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PHMSA Western Region Overview Tempe, AZ August 20, 2014

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Presentation on theme: "PHMSA Western Region Overview Tempe, AZ August 20, 2014"— Presentation transcript:

1 PHMSA Western Region Overview Tempe, AZ August 20, 2014

2 PHMSA Region Updates Relatively Quiet Year for Accidents but busy Total Switch to Integrated Inspection Process (II) Use the Integrated Inspection Assistant Tool (IA) Continued Construction Oversight of pipeline boom in MT, WY and NE Colorado Aging Workforce and More Departures Focus was on: Lesson Learned from Near Misses and Accidents Jump on even smallest incidents hard and anticipate questions, e.g. flooding, Bakken crude

3 PHMSA Region Contacts & SMEs
Chris Hoidal – Director of Western Region Bryn Karaus – Western Region Counsel Huy Nguyen, Jeff Gilliam, Terry Larson– Supervisors Peter Katchmar – Accident Coordinator Ross Reineke – Construction Coordinator Tom Finch and David Mulligan – Community Assistance and Technical Services (CATS) David Mulligan and Kim Nguyen - Inspection Assistant Power Users Dustin Hubbard and Claude Allen - PDM and Mapping Issues Jerry Kenerson – Safety Related Condition Follow-up

4 PHMSA Regions

5 Western Region Offices
Western Region Office – 16 Engineers West Dakota Avenue, Suite 110 Lakewood, CO Satellite offices in: Cheyenne, WY (Accident Investigator) Billings, MT (1 engineer) Reno, NV (1 engineer) Ontario, CA (3 engineers) Anchorage, AK (5 engineers) One Regional Attorney – DC Openings – One Engineer/Inspector

6 Recap of Western Region Priorities – (2010-2013)
Continue to roll on more accidents, even low level ones Multiple Orders completed or finishing up. Construction Oversight of Bakken Field pipelines (Intense public scrutiny due to commodity characteristics) Get Better at II, IA and tweak process – Better not great Finish CRMs and DIMP - COMPLETED Do more IMP validations in field (mandated by HQ) Moving to Next Level of IMP (Focus on Prevention and Mitigation Measures)

7 Incidents Continue to Set Pipeline Safety Agenda
Integrity Management Regulations prompted by: Olympic Pipeline Rupture in Bellingham, WA (6/10/99) El Paso Pipeline Explosion in Carlsbad, NM (8/19/00) PG&E Pipeline Fire in San Bruno, CA (9/9/10) SCADA/CRM, remote valves, and Leak detection prompted and/or reinforced by the above and the more recent failures Enbridge Pipeline Spill in Marshall, MI (7/25/10) Chevron Pipeline Spills (Salt Lake City) June/Dec 2010 Exxon/Mobil Spill into Yellowstone River (7/1/11) Bellingham, 3 dead; 3rd party damage, 16 inch El Paso 12 dead Thus, water and contaminants such as chlorides, O2, CO2, and H2S all likely contributed to the observed corrosion damage. The Safety Board therefore concludes that the corrosion that was found in line 1103 at the rupture site was likely caused by a combination within the pipeline of microbes and such contaminants as moisture, chlorides, O2, CO2, and H2S. ; PG&E 8 dead, 70 homes, 30 inch pipeline, couldn’t shut valves Marshall, MI – BBLs into Kalamazoo River

8 2013/2014 Accidents – High Profile
Recent Accidents and Near Misses: 7/2/13 – P66 Seminoe P/L, Crow Nation, Wyoming 9/10/14 – Alyeska failure of encapsulation, MP 38 3/31/14 – Plymouth, WA LNG Plant –WUTC (lead) and PHMSA investigating

9 P66 Seminoe Pipeline Spill Crow Nation near Lodge Grass, MT July 2, 2013
Compression and buckling of 8-inch refined products line resulted in 600 BBLs released on to Crow Nation land Crow Nation cooperative but demanding of P66. Wanted routine updates from PHMSA Terrain was hilly but not particularly steep, evidence of soil movement No CAO issued due to fast response by operator and couldn’t add anything

10 Crow Nation Rupture – Rolling Hills

11 P66 Actions Taken Replaced 500 feet of pipe.
Relieved stress on over 4000 feet of pipe based on Geotechnical Engineer evaluation. Installed additional strain gauges in the area of the failure post stress relief and monitor for a year to validate if there was movement. Stand up test to ensure no other seepers in area. Perform weekly aerial patrols on pipeline until the completion of a deformation/strain tool and other slope movement areas remediated.

12 Seminoe Pipeline Lesson Learned
Ground movement doesn’t need to be a sudden catastrophic slope failure to fail pipe ILIs should be selected to look for deformation, ovality, and wrinkles caused by ground movement Remember to treat incidents on Sovereign Nations differently Companies must consider land movement and water crossings in their IMP preventative and mitigative measures.

13 Alyeska Vent Encapsulation Failure September 2013
Large 10-inch diameter coupon of carrier pipe found in Valdez Back Pressure Valve Recent ILI data showed that it had come from recently installed vent encapsulation over 400 miles to north No release but encapsulation and hole sleeved. It appears epoxy in sleeve expanded and pushed carrier pipe inwards Over 100 of these had been put on during previous 2 years Simulated encapusulation in Fairbanks yard failed Issued Order to investigate other encapsulations on pipe requiring additional testing, ILI runs, and repairs

14 Vent Encapsulation Photos

15 Sleeved encapsulation at MP 385.77

16 Lesson Learned Don’t use untried methods of repair that don’t follow manufacturers guidelines. Need boots on ground – neither us or JPO knew these were being put on.

17 P66 Spill “Out of Service” Pipeline Spill Wilmington, CA – March 17, 2014
On March 17, 2014, Phillips (P66) is notified by emergency responders of crude oil leaking up from below pavement in a residential area of Wilmington, California. While leak was close to a P66 Wilmington refinery, they didn’t think it was theirs.

18 P66 Wilmington, CA spill On March 18th, P66 excavated the leaking pipeline and determined it was actually their line. P66 had purchased the pipeline from the previous operator in P66 thought it had been properly abandoned and purged prior to their purchase. The leaking pipeline was a 10-inch diameter, 0.25 inch thick wall, carbon steel pipe installed in The cause of failure was an internal “pinhole” corrosion leak on a weld. P66 estimates that 39 barrels of crude oil was released and recovered. Estimated property damage reported $400,900.

19 Lesson Learned Pipelines are either active or abandoned. There is no “out of service” or “idled” designation for pipelines under Parts 192 or 195. Even if the previous operator says lines were abandoned make sure you review how it was done and confirm it is actually isolated, cleaned and purged. Treat idled lines like active lines under IMP. California Congresswoman may propose legislation clarifying and confirming status of pipelines.

20 Williams LNG Facilty Plymouth, WA – March 31, 2014

21 Lesson Learned Look at pre-liquefaction processes or any processes that could affect LNG facility Evacuation zones are much wider than is common knowledge Change must be focus, e.g. this plant had had its adsorbers recently overhauled Good State Agents Garner Public Confidence and are Priceless to PHMSA (WUTC will cover in more detail)

22 Accidents w/ Oversight Impact July 2011- June 2013
Exxon Mobil Silvertip Pipeline Spill – July 1, 2011 TransCanada Bison Pipeline Rupture – July 20, 2012 Chevron Willard Bay, Utah Spill – March 2013

23 Exxon Mobil Pipeline Spill July 1, 2011
Exxon Mobil Pipeline spills 1500 BBLs into Yellowstone River during record flooding. CAO issued 7/5 to take out of service until they put HDD under Yellowstone River, did water crossing surveys and remediation, rework SCADA training and abnormal operating procedures.

24 ExxonMobil Silvertip – July 2011

25 Preliminary Findings ExxonMobil Silvertip pipeline released estimated 1500 barrels of crude oil into the Yellowstone River near Laurel, Montana; Est. $42M damages River scour is cause of ruptured pipeline EMPL was aware of the flood conditions EMPL detected pressure drop at river and shut pipeline pumps down in 7 minutes Despite having numerous remote actuated valves at rivers, controllers took 56 minutes after first alarm to close valve adjacent to river allowing crude oil to drain into the river

26 Montana Governor’s Task Force
Reason for Study: As a result of the July 2, 2011 crude oil spill into the Yellowstone River, ensure the integrity of petroleum pipelines at major water crossings that affect rivers in Montana. Primary Purpose: Collaborate with State of Montana to compile an inventory of petroleum pipelines at water crossings and determine if they are currently safe.

27 Other Purposes of Survey and Lessons Learned
Determine if additional steps are required before Spring 2012 run off. Determine adequacy of pipeline operators’ patrolling methods and remedial actions at water crossings Develop recommendations regarding: Enhance PHMSA inspection guidance to ensure operators are meeting all aspects of regulations, particularly with respect to protecting their pipelines from water-related damage. Identify possible regulatory changes to PHMSA leadership expanding the requirements for water crossings.

28 TransCanada Bison Rupture Near Gillette, WY July 20, 2012
Pipeline ruptured within 6 months of being put into service Pipeline was first pipeline to be put into service using the Alternative MAOP regulation CAO issued on 7/21 requiring DCVG, completion of ILI run and remediation digs. Metallurgical analysis

29 Bison Pipeline Rupture – 7/20/11

30 TransCanada Lesson Learned
Pipeline companies still need to ensure there is good quality control during all phases of construction. The defect can manifest itself before the baseline pig run, in this case 6 months, can be analyzed Happened within a few days after being smart pigged DCVG revealed other areas of “lowering in” damage. Relative low Charpy value in steel (still met API 5L)

31 Chevron Pipeline Spill March 18, 2013
Chevron Products Pipeline spilled 500+ BBLs adjacent to Willard Bay due to corrosion near longitudinal seam split on Low Frequency ERW pipe. CAO issued 3/22 to reduce pressure, hydrotest LFERW pipeline in area of Willard Bay, notify emergency responders and stakeholders during start up, and conduct metallurgical examination of failed pipe. Will expand CAO scope based on these findings.

32 Chevron Northwest Products _ Willard Bay, UT – March 2013

33 Lesson Learned Ensure that IMP program reflects all of line pipe
Match up alignment sheets with corporate IMP plans Just because LFERW has not failed doesn’t mean it’s not seam susceptible Spike Hydros do have place Can not communicate enough – Keep logs of contacts

34 Older Accidents w/ Oversight Impact June 2010- June 2011
Major Accidents: Bridger Lake Spill April 2010 Chevron Crude Oil Spill June 2010 Chevron Crude Oil Spill in December 2010 Alyeska PS9 Tank Overfill in May 2010 Alyeska PS1 Corrosion Leak at PS1 in January 2011 PG&E San Bruno, CA explosion in September 2010

35 Pipeline Spill April 5, 2010 Unknown crude oil line spills 2000 BBL near Mt View, WY CAO issued 4/28 to take out of service until O&M, OQ, and ILI conducted. Tank allowed to come back into service.

36 Lessons Learned Inspectors missed this pipeline by not looking around for new pipelines when in the area Check out pipeline facilities in person; we called about this one and took operator’s word of regulatory exemption without verifying

37 Another High Profile Accident in Alaska
Alyeska Pump Station (PS) 9 – May 25, 2010 Overfilled Breakout Tank at PS 9 5000 BBLs spilled out vents and into containment area. Failed Unit Power System (UPS) prevented communications, tank monitoring and valve control. Tank appears to be damaged. Issued a CAO requiring full time monitoring at PS9 and staffing by OQ personnel at site. Verification that pipeline could operate without PS 9 relief.

38 Photo of Alyeska Spill

39 Lessons Learned Maintain Close Working Relationship with State and Federal OSCs Move Fast – Have an Enforcement Strategy to Move Quickly Focus on Change During Inspections Ensure Operators have Some or Sufficient Qualified Individuals Present During All Maintenance Operations

40 Chevron – Salt Lake City, June 12, 2010
Approx 750 BBL of crude spill into Salt Lake City creeks and small lakes on June 11/12, 2010. Power company built substation immediately adjacent to pipeline. Fence post directly on top of pipeline. Fault current burned dime sized hole in pipeline.

41 Damaged Pipe - Salt Lake City, June 12, 2010

42 Lesson Learned Roll quick and get there quick
Personal experience is to lean into it Put someone embedded in Unified Command during High Profile Accidents Just because you are talking to Operator and FOSC doesn’t mean your message is getting out; Goes better when people know someone is in charge (people want to be in loop) Keep State Partner informed first Work with Mayors or County Commissioners Volunteer to Speak at Community Meetings Talk to Congressman

43 Lesson Learned We need to spend more time on the right of way
AC and fault current mitigation not being looked at hard enough ROW patrol methods are not appropriate for terrain or foliage cover Prediction – Rulemaking for remote valve actuation, or stronger focus on the preventative and mitigative part of IMP

44 Salt Lake City, Utah – December 1, 2010

45 Salt Lake City, Utah – December 1, 2010

46 Lesson Learned Don’t have a release in same area after remedial actions Make sure that the operators fix or your remedial actions didn’t introduce other risks Outreach needs to be even greater – Now regulator’s ability is in question. Figure out someway to give other stakeholder input Worked with Mayor’s consultant Realize that even then, you need to give local officials some credible input – valve placement planning, extra time.

47 Alyeska Pump Station 1 January 8, 2011
A crude oil release was discovered on the Trans-Alaska Pipeline (TAPS) at Pump Station #1 (PS1). The leak source was from below ground piping that led to the basement of the of booster pump building. The piping was encased in concrete and could not be accessed. The TAPS could not be operated without the booster pumps so the entire pipeline system needed to be shutdown to stop the leak and enact the repairs.

48 Alyeska Pump Station 1 Cold weather and lowering crude oil temperatures within the TAPS pipeline became a serious concern. If the temperature on TAPS got much below freezing on other sections of the 800-mile long pipeline, or on idled North Slope production lines, there was a strong possibility of other crude oil releases occurring during the shutdown period or after eventual restart of the systems

49 Alyeska Lesson Learned
PHMSA needs inspectors to focus more on station piping during IMP inspections. Sync up expectations with other responders; in this case we were lucky to have a long standing relationship where we were comfortable recommending line be restarted with leak. Sometimes it is better to let someone else take lead and work behind scenes.

50 San Bruno, CA - September 9, 2010

51 PG&E, San Bruno, CA September 9, 2010
30 inch gas transmission pipeline in dense suburb Ruptured at 6:11 pm during rush hour 8 fatalities, over 50 injuries 38 homes destroyed Over an hour to close two valves less than a 1 ½ miles apart Grandfathered Pipelines (1948 and 1956) – No hydro PG&E used Direct Assessment

52 Lesson Learned Feds and State Need to support each other -
Gas IMP rule is interpreted differently by different operators, States, and Feds NTSB doesn’t conduct investigations – they coordinate Helps if you have a strong enforcement record with operator in past Direct Assessment is being misapplied – many companies do not know what they have in ground Western Region had many small operators that had not gone through and IMP review in CA.

53 Integrated Inspections
System approach – contiguous, same vintage, same risks, one or more inspection units Heavy focus on Preparation to determine what to ask prior to inspections Tap multiple experts Data driven approach to determine where we focus our inspection resources Are beginning to find common precursors to recent incidents, e.g. hydraulic changes, parallel structures, AC interference, type of assessment

54 Integrated Inspection
Time consuming and labor intensive – taking 6 to 15 months from start to finish Teams are hard to assemble and coordinate Operators are complaining about time to conduct Staff committed to inspections for months – lose management ability to re deploy staff Concerns that if we wait too long to conduct periodic inspections that operator will backslide Inconsistency on II approach between regions needs to be reduced further

55 Questions?

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