 17.94 End of MPI Indication 1a (CW) 18.62 UIS End of MPI Indication 1b (COW) 18.70 Section through MP1 1a and 1b Mount M1 18.81 DIS End of MPI Indication 1a (CW) 19.05 DIS End of MPI Indication 1b (COW) 19.12 Failed Joint. Away from Rupture Mount M7 21.16 MPI Indication 2 Mount M2 23.83 DIS Girth Weld 26.44 DIS Joint Mount M3 28.19 End of DIS Pipe Section 28.23 Summary of locations of metallurgical mounts and other features on the DNV GL OAPUS311MPHB (PP158491) November 7, 2016 19 Shell Pipeline Company Metallurgical Analysis of May 20, 2016 Rupture on Tracy to Windmill Portion of San Pablo Bay Pipeline System Table 4. surface of failed joint by magnetic particle inspection. Summary of the locations and dimensions of indications identified on the internal Distance 2 Axial from UIS GW Length O?clock Depth 1 Indication (feet) (inches) Orientation (inches) Indication 1a 0 119 Crack-like indication on lD surface. 18.62 5.6 3:26 Crack at CW side At HAZ on CW side of seam weld Indication 1b 0 000 Crack?like indication With weld 18.70 035 3:26 No crack under overlap on 1D surface. At HAZ on CCW side of seam weld overlap indication 2 OHOBO Notch (weld undercut) on ID surface. 23.83 0.02 3:26 0% Gaff? At HAZ on CW side of seam Crack from notch Measurements made on metallographic cross?sections. 2 Distance indicates end of the indication. Table 5. Results of EDS analyses (in performed on corrosion products remaining within corrosion pits at weld toe on the internal pipe surface of Mount M2. Refer to Figure 47 for analysis locations. Spectrum EDS #Carbon (C) Oxygen (O) 8 11.4 7 5.4 Sodium (Na) Aluminum (Al) 0.?l Silicon (Si) 0.1 0.4 "0.1 0.5 Phosphorous (P) 0.1 Sulfur (S) 32.3 31.6 27.0 0.1 Calcium (Ca) 0.2 0.3 0.2 0.1 Chromium (Cr) 0.1 Manganese (Mn) 0.6 0.4 0.9 Copper (Cu 0.2 iron (Fe) 59.4 55.7 65.3 91 DNV GL OAPUS311MPHB (PP158491) November 7, 2016 20 Shell Pipeline Company Metallurgical Analysis of May 20, 2016 Rupture on Tracy to Windmill Portion of San Pablo Bay Pipeline System Table 6. Results of measurements performed on Mounts to determine the angle between the plate edges on the CCW and CW sides of the seam weld. Refer to Appendix A for additional details. Angle Between CW and CCW Sides Mount N9 Location (Degrees) Mount M1 MPI indications 1a/1b 162 Mount M2 MPI indication 2 165 Mount M3 DIS Joint 167 Mount M4 Joint - 169 Mount M5 Section Through Rupture Origin 161 Mount M6 Section Through Rupture 163 Mount M7 Failed Joint, Away from Rupture 165 DNV GL OAPUS311MPHB (PP158491) 21 November 7, 2016 . i Shell Pipeline Company Metallurgical Analysis of May 20, 2016 Rupture on Tracy to Windmill Portion of San Pablo Bay Pipeline System Results of tensile tests performed on transverse base metal and weld (HAZ) Table 7. specimens from the joint that ruptured compared with requirements for API 5LX Grade X60 line pipe steel.2 API 5LX Grade X60 Base Metal Seam Weld (Minimum Values) 2 Yield Strength, kSi 1 70.3 60.0 Tensile Strength, kSi 1 87.8 85. 7 75.0 Elongation in 2 incheS, 1 26.0 20.6 Reduction of Area, 1 33.7 32. 7 1 Average of duplicate tests. 2 API 5LX, 23rd Edition, 1980. Table 8. Results of tensile tests performed on transverse base metal specimens from the and joints compared with requirements for API 5LX Grade X60 line pipe steel.2 5LX UIS Base DIS Base Grade X50 2 Metal Metal (Minimum Values) Yield Strength, kSi 1 77. 7 71.2 60. 0 Tensile Strength, ksi1 95.6 86.8 75.0 Elongation in 2 inches, 1 22.7 27.2 20.6 Reduction ofArea, 1 29.1 33.3 _1 Average of duplicate tests. 2 API 5LX, 23rd Edition, 1980. DNV GL OAPUS311MPHB (PP158491) November 7, 2016 22 Shell Pipeline Company Metallurgical Analysis of May 20, 2016 Rupture on Tracy to Windmill Portion of San Pablo Bay Pipeline System Table 9. Results of Charpy V?notch impact tests performed on transverse base metal specimens removed from the joint that ruptured. Sub-Size Full Size Lateral Sample Temperature, impact Energy, impact Energy, Shear, Expansion, ID ft-lbs ft-Ibs inches A-10 ?60 6 11 5 0.006 A-6 -45 5 9 10 0.011 ?30 7 12 35 0.012 A-5 ?20 7 12 35 0.017 A-8 ~10 7 12 35 0.013 11 19 80 0.020 A-4 5 15 26 90 0.028 30 16 28 95 0.031 A-2 55 20 35 100 0.034 A-1 80 18 32 100 0.034 Table 10. Results of Charpy V?notch impact tests performed on transverse seam weld (HAZ) specimens removed from the joint that ruptured. Sub-Size Full Size Lateral Sample Temperature, Impact Energy, impact Energy, Shear, Expansion, ID ft-lbs ft-lbs inches ?100 6 12 0 0.012 8?9 ?80 6 11 5 0.011 8-8 ?60 12 24 95 0.029 6-6 -45 14 28 95 0.026 8?7 -30 15 30 100 0.028 8?5 ~20 15 30 100 0.027 8-4 5 15 30 100 0.027 8?3 30 17 33 100 0.029 8?2 55 16 32- 100 0.035 8-1 80 18 36 100 0.037 DNV GL OAPUS311MPHB (PP158491) November 7, 2016 23 . i Shell Pipeline Company Metallurgical Analysis of May 20, 2016 Rupture on Tracy to Windmill Portion of San Pablo Bay Pipeline System Table 11. Results of analyses of the Charpy V?notch impact energy and percent shear plots for base metal and seam weld (HA2) specimens removed from the joint that ruptured. Base Metal Seam Weld (HA2) Upper Shelf Impact Energy (Full Size), Ft?Ibs 31.7 34.0 85% FATT, 10.8 -82.1 85% FATT, (Full Scale Pipe) 1 0.2 ?63.6 1 Full Scale Pipe 85% where tW pipe wall thickness and tc width of the CVN specimen. DNV GL OAPUS311MPHB (PP158491) 24 November 7, 2016 Shell Pipeline Company Metallurgical Analysis of May 20, 2016 Rupture on Tracy to Windmill Portion of San Pablo Bay Pipeline System Table 12. Results of chemical analyses performed on samples removed from the joint that ruptured and the and joints compared with composition requirements for API 5LX Grade X60 line pipe steel.1 Composition, 5LX Joint That Composition, Composition, Grade X60 Ruptured Uls Joint DIS Joint Spec 1 Element (Wt. (Wt. (Wt. oAl) (Wt. (Carbon) 0.158 0.174 0.150 0.29 (max) Mn (Manganese) 1.23 1.40 1.32 1.45 (max) (Phosphorus) 0.010 0.024 0.008 0.05 (max) (Sulfur) 0.019 0.017 0.017 0.06 (max) Si (Silicon) 0.028 0.047 0.030 Cu (Copper) 0.110 0.075 0.107 Sn (Tin) 0.005 0.004 0.005 Ni (Nickel) 0.118 0.195 0.093 Cr (Chromium) 0.135 0.148 0.097 Mo (Molybdenum) 0.045 0.050 0.049 AI (Aluminum) 0.001 0.001 0.001 (Vanadium) 0.024 0-025 0.028 0.01 (min)* Nb (Niobium) 0.020 0.028 0.025 0.005 (min)* Zr (Zirconium) 0.002 0.002 0.002 Ti (Titanium) 0.001 0.001 0.001 0.02 (min)* (Boron) 0.0003 0.0003 0.0003 Ca (Calcium) 0.0005 0.0005 0.0005 Co (Cobalt) 0.009 0.009 0.008 Fe (Iron) Balance Balance Balance Balance Carbon Equivalent, ca?,2 0.42 0.47 0.43 1 Product Analysis per API 5LX, 23rd Edition, 1980, for welded, non?expanded or cold? expanded Grade X60 pipe. 2 CE11W (Mn/6) Either niobium, vanadium, or titanium, or a combination thereof, shall be used at the discretion of the manufacturer. DNV GL OAPUS311MPHB (PP158491) November 7, 2016 25 Shell Pipeline Company Metallurgical Analysis of May 20, 2016 Rupture on Tracy to Windmill Portion of San Pablo Bay Pipeline System Table 13. Results of failure pressure analyses using The pressure at the failure site was estimated to be 665 psig. Estimated Measured Failure Pressure Case N9 Flaw Profile Properties (psig) 1 Equivalent Flaw (Region 1) Base Metal 1413 1 2 Equivalent Flaw (Region 1+Region 2) Base Metal 658 1 3 Equivalent Flaw (Region 1) HAZ 1394 1 4 Equivalent Flaw (Region 1+ Region 2) HAZ 664 1 1? Fracture Toughness failure criterion DNV GL - onpussunpas (PP158491) 26 November 7, 2016 EU, 6 Rupture on Tracy to Windmill Portion of San Pablo Bay Pipeline System Flow 1 Mount M1 . and break open Mount M2 . rm '1 Mount 3:26 orientation :cw+ E6 Seam - I I I indication 3 :Rupture i at 23.83 ft (3 :Opening ?r . - :1 I I Coupon removed. . . . ?animation @333 a: ount M3 egg I 2 3t 14.17 17.94 26.44 28.23 1 P4 5 14.17 feet Rupture 3.77 ft 8.50 feet 1.79 feet Whole Pipe Section 29.81 feet Distance to GW (feet) of Pipe Section showing the location of the rupture, MPI indications, and where samples were removed nical testing, chemistry, and metallography (Mounts M1, M2, M3, M4, M5, M6, M7). 28491) 27 10. Rupture on Tracy to Windmill Portion of San Pablo Bay Pipeline System 8491) 28 20 .6 Rupture on Tracy to Windmill Portion of San Pablo Bay Pipeline System I i . . Whole pipe section 29.81 ft . 17.94 ft From GW I Iv; ms of Pipe Section showing the rupture location following removal of the protective plastic wrappings. i8491) 29 20. .6 Rupture on Tracy to Windmill Portion of San Pablo Bay Pipeline System .. Lii"l I . ?~1th A "Seam Weld? MPI Indication 1a (CW) 1905? Mount M1 I . - . . ah. the internal pipe surface showing MPI Indication 1a and MP1 Indication 1b along the clockwise iterclockwise (CCW) side of the seam weld, approximately 2.7 feet of the rupture 18.62 19.12 ft from GW), and location where Mount M1 was removed. :8491) 3o 20i 6 Rupture on Tracy to Windmill Portion of San Pablo Bay Pipeline System Seam Weld- . MPI Indication 2 (CW) Moont M2 ihl. .?he internal pipe surface showing MPI Indication 2 along the clockwise (CW) side of the seam weld, 3th., 7.7 feet of the rupture location (23.83 ft from GW), and location where was removed. 8491) 31 IO, 6 Rupture on Tracy to Windmill Portion of San Pablo Bay Pipeline System I MountIMS .-- .- '72' h? . -. Flaw end at 16.46? lh of the fracture surface (clockwise side) at the suspected rupture origin before cleaning. Light gray a?existing flaw that initiated from the pipe inside surface. Figure 10 Figure 8 - 1.0 inches age of the fracture surface (clockwise side) at the suspected rupture origin after cleaning in a degreaser anol. Light gray area is the pre?existing flaw that initiated from the pipe inside surface. 8491) 32 Shell Pipeline Company Metallurgical Analysis of May 20, 2016 Rupture on Tracy to Windmill Portion of San Pablo Bay Pipeline System 0.1 inches 0D lr Region 3 (Rupture) lg . ?u - Ill-?Maxie"? . 3 In I. . Figure 9 Ratchet Marks Figure 8. Photomicrograph showing a portion of the fracture surface from the rupture, clockwise (CW) side of the seam weld, after cleaning with a degreaser and methanol. Area indicated in Figure .5341? 0.05 Inches ., 2 . 4 .?fz #9 'f - a. - Figure 9. Photomicrograph showing close?up View of pits at ID pipe surface; area indicated in Figure 8. DNV GL OAPUS311MPHB (PP158491) 33 November 7, 2016 - Shell Pipeline Company Metallurgical Analysis of May 20, 2016 Rupture on Tracy to Windmill Portion of San Pablo Bay Pipeline System "\af Region 3 m? El .- - Fi??lime Piaf" . Region 2 Region 1 ID cw_#2 Figure 11 2000 um MAG: 10x kV Figure 10. SEM photomicrograph showing three distinct morphologies on fracture surface from rupture, area indicated in Figure 7 . I Flgure 12200 pm MAG: 100x Figure 11. SEM photomicrograph showing Region 1 of fracture surface from rupture, 100x; area indicated in Figure 10. DNV GL November 7, 2016 34 Shell Pipeline Company Metallurgical Analysis of May 20, 2016 Rupture on Tracy to Windmill Portion of San Pablo Bay Pipeline System Figure 12. SEM photomicrograph showing pit at ID surface 500x; area indicated in Figure 11. MAG: 2500 HV: 20.0 Figure 13. SEM photomicrograph showing fatigue striations in Region 1, area indicated in Figure 11. DNV GL (PP158491) 35 November 7, 2016 . .- Shell Pipeline Company Metallurgical Analysis of May 20, 2016 Rupture on Tracy to Windmill Portion of San Pablo Bay Pipeline System MAG: 500 HV: 20.0 kV Figure 14. SEM photomicrograph showing secondary cracking within Region 2, 500x; area indicated in Figure 10. cw_# 3:00 24 HV: 20.0 kV Figure 15. SEM photomicrograph showing small cracks on corrosion product-covered fracture surface in Region 2, area indicated in Figure 14. DNV GL OAPUS311MPHB (PP158491) 36 November 7, 2016 Shell Pipeline Company Metallurgical Analysis of May 20, 2016 Rupture on Tracy to Windmill Portion of San Pablo Bay Pipeline System . . . . . m'glidl Wk: momma?- Figure 16. SEM photomicrograph showing ductile fracture morphology in Region 3, 500x; area indicated in Figure 10. Figure 17. SEM photomicrograph showing ductile fracture morphology in Region 3, area indicated in Figure 16. DNV GL OAPUS311MPHB (PP158491) 37 November 7, 2016 {0 L6 Rupture on Tracy to Windmill Portion of San Pablo Bay Pipeline System 1.25 1.50 1.75 2.00 2.25 2.50 2.75 3.00 3.25 3.50 3.75 4.00 4.25 4.50 4.75 5.00 5.25 5.50 5.75 6.00 6.25 5.50 6.75 7.00 7.25 1038 0077 0.052 0.002 0.082 0.090 0.074 0.097 0.074 0.052 0.078 0.058 051% if? aquu'v 1 "2 - .17. .1, f3" '15} Awrmr?Lm "11.1 'z 2- .j'i >55 336(4 71m! a . .5: 11%? - .- - 0057 (1071 0.081 0.007 0.082 0.081 0.081 0077 0.044 0.081 0.054 0.030 .1 age of the fracture surface (clockwise side), showing depth measurements (red) of Region 1 of the pre? aw. 550 0.243 0.245 0.251 0.245 0.241 0.226 1.25 1.50 1.75 2.00 2.25 2.50 2.75 3.00 3.25 3-50 3.75 4.00 4.25 4.50 4.75 5.00 5.25 5.50 5.75 5.00 6.25 6.50 6.75 7.00 7.25 0.188 1.189 019131.195 0.205 .203 0.189 .177 0.159 ".143 0.078 . 51-97%. wk?. 3 02"? gh;ib h11" if; h. {khan-tau.- .1MIM ?911m?*W?mlwmuwug?wmm?w3" 4 0.177 0.186 0210 0210 0.193 0202 0.195 0.183 0.147 0.150 0.104 0.038 age of the fracture surface (clockwise side), showing depth measurements (green) of Region 1 and 3f the pre-existing flaw, together with wall thickness measurements (blue). 8491) 38 l0; 6 Rupture on Tracy to Windmill Portion of San Pablo Bay Pipeline System Mount M5 Mount M6 "in Region 1 i i \iominal Wall Thickness 0.260 inches ~E?Region 2 New A uv 15.9 16.0 16.1 16.2 16.3 16.4 16.5 Distance from GW, feet versus distance from the GW for Region 1 and Region 2 identified on the fracture surface. The 3f Mount M5 and Mount M6 are indicated by dashed lines. 8491) 39 Shell Pipeline Company Metallurgical Analysis of May 20, 2016 Rupture on Tracy to Windmill Portion of San Pablo Bay Pipeline System FLOW Mount M1 Flaw of Back-Cut . MPI Indication 1a Lab Fracture 4.25? length 0.125" maximum depth 48.1% of O. 260? nominal wall Figure 21. Photograph of the clockwise (CW) side of the fracture surface associated with MPI Indication 1a, and location of Mount M1. gr OD Back-Cut 0.260? wall ?7 - - Lab Fracture Region 2 7 0.125? . I Region 1 0.102" um. ID 7 Figure 22. Stereo-photograph showing a portion of the fracture surface associated with broken open MPI Indication 1a, without cleaning. Area indicated in Figure 21. DNV GL OAPUS311MPHB (PP158491) November 7, 2016 Shell Pipeline Company Metallurgical Analysis of May 20, 2016 Rupture on Tracy to Windmill Portion of San Pablo Bay Pipeline System . .. W, .. r- a. . . ?mmw - I I Lab Fracture Region -1 Figure 23. Stereo?photog raph showing a close-up View of the fracture surface associated with broken open MP1 Indication 1a, without cleaning. Area indicated in Figure 22. DNV GL OAPUS311MPHB (PP158491) November 7, 2016 .rw. up- .- v..r . . - . . Shell Pipeline Company Metallurgical Analysis of May 20, 2016 Rupture on Tracy to Windmill Portion of San Pablo Bay Pipeline System Figure 26 Figure~32 Figure 24. Photograph of the mounted Cross-section (Mount M5) removed from the likely rupture origin; 16.13 feet from the GW. Flow direction is into the page. Location indicated in Figure 1. 4% Nitai Etch. 7v I F1gure 34 'u 3.. Figure 25. Photograph of the mounted cross-section (Mount M6) removed from the ruptured joint, just from the likely rupture origin; 16.33 feet from the GW. Flow direction is into the page. Location indicated in Figure 1. 4% Nitai Etch. DNV GL 1 OAPUS311MPHB (PP158491) November 7, 2016 Shell Pipeline Company Metallurgical Analysis of May 20, 2016 Rupture on Tracy to Windmill Portion of San Pablo Bay Pipeline System . 3.9Int {1.2 I. "i Ferrite Pearlite . . . . 'fltweak1?5711.33" . "w - . . ?ung}. '5 '1 Inclusions :l .1 I .. Hm" hf? .30? - Hut-bf}; . it?? . .11 (cl) HAZ near Mid?Wall 1.41 - atI Figure 26. Photomicrographs of Mount M5, showing microstructure of base metal, weld fusion metal near ID, HAZ metal near ID weld toe, and HAZ metal near mid-wall. Locations indicated in Figure 25. 4% Nital Etch. DNV GL (PP158491) November 7, 2016 Shell Pipeline Company Metallurgical Analysis of May 20, 2016 Rupture on Tracy to Windmill Portion of San Pablo Bay Pipeline System Photomicrograph of Mount M5, clockwise (CW) side of the weld, showing the Figure 27. Figure 24. 4% Nita] Etch. in area indicated - I fracture path in cross?section DNV GL - OAPUS311MPHB (PP158491) November 7, 2016 Shell Pipeline Company Metallurgical Analysis of May 20, 2016 Rupture on Tracy to Windmill Portion of San Pablo Bay Pipeline System Figure 28. Photomicrograph of Mount M6, clockwise (CW) side of the weld, showing the fracture path in cross?section; area indicated in Figure 25. 4% Nital Etch. DNV GL OAPUSBIIMPHB (PP158491) November 7, 2016 Shell Pipeline Company Metallurgical Analysis of May 20, 2016 Rupture on Tracy to Windmill Portion of San Pablo Bay Pipeline System P). 9.: 3 n'J? . 1.. - . ?313' 4.5?2; 5 5' ?fzge? "are gar,? 351%?: Figure 29. Photomicrograph of Mount M5 showing the microstructure and the fracture profile within Region 1 near the internal pipe surface; area indicated in Figure 27._ 4% Nital Etch. *1 - - fie/Figure 30. Photomicrograph of Mount M5 showing the microstructure and the fracture profile within Region 2; area indicated in Figure 27. 4% Nital Etch. DNV GL OAPUS311MPHB (PP158491) November 7, 2016 Shell Pipeline Company Metallurgical Analysis of May 20, 2016 Rupture on Tracy to Windmill Portion of San Pablo Bay Pipeline System 100 pm Elongated/ deformed grains (shear) t. A. .6. - - $13Figure 31. Photomicrograph of Mount M5 showing the and the fracture profile within Region 3 near the external pipe surface; area indicated Figure 27. 4% Nital Etch. ?Fm-:11; Jim?s-1E8; . :77; .- r2931 5-. I 114' M5 As Polished M5 4% Nital Etch Figure 32. Photomicrographs of Mount M5 showing round and elongated inclusions in the base metal and corrosion product in a micro?pit on the ID surface of the pipe; area indicated in Figure 24. DNV GL OAPUS311MPHB (PP158491) November 7, 2016 um(322514;? 1 373,5," 1. .111. 5.34Lists-dc? 134.4. vanadium -31da?43 Shell Pipeline Company Metallurgical Analysis of May 20, 2016 Rupture on Tracy to Windmill Portion of San Pablo Bay Pipeline System ID 1000 um Figure 33. Photomicrograph of Mount M6, counterclockwise (CCW) side of the weld, showing a small crack at the weld toe; area indicated in Figure 25. 4% Nital Etch. DNV GL - OAPUS311MPHB (PP158491) November 7, 2016 Shell Pipeline Company Metallurgical Analysis of May 20, 2016 Rupture on Tracy to Windmill Portion of San Pablo Bay Pipeline System . o'v I a . ?f??it i 100 gm M5 4% Nital Etch (C 'r 1?3?3'f??m71i h?q M6 As Polished .. M6 4% Nital Etch Figure 34. Photomicrographs of Mount M5 (top, refer to Figure 24) and Mount M6 (bottom, refer to Figure 25, showing cracks at weld toe with pits and corrosion products on ID pipe surface; counterclockwise (CCW) side of the seam weld. DNV GL (PP158491) November 7, 2016 Shell Pipeline Company Metallurgical Analysis of May 20, 2016 Rupture on Tracy to Windmill Portion of San Pablo Bay Pipeline System doFigure 35. Photograph of the mounted cross?section (Mount M7) removed from the ruptured joint, away from the failure; 21.16 feet from the GW. Flow direction is into the page. Location indicated in Figure 1. 4% Nital Etch. Figure 36. Photograph of the mounted cross-section (Mount M3) removed from joint; 28.19 feet from the GW (01c the ruptured joint). Flow direction is into the page. Location indicated in Figure 1. 4% Nital Etch. Figure 37. Photograph of the mounted cross-section (Mount M4) removed from joint; ?1.54 feet from the GW (of the ruptured joint). Flow direction is into the page. Location indicated in Figure 1. 4% Nital Etch. DNV GL OAPUS311MPHB (PP158491) November 7,2016 Shell Pipeline Company Metallurgical Analysis of May 20, 2016 Rupture on Tracy to Windmill Portion of San Pablo Bay Pipeline System Figure 38. Photograph of the mounted cross?section (Mount M1) removed from MP1 Indication 1a (CW) and MP1 Indication 1b (CCW) of the ruptured joint, away from the rupture; 18.81 feet from the GW. Flow direction is into the page. Location indicated in Figure 1. 4% Nital Etch. OD Figure 43 . it?" Figure 44 Figure 39. Photograph of the mounted cross-section (Mount M2) removed from MPI Indications 2 (CW) of the ruptured joint, away from the rupture; 23.83 feet from the GW. Flow direction is into the page. Location indicated in Figure 1. 4% Nital Etch. DNV GL November 7, 2016 Shell Pipeline Company Metallurgical Analysis of May 20, 2016 Rupture on Tracy to Windmill Portion of San Pablo Bay Pipeline System gayr2"? 1" (.L .I a 1* Photomicrograph of Mount M1 (MP1 Indication 1a) showing crack at weld toe from ID surface on clockwise (CW) side of the seam weld; mirror image of Figure 40. area indicated in Figure 38. 4% Nital Etch. DNV GL OAPUS311MPHB (PP158491) November 7, 2016 Shell Pipeline Company Metallurgical Analysis of May 20, 2016 Rupture on Tracy to Windmill Portion of San Pablo Bay Pipeline System were an 1- agzmy"? Rises-14E gang-aw {age-5W .?esgote .1 . -. Ru. 733w. .96 Wfrv? ?an ,amx .- . ?5113? ?we? .1233. grin; v. we? mar-m - . . viz-49* - 31.Ipi?hi?} a. l. r: . 41?: vn?ru . '13'33:15.; Figure 41. Photomicrograph of Mount Ml (MPI Indication la) showing crack tip on clockwise (CW) side of the seam weld; area indicated in Figure 40. 4% Nital Etch. Inset photo shows close-up of transgranular morphology at crack tip. DNV GL OAPUS311MPHB (PP158491) November 7, 2016 .: I V, . - .- . ?prf mg- vhf]: =7 :7 ?Hr-nub . . a- - ?my.?mx .3. . . Jug, ..-A- A - {1.4 Ems-iv? a? ?uv? ~30 77? a Shell Pipeline Company Metallurgical Analysis of May 20, 2016 Rupture on Tracy to Windmill Portion of San Pablo Bay Pipeline System was - 1 3-4.. . . .. ?It ?sghas? seesaw r. ?b :1 Figure 42. Photomicrograph of Mount M1 (MPI Indication 1b) showing overlap of weld bead on ID surface, counterclockwise (CCW) side of the seam weld; mirror image of area indicated in Figure 38. 4% Nital Etch. DNV GL OAPUS311MPHB (PP158491) November 7, 2016 Shell Pipeline Company Metallurgical Analysis of May 20, 2016 Rupture on Tracy to Windmill Portion of San Pablo Bay Pipeline System J. Figure 43. Photomicrograph Of Mount M2 (MPI Indication 2), clockwise (CW) side of the. weld, showing a notch from undercut at the weld toe; mirror image of area indicated in Figure 39. 4% Nital Etch. DNV GL OAPUS311MPHB (PP158491) November 7, 2016 Shell Pipeline Company Metallurgical Analysis of May 20, 2016 Rupture on Tracy to Windmill Portion of San Pablo Bay Pipeline System '1 "s n-?Polished M2 4% Nital Etch Photomicrographs of Mount M2 (MPI Indication 2) showing crack at weldtoe from ID surface on clockwise (CW) side of the seam weld; mirror images of area indicated in Figure 39. Figure 44. Visibl?p'qrtibnsot tiP'i's 7 Loomicrohse '2-[04043? inches. Figure 45. EDS map of Mount M1 (MPI Indication 1a) at crack shown in Figure 40, showing presence of sulfur at tip of the crack that started at weld toe from ID surface on clockwise (CW) side of the seam weld. DNV GL OAPUS311MPHB (PP158491) November 7, 2016 Shell Pipeline Company Metallurgical Analysis of May 20, 2016. Rupture on Tracy to Windmill Portion of San Pablo Bay Pipeline System .. . ?ft? 13-#33263 Man anese Sulfur Silicon Carbon Figure 46. EDS map of Mount M1 (MP1 Indication 1a) at crack shown in Figure 40, showing distribution the crack that started at weld toe from ID surface on clockwise (CW) side Of the seam weld. DNV GL (PP158491) November 7, 2016 a} . Shell Pipeline Company Metallurgical Analysis of May 20, 2016 Rupture on Tracy to Windmill Portion of San Pablo Bay Pipeline System Figure 47. EDS measurement locations on Mount M2 (results shown in Table 5; also refer back to Figure 44), at weld toe crack with pit and corrosion product, from ID surface on counterclockwise (CCW) side of the seam weld. Figure 48. EDS map of Mount M2 (MPI Indication 2) at crack shown in Figure 47, showing distribution of sulfur. DNV GL OAPUS311MPHB (PP158491) November 7, 2016 Shell Pipeline Company Metallurgical Analysis of May 20, 2016 Rupture on Tracy to Windmill Portion of San Pablo Bay Pipeline System Iron Ox sen Man anese Sulfur Silicon Carbon Figure 49. EDS map of Mount M2 (MP1 Indication 2) at crack shown in Figure 47, showing distribution OAPUS311MPHB (PP158491) November 7, 2016 Shell Pipeline Company Metallurgical Analysis of May 20, 2016 Rupture on Tracy to Windmill Portion of San Pablo Bay Pipeline System Hardness (HV) Measurement Mount M5 Mount M6 Location 16.13 ft from UIS GW 16.33 ft from GW 1 190.3 192.5 2 218.1 187.6 3 204.1 201.7 4 206.5 218.8 5 210.9 . 209.1 6 215.5 228.5 7 204.1 206.0 8 216.1 183.4 9 163.1 176.4 10 182.9 210.3 11 201.7 214.8 12 182.9 190.9 13 207.8 190.9 14 212.2 211.6 15 197.0 208.4 16 191.4 224.3 17 227.8 214.8 18 206.5 195.3 19 180.4 180.9 Figure 50. Results of hardness measurements at various locations on Mount M5 (Figure 24) and Mount M6 (Figure 25). Mount M5 shown above; measurements performed at similar locations on Mount M6. DNV GL - OAPUS311MPHB (PP158491) November 7, 2016 Shell Pipeline Company Metallurgical Analysis of May 20, 2016 Rupture on Tracy to Windmill Portion of San Pablo Bay Pipeline System Hardness (HV) Measurement Mount M3 Mount M4 Mount M7 Location DIS joint UIS joint Failed joint 1 183.4 213.4 193.1 2 213.5 235.1 196.5 3 195.3 226.4 218.1 4 207.8 226.4 220.1 5 205.3 227.8 225.0 6 201.7 214.2 214.2 7 205.3 216.8 214.2 8 172.1 214.2 214.2 9 201.1 205.3 200.5 10 214.8 192.0 191.9 11 201.1 227.8 204.1 12 190.3 218.1 210.3 13 180.4 199.9 210.3 14 181.4 220.1 201.1 15 183.4 205.3 193.1 16 168.9 212.9' 193.1 - Figure 51. Results of hardness measurements taken at representative locations on Mount M3 (Figure 36), Mount M4 (Figure 37), and Mount M7 (Figure 35). Mount M3 shown above; measurements performed at similar locations on Mount M4 and Mount M7. DNV GL OAPUS311MPHB (PP158491) November 7, 2016 . . . . . . . . . - . A - . . 1 I Shell Pipeline Company Metallurgical Analysis of May 20, 2016 Rupture on Tracy to Windmill Portion of San Pablo Bay Pipeline System Hardness (HV) Measurement Mount M1 Location MPI Indications 1al1b 1 188.7 2 211.6 3 208.4 4 200.5 5 211.6 6 184.5 7 194.2 8 201.7 9 174.0 10 163.1 11 166.5 12 197.0 13 197.7 14 214.8 15 203.2 16 187.6 - 17 214.2 18 227.1 19 197.0 20 183.4 Figure52. Results of hardness measurements at various locations on Mount M1. DNV GL OAPUS311MPHB (PP158491) November 7, 2016 I 1 Shell Pipeline Company Metallurgical Analysis of May 20, 2016 Rupture on Tracy to Windmill Portion of San Pablo Bay Pipeline System Hardness (HV) Measurement Location Mount M2 1 179.9 2 192.0 3 210.3 4 207.2 5 197.6 6 196.5 7 199.3 8 196.5 9 204.1 10 211.6 11 180.9 12 196.7 13 194.2 14 190.1 15 191.4 Figure 53. Results of hardness measurements at various locations on Mount M2. DNV GL (PP158491) November 7, 2016 Shell Pipeline Company Metallurgical Analysis of May 20, 2016 Rupture on Tracy to Windmill Portion of San Pablo Bay Pipeline System Base Meta! - Shear Curve 100 Shear?rea-250 450 -50 50 150 250 Temperamre, Figure 54. Percent shear from Charpy V?notch tests as a function of temperature for transverse base metal specimens removed from the pipe joint that ruptured. Base Metal Impact Curve 40 0th Impact Energy Ft-ibs -250 450 *50 so 150 250 Ternpemmretf Figure 55. Charpy V?notch impact energy as a function of temperature for transverse base metal specimens removed from the pipe joint that ruptured. DNV GL - (PP158491) November 7, 2016 Shell Pipeline Company Metallurgical Analysis of May 20, 2016 Rupture on Tracy to Windmill Portion of San Pablo Bay Pipeline System HAZ - Shear Curve nix )?250 .159 so so 150 250 Temperamre.?f Figure 56. Percent shear from Charpy V?notch tests as a function of temperature for transverse seam weld (HAZ) specimens removed from the pipe joint that ruptured. HAZ-lmpactCurve 4o CNN Impacl Energy, Ft?lbs -250 450 -50 so 150 250 Temperature? Figure 57. Charpy V?notch impact energy as a function of temperature for transverse seam weld (HAZ) specimens removed from the pipe joint that ruptured. DNV GL OAPUSBIIMPHB (PP158491) November 7, 2016 i Shell Pipeline Company Metallurgical Analysis of May 20, 2016 Rupture on Tracy to Windmill Portion of San Pablo Bay Pipeline System APPENDIX A DSAW Measurements DNV GL OAPUS311MPHB (PP158491) November 7, 2016 Shell Pipeline Company Metallurgical Analysis of May 20, 2016 Rupture on Tracy to Windmill Portion of San Pablo Bay Pipeline System Rupture Location Figure A1. Photograph of the mounted cross-section (Mount M5) removed from Rupture Origin. 16.13 feet from the GW. Figure A2. Photograph of the mounted cross-section (Mount M6) removed from Rupture Origin, 16.33 feet from the GW. DNV GL (PP158491) A-l November 7, 2016 A . u- 4n. Shel] Pipeline Company Metallurgical Analysis of May 20, 2016 Rupture on Tracy to Windmill Portion of San Pablo Bay Pipeline System Reference Locations Irv?? af?u? Figure A3. Photograph of the mounted cross?section (Mount M7) removed from Failed Joint, Away from the Rupture, 21.16 feet from the GW. Figure A4. Photograph of the mounted cross?section Joint, ?1.54 ft from the GW. .1, lags j, a? f, . . . Figure A5. Photograph of the mounted cross?section (Mount M3) removed from Joint, 28.19 feet from the GW. DNV GL OAPUS311MPHB (PP158491) A-2 November 7, 2016 Shell Pipeline Company Metallurgical Analysis of May 20, 2016 Rupture on Tracy to Windmill Portion of San Pablo Bay Pipeline System MPI Indications Figure A6. Photograph of the mounted cross?section (Mount M1) removed from MPI Indications 1a/1b, 18.81 feet from the GW. Figure A7. Photograph of the mounted cross-section (Mount M2) removed from MP1 Indication 2, 23.83 feet from the GW. DNV GL - OAPUS311MPHB (PP158491) A-3 November 7, 2016 Shell Pipeline Company Metallurgical Analysis of May 20, 2016 Rupture on Tracy to Windmill Portion of San Pablo Bay Pipeline System APPEN DIX Analysis DNV GL November 7, 2016 Shell Pipeline Company Metallurgical Analysis of May 20, 2016 Rupture on Tracy to Windmill Portion of San Pablo Bay Pipeline System APPENDIX Description of The computer program was developed by Det Norske Veritas (U.S.A.), Inc. (formerly CC Technologies) to evaluate crack?like flaws in pipelines based on inelastic fracture mechanics. Using the effective area of the actual, measured crack length?depth profile, an equivalent semi?elliptical surface flaw is modeled and used to compute the effective stress and the applied value of for internal pressure loading. The effective stress and'applied are then compared with the flow strength (0's) and fracture toughness respectively, to predict the failure pressure. The program also contains a similar inelastic fracture mechanics analysis for through-wall flaws. The fracture toughness of the steel can be estimated from Charpy data or measured by means of a JIC test. In the most recent version of the fracture toughness analysis automatically checks for plastic instability and only the fracture toughness curve needs to be considered for crack?like flaws. The actual tensile and Charpy properties of the pipe joint, measured from the samples removed, can be used for the critical leak/rupture length calculation. DNV GL - OAPUS311MPHB (PP158491) 3-1 November 7, 2016 Shell Pipeline Company Metallurgical Analysis of May 20, 2016 Rupture on Tracy to Windmill Portion of San Pablo Bay Pipeline System Case 1: Measured mechanical base?metal properties, measured dimensions, and the as? measured flaw profile of Region 1 (Fatigue). Shell SW 24" Semi-Elliptical Flaw Profile Base Metal Maximum Operating Pressure (psig) 936 UTS (psi) 87800 YS (psi) 70300 FS (psi) 79050 (ksi) 29500 nexp 0.089 Jc (lb/in) 3068 Thin?wall (OD) formula for hoop stress Tmat 49.3 OD 24 Wall Thickness (in) 0.260 Summary of Results for Effective Area Method Flaw: Start (in) 0.50 Length (in) 6.75 Area 0.464 Depth (in) Maximum 0.097 Equivalent Flaw 0.088 For Design Factor 0.72 Design Pressure (psig) 1096.68 Failure Stress (psi) 65598 Failure Pressure (psig) 1421.28 For Design Factor 0.72 . Maximum Safe Pressure (psig) 1023.32 Critical and Safe Pressure for a Crack At operating pressure: (lb/in) 43.3 4.9 For Jc (lb/in) 3068.0 Tmat 49.3 Predicted Critical Pressure (psig) 1413.18 For Design Factor 0.72 Maximum Safe Pressure (psig) 1017.49 Based on Fracture Toughness (Jc) criterion Flaw: Start (in) 0.50 Length (in) 6.75 Area 0.464 Depth Maximum 0.097 Equivalent Flaw 0.088 DNV GL 5-2 November 7, 2016 Shell Pipeline Company Metallurgical Analysis of May 20, 2016 Rupture on Tracy to Windmill Portion of San Pablo Bay Pipeline System Case 2: Measured mechanical base?metal properties, measured dimensions, and the as? measured ?aw profile of Region 1 (Fatigue) Region 2 (Step-Wise Cracking). Shell SW 24" Semi?Elliptical Flaw Profile Base Metal Maximum Operating Pressure (psig) 936 UTS (psi) 87800 YS (psi) 70300 FS (psi) 79050 (ksi) - 29500 nexp 0.089 Jc (lb/in) 3068 Thin?wall (OD) formula for hoop stress Tmat 49.3 OD (in) 24 Wall Thickness (in) 0.260 Summary of Results for Effective Area Method Flaw: Start (in) 1.00 Length (in) 5.00 Area 1.010 Depth (in) Maximum 0.210 Equivalent Flaw 0.234 For Design Factor 0.72 Design Pressure (psig) 1096.68 Failure Stress (psi) 35994 Failure Pressure (psig) 779.86 For Design Factor 0.72 . Maximum Safe Pressure (psig) 561.5 Critical and Safe Pressure for 3 Crack At operating pressure: (lb/in) 37199.3 For Jc (lb/in) 3068.0 Tmat 49.3 Predicted Critical Pressure (psig) 658.13 For Design Factor 0.72 Maximum Safe Pressure (psig) 473.85 Based on Fracture Toughness (Jc) criterion Flaw: Start (in) 1.75 Length (in) 3.50 Area 0.684 Depth Maximum 0.210 Equivalent Flaw 0.249 DNV GL 8-3 November 7, 2016 Shell Pipeline Company Metallurgical Analysis of May 20, 2016 Rupture on Tracy to Windmill Portion of San Pablo Bay Pipeline System Case 3: Measured mechanical HAZ properties, measured dimensions, and the as?measurecl flaw profile of Region 1 (Fatigue). Shell SW 24" Semi-Elliptical Flaw Profile HAZ Maximum Operating Pressure (psig) 936 UTS (psi) 85700 YS (psi) 70300 FS (psi) 78000 (ksi) 29500 nexp 0.083 Jo (lb/in) 3000 Thin?wall (OD) formula for hoop stress Tmat 49.7 OD (in) 24 Wall Thickness (in) 0.260 Summary of Results for Effective Area Method Flaw: Start (in) 0.50 Length (in) 6.75 Area 0.464 Depth (in) Maximum 0.097 Equivalent Flaw 0.088 For Design Factor 0.72 Design Pressure (psig) 1096.68 Failure Stress (psi) 64726 Failure Pressure (psig) 1402.41 For Design Factor 0.72 Maximum Safe Pressure (psig) 1009.73 Critical and Safe Pressure for a Crack At operating pressure: (lb/in) 41.7 4.7 For Jc (lb/in) 3000.0 Tmat 49.7 Predicted Critical Pressure (psig) 1394.41 For Design Factor 0.72 Maximum Safe Pressure (psig) 1003.97 Based on Fracture Toughness (Jc) criterion Flaw: Start (in) 0.50 Length (in) 6.75 Area 0.464 Depth Maximum 0.097 Equivalent Flaw 0.088 DNV GL 3-4 November 7, 2016 Shell Pipeline Company Metallurgical Analysis of May 20, 2016 Rupture on Tracy to Windmill Portion of San Pablo Bay Pipeline System Case 4: Measured mechanical HAZ properties, measured dimensions, and the as-measured flaw profile of Region 1 (Fatigue) Region 2 (Step?Wise Cracking). Shell SW 24" Semi-Elliptical Flaw Profile HAZ Maximum Operating Pressure (psig) 936 UTS (psi) 85700 YS (psi) 70300 FS (psi) 78000 (ksi) 29500 nexp 0.083 Jc (lb/in) 3000 Thin-wail (OD) formula for hoop stress Tmat 49.7 OD 24 Wall Thickness (in) 0.260 Summary of Results for Effective Area Method Flaw: Start (in) 1.00 Length (in) 5.50 Area 1.010 Depth (in) Maximum 0.210 Equivalent Flaw 0.234 For Design Factor 0.72 Design Pressure (psig) 1096.68 Failure Stress (psi) 35516 Failure Pressure (psig) 769.50 For Design Factor 0.72 Maximum Safe Pressure (psig) 554.04 Critical and Safe Pressure for a Crack At operating pressure: (lb/in) 20361.8 5938.4 For Jc (lb/in) 3290.3 Tmat 54.5 Predicted Critical Pressure (psig) 663.78 For Design Factor 0.72 Maximum Safe Pressure (psig) 477.92 Based on Fracture Toughness (Jc) criterion Flaw: Start (in) 1.25 Length (in) 425 Area 0.817 Depth Maximum 0.210 Equivalent Flaw 0.245 GL 35 November 7, 2016 ABOUT DNV GL Driven by our purpose of safeguarding life, property, and the environment, DNV GL enables organizations to advance the safety and sustainability of their business. We provide classification and technical assurance along with software and independent expert advisory services to the maritime, oil and gas, and energy industries. We also provide certification services to customers across a wide range of industries. Operating in more than 100 countries, our 16,000 professionals are dedicated to helping our customers make the world safer, smarter, and greener. DNV GL OAPUS311MPHB (PP158491) 5-6 November 7, 2016 SJV 24-INCH MAY 2016 LOPC RCA REPORT Copyright of Shell Pipeline Company October 20] 6 1 AGENDA I Summary ol: RCA I Timeline at Events I Summary of the Failure Analysis Results Summary Cause and Effect Diagram I Explanation of the Metallurgical Causes I Vendor Selection and Performance I Recommendations I Background I DNV GL Failure Analysis Report I Detailed Timeline I Cause and Effects Diagram Copyright of Shell Pipeline Company October 2016 2 SUMMARY OF THE RCA On May 20th, 2016, a rupture occurred on the Tracy to Windmill section at the SJV pipeline system. This rupture occurred due to a tatigue crack that developed and grew to tailure and was not reported by the UT-C survey. The tatigue crack developed and grew to tailure during transportation and/ or in-service. The peaked geometry at the longitudinal seam weld, operational pressure cycling, inclusions in the pipe steel, and potentially an environmental tactor played a role in the growth at the crack. A feature was ?,detected identitied classified as a crack- like in long seam at the location at tailure In the automatic report following the UT- survey. During manual review of the data by Rosen,? an incorrect amplitude was selected.? Because at this ?the Analyst overruled the [automated] call with the lower depth ot 0.013 inch? This ultimately led to Rosen notreporting the Feature. Copyright of Shell Pipeline Company October 2016 3 TIMELINE OF EVENTS - 1 I i 982 Pipe was manufactured by ARMCQ in Houston, TX tor Columbia Gas and shipped to Northeastern US I 1988 - Pipe was purchased by Texaco From Columbia Gas and shipped From the Northeastern US to Coalinga, California I 1989 Pipe was installed at Tracy to Windmill Forms (305 miles) lAlso installed at Coalinga to Mack Hill (3.4 miles at 5.9 mile segment) and Butts Road to Gustine (6.1 miles at 7.2 mile segment) I April 1990 -- Pipeline hydrotested to 1,181 psig, held tor tour hours I i 998 to 2015 Multiple MFL and Caliper surveys performed I 6/6/1998 02:35 PST Pipe iailure approximately one mile oi Tracy in pipe body I 5/25/i 5 Pump Fire at Tracy I Heat and pressure from the incident is not thought to have attected the pipeline segment Copyright at Shell Pipeline Company October 2016 4 TIMELINE OF EVENTS - 2 I 9/16/15 at 23:35 CDT Rupture occurred on the 24? section of piping ,829 feet ot Tracy Station I Subsequent Failure analysis determined the pipe section ruptured at a preexisting tatigue crack that initiated at the toe of the double submerged arc weld (DSAW) 9/21/15 - Pipeline operation commenced at a temporarily reduced pressure 0t to 724 psig I 80% at 905 psig the pressure at the time at the 9/16/2015 LOPC 12/3/2015 Rosen MFL-C survey performed on the pipeline I 12/4/2015 - Rosen UT-C survey performed on the pipeline I 3/ 7/ 201 6 Final MFL-C report provided to SPLC showing: I No crack-like or other anomalies necessitating immediate action or any additional repairs required per SPLC Anomaly Response Table. Copyright of Shell Pipeline Company I October 2016 5 TIMELINE OF EVENTS - 3 I /2016 - Dratt Preliminary Report received from Rosen I Resulted in two excavations based on iSO-day conditions trom the SPLC Anomaly Response Table I 4/ 25/ 201 6 Preliminary UT-C report received tram Rosen. I No additional Features reported that met the SPLC Anomaly Response Table I 5/2/2016 - Final UT-C report provided to SPLC showing: I No crack anomalies necessitating immediate action per the SPLC Anomaly Response Table ITwo conditions reported by Rosen classified as 180 day conditions by SPLC I Scheduled for excavation based on 4/ 1/2016 Dratt Preliminary Report Copyright at Shell Pipeline Company - October 2016 6 TIMELINE OF EVENTS 4 I 5/9/2016 - Based on the MFL-C and UTEC surveys confirming the absence of any actionable detects, the recommendation was made by SPLC Engineering to remove the operating pressure reductions on three North Heavy segments with 24-inch Armco pipe. I 5/ 1 6/201 6? Statement at Fitness to remove the 20% pressure reduction was approved I 5/17/2016? 20% pressure reduction was removed and original 936 psig MOP re- instated I 5/20/2016- 00:35:55 PDT- Pipeline tailed 4,013 teet at Tracy Station I 5/22/2016 - Failed pipe joint was replaced with 24-inch pipe I 6/9/2016 - Spike (1,170 psig) and 8-hour hold (1,070 psig) rotest was successful I 7/19/2016? Pipeline restarted at a new MOP of 850 psig Copy right otSh elleelin eaaCrnp ny Owtber2016 7 SUMMARY OF FAILURE ANALYSIS I DNV GL in Columbus, OH performed the metallurgical Failure analysis. The pipe section ruptured at a preexisting Fatigue crack that initiated at the toe of the double submerged arc weld (DSAW) and exhibited three distinct regions: I Region 1 a crack region at the internal surface with a maximum depth at 0.097 inches (37.3% at 0.260 inches nominal wall thickness) caused by Fatigue; Region 2 I Region 2 a crack region with a stair-stepped appearance, beginning at the end at Region 1, resulting tram higher stress intensity tactor at the crack tip as the crack propagated deeper into the material and possibly an environmental component. The maximum depth at this region is 0.210 inches (80.8% of 0.260 inches nominal wall thickness); Region 1 1000 pm I Region 3 the remaining ligament that DNV GL Mount M6 overloaded during the rupture event. Copyright of Shell Pipeline Company October 2016 8 CAUSE AND EFFECT - HIGH LEVEL Rupture of fatigue crack in the toe of a DSAW pipe Crack initiated and grew by fatigue (Region 1) Or during 9 initiated and grew transportation during operation See Page 2 See Page 3 Copyrighi oi Sheii Pipeline Company And Crack grew in?service by a second mechanism (Region 2) AndiOr inclusions in the Graig: by heat affected zone emiironmental became connectedH mechanism See Page 4 See Page 5 chober 201 6 9 REGION 1 - FATIGUE CRACK INITIATION AND GROWTH I Transport Fatigue I Pipe was susceptible to transport Fatigue I Pipe was transported multiple time I Pipe had a peaked geometry that acted as a stress riser I In-Service Fatigue I Cracks initiated at corrosion micro-pits at the inner diameter surface at the pipe I Pipeline has aggressive pressure cycling I Pipe had a peaked geometry that acted as a stress riser DNV GL concluded that ?the fatigue crack initiation and propagation most likely occurred while in service. However, transit iatigue during transportation of the pipe cannot be ruled out as a contributing factor? Copyright oi: Shell Pipeline Company October 20] 6 10 REGION 2 - CONTINUED CRACK GROWTH I A combination of three different Factors contributed to changing how the crack grew in service and had a different appearance from Region 1 1. Linkage ot inclusions through pressure cycling of the pipeline 2. Higher stress at crack tip I Higher stress intensity as crack penetrated deeper I Peaked geometry of the weld 3. Possible environmental mechanism Copyright at Shell Pipeline Company October 2016 i I PRE-EXISTING FLAW PROFILE DNV GL Mount M5 0255 1 . DNV (3L Mount M6 0.166 ?0,132 E.0099 \i 0.055 Gym-015.3 1519 15.0 I 15.1 16.2 I 16.3 i 16.4. 3.5.5 Distance from U15 aw, feat Length 6.96 inches Region 3 Maximum depth of Region 1 0.097 inches (Rupture) (37.3% oi nominal) Maximum depth of Region i and 2 0.210inches Region 2 (80.8% of nominal) Average wall thickness for Failed Joint 0.275 - inches Regim 1 20m 51m- Copyrighi of Shell Pipeline Company Oclolser 7.016 I2 TRANSPORTATION FATIGUE I Pipe with a diameter to wall thickness ratio greater that 50 is susceptible to transport Fatigue per API 5LT I Failed ioint had a ratio at 92. I Pipe was transported multiple times I Transported From Armco (Houston, TX) to the Northeastern US I Likely the Delaware, Maryland, or area (Columbia Gas) I Purchase records show API 5L1 Recommended Practices was followed ITransported from the Northeastern US to Coalinga, CA IVerbal intormation indicates that API 5LT would have been specitied per industry norms, written records have not been located I Pipe had a peaked geometry that acted as a stress riser Copyright of Shell Pipeline Company October 2016 i 3 PIPELINE OPERATIONS PRESSURE CYCLING I Pressure cycling is a significant Factor in the development and growth of fatigue cracks Pipeline had ?aggressive" pressure cycles in accordance with Baker TTO5 reference standard I Daily power optimization leads to pressure cycling I psig (23% SMYS) daily pressure change at original MOP oi 936 psig (32% oi MOP) I ?200 psig (15% SMYS) daily pressure change with 20% pressure reduction from 936 psig MOP (21% oi MOP) I Shutdowns lead to pressure cycling I psig (65% SMYS) pressure change during shutdown at original MOP at 936 psig (91% at MOP) . psig (50% SMYS) pressure change during shutdown with 20% pressure reduction From 936 psig MOP (69% of MOP) Copyright of Shell Pipeline Company October 201 6 i4 PIPELINE OPERATIONS PRESSURE CYCLING (2) I May 2016 - Tracy Discharge Pressure 800 - Daily Power Optimization Pressure Shutdown Reduction (Failure) Removed ii 5i; 500 I. 400 300 Shmdow?IL-i? Shutdown 200 Shutdown Shutdown 100 shutdown 3L Shut 0?31; Shutdown h? 0 5f1f15 5/3/15 5/5/15 5/7/16 54"111'16 5f13/16 53?15/16 53'173'16 5f21/16 Date Copyright of Sheii Pipeline Company October 2016 15 PEAKED Mount Uneaked A i - Peakedi' I The ?peaked? geometry of the DSAW was a causal factor for Region 1 and Region 2 For each hypothesis reviewed in the cause and effect diagram I Quality control and quality assurance From the pipe mill should have identified the ?peaked? geometry I The ?peaked? weld had a deformation at approximately 0.5% which is below the reporting threshold at traditional deformation tools IThe ?peaked? seam would be considered a sharp contour and ditticult to detect in larger diameter pipe using traditional geometry surveys Copyright of Shell Pipeline Company October 20] 6 6 ADDITIONAL FEATURE IN SAME PIPE JOINT AS FAILURE I Three additional indications were identitied through magnetic particle inspection FLOW I MPI Ia exhibited similarities Mount M1 . . ., I to the mam I'eature With a Back-Cut A Lab Fracture . I OD Figure Flaw of Indication la Region I and Region 2 Found to be 4.25 Inches Iong ID 7: "Egg; and O.I 25 inch deep I?i; IWas not reported by the ILI DNV GL Mount MI vendor in any report lMeets the stated detection threshold oi UT-C survey MPI I la and 2 were over-till or under-till respectively Copyright of Shell Pipeline Company October 2016 I7 VENDOR SELECTION I A recommendation from the September 2015 LOPC RCA on Tracy to Windmill Farms was to perform a crack detection ILI survey lThis recommendation applied to the three segments that have ARMCO pipe at similar vintage I Rosen could perform both MFL-C and UT-C surveys IMFL-C can give a second opportunity to review the longitudinal seam weld tor crack-like teatures Copyright of Shell Pipeline Company October 2016 I 8 ILI VENDOR PERFORMANCE (1) I Per Rosen, an ?anomaly In ioint 1250 was detected, identified, and boxed. It was classified as a crack- like In long seam with the automated sizing process lOdometer 4073. 71 8, 7. 594 inch long and 0.150 inch (57. deep I Due to the volume oi features that required review by the Rosen elected to modiiy their process For review of features. This included changing the amplitude that was used tor signal review I No management of change or equivalent process was utilized within Rosen and SPLC was not consulted I Per Rosen, ?during sizing an incorrect amplitude was selected. Anomaly depth was calculated at 0.08 inch? I Rosen believed that the reporting threshold was 0.08 inch Odometer 4073.718, per Rosen, ?the Analyst overruled the [automated] call with the lower depth ot0.013 inch? I No Feature was reported at the location at the Failure Copyright of Shell Pipeline Company October 2016 i 9 ILI VENDOR SELECT ION AND PERFORMANCE (2) Rosen has i .. . . .. I ?The acoustics ol: DSAW long seams are complex. This is due to a parabolic I reflection of the weld cap/crown? I strong signal is generated when the beam is reflected in itself? I?Mill grinding or repair cause a locally i i i, I shitted sell-reflection? 1' 'l I ?Edge or root re?ections occur, but are only visible from one side? I Prior to the survey, SPLC provided a summary at the peaked geometry from the September LOPC to the Rosen sales representative. It is unclear it this information was shared with the technical stall within Rosen. Copyright of Shell Pipeline Company October 2016 20 ROSEN JOINT 1250 SUMMARY DATA EVALUATION ANDMALIES DETECTED ROSEN IN JOINT 1 250 Manual Depth Sizing Distance length Angel {deg} Type [?eet] {inch} [degree] [d3] [inch] 4072.555 9.930 250.977 40.200 0.000 4073.710 7.594 251.033 CRAB-LIKE 42.000 0.013 r" 4076.633 5.443 252.530 43.400 0.017 4031.577? 3.245 251.553 CRAB-LIKE 45300 0.032 Automated Depth Sizing Distance length Ange?de? Type WJIMPL [teat] [inch] [degree] ?nch] 4.073333 . 7594 251933. . . 51.000 . . The review of the data revealed a different depth for feature at 4073.718 it based on the Automated? Depth Sizing. The Analyst overruled the call with the lower depth of 0.013 in. This is typically done if the echo signal. shews inconsistent pattern. This is subjectfor further investigation. ROSEN I SlidEE Copyright of Shell Pipeline Company - October 2016 21 RECOMMENDATIONS (APPROVED) Enhancement of integrity program related to crack-like defects. Enhance process for identifying lines to survey, tool selection, vendor verification, run acceptance, and response. This item is procedural changes to be in place for 2017 crack detection surveys. This item will also serve to modify the seam susceptibility algorithm for of all seam types DSAW, high frequency ERW, etc.) Review pipelines with aggressive pressure cycling to determine: 1) if additional integrity assessment is required 1L1 crack detection or hydrotest) and (2) if any operational modifications can be made to reduce the pressure cycle severity Review previous ILI data in ARMCO pipe to determine if peaking can be identified in those surveys Determine the reassessment interval for the ARMCO pipe in the SJV system for (1) ILI reassessment, and (2) hydrotest Confirm how frequently corrosiveness testing (CO2, H25, pH, etc.) in pipelines is performed End the practice of daily power optimization on SJV system Install MOVs at Los Bones and Kamm to eliminate the necessity for shutdowns of adiacent segments when Los Banos and Kamm are shutdown Review operating procedure related to planned shutdowns to identify opportunities to limit the magnitude or pressure cycling that occur on the North Heavy System Develop a list of pipelines that are aggressively cycled and what is being done about the cycling. There needs to be corporate aWareness for what pressure cycling does to the pipelines. This action needs to lead to more discipline and visibility of the issue Continuously improve the process by ensuring there is documentation following a 1 15 adiustment to set points that the notification is closed out by the technician following the implementation of changes Copyright of Shell Pipeline Company 12/15/16 12/15/16 12/15/16 12/15/16 12/15/16 Complete 7/1/17 12/15/16 12/15/16 3/31/17 October 2016 22