2015 NAPSR Central Region Meeting State of the State Report: Michigan

Transcription

1 2015 NAPSR Central Region Meeting State of the State Report: Michigan David Chislea Program Manager 1

2 Program Staffing Overview Number of inspectors: 8 Number of inspectors w/ 3 years or less: 6 Number of inspectors w/more than 3 less than 7: 2 Number of inspectors w/ 7 years or more: 0 2

3 Intrastate Pipeline Facilities Intrastate Gas: Transmission mileage: 5,201 Gathering mileage: Distribution mileage: 57,367 Number of services: 3,247,804 3

4 Other Intrastate Pipeline Facilities LNG Operators 0 Gathering Approx. 10,500 active natural gas wells Jurisdictional Miles Estimated non-jurisdictional Master Meter operators 0 Jurisdictional LP operators 2 Miles (regulated) Approx Services Approx

5 Interstate Agency Summary Gas Interstate Transmission: Number of operators: 7 Miles of gas transmission pipelines: 3,538 5

6 2014 Inspection Days Records 272 O&M 169 TIMP Program On-site Incident Construction CRM Remote Incident Follow-up DIMP Other

7 Inspection Day Activity O&M Records Construction On-site Incident

8 Number of Inspection Days Average Inspection Days per Inspector Inspection Days Inspection Days Days / Inspector

9 Number of Probable Violations 500 Intrastate Probable Violations Found in CY Closed in CY Open at CY End

10 Number of Compliance Actions taken in Calendar Year 120 Compliance Actions

11 Distribution Pipeline Materials 1, ,907 Plastic Steel - coated, protected Cast iron Steel - coated, unprotected Steel - bare, protected 30,569 Steel - bare, unproetected 20,939 Other Ductile iron Copper 11

12 Infrastructure Replacement Programs DTE Gas Company Main Replacement Program (MRP) Directed by Commission in 2010 to develop a long-term plan to significantly reduce amount of cast iron in DTE s system Plan approved in 2011 for a 10-year program to replace or retire 30 miles of high-risk main annually with annual expenditures of $17.1 million Increase to the size of the program approved in 2013 to replace or retire 66 miles of high-risk main annually with annual expenditures of $46.9 million through an Infrastructure Recovery Mechanism (IRM) surcharge. Pending case to increase the size of the program in 2016 and 2017 to replace or retire 123 miles of high-risk main annually with annual expenditures of $93.8 million From 2011 to 2014, 231 miles of high-risk main replaced or retired through the MRP.

13 Infrastructure Replacement Programs DTE Gas Company Meter Move Out Program (MMO) Directed by Commission in 2010 to develop a long-term plan for moving inside meters to outside locations Plan approved in 2011 for a 10-year program to relocate or remove 12,790 inside meters per year with annual expenditures of $22.7 million Scope of program changed in 2013 to impact 12,790 meters per year, including affected outside meters and included the recovery of expenditures through IRM surcharge From 2011 to 2014, 39,764 inside meters impacted through MMO and 58,138 inside meters impacted through MRP and other routine construction

14 Infrastructure Replacement Programs SEMCO Energy Main Replacement Program (MRP) Plan approved in 2011 for a program to replace 13 miles of unprotected metallic main annually with annual expenditures of $4.4 million collected through a 5-year surcharge mechanism. MRP miles are in addition to a minimum of 9 base miles through routine programs. Increase to the size and scope of the program approved in 2013 to replace 26 miles of unprotected metallic and vintage plastic main annually with expenditures of $8.7 million through the surcharge mechanism, in addition to a minimum of 14.6 base miles. Extension of the MRP approved in 2015 to continue the MRP through 2020 with average annual expenditures of $10.1 million collected through the 5-year surcharge From 2011 to 2014, 100 miles of high-risk main replaced or retired through the MRP.

15 Infrastructure Replacement Programs Consumers Energy Enhanced Infrastructure Replacement Program (EIRP) Plan approved in 2012 for a 25-year program to accelerate the replacement of high-risk main with expenditures of $56 million annually. Program includes distribution main replacement, transmission main replacement, and installation of launchers and receivers. Increase to the size of the program approved in 2014 to increase annual expenditures for the EIRP to $75 million. Program going forward excludes transmission launchers and receivers. From 2012 to 2014, miles of distribution main has been replaced, 28.5 miles of transmission main has been replaced, and an additional 253 miles of transmission pipe has been made piggable through the EIRP.

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17 Enforcement Statistics 2014 Civil Penalties Issued 0 Civil Penalties Collected 1, $90,000 (CY 2013 collected in 2014) Alternative / Equivalent Enforcement Actions Taken 1 Cost to Operator for Alternative/Equivalent Methods $0 to Operator, $160,000 to Contract Locator 17

18 Equivalent Enforcement Consumers Energy / USIC Locating Services failure to locate facilities Complaint received that the contract locator, USIC, was clearing tickets for locate requests related to invisible fences and lawn aeration Staff reviewed a sample month of tickets and found 41 tickets cleared or not responded to where gas facilities were present MPSC assessed civil penalty of $250,000 against Consumers Energy for 92 probable violations found Agreement reached where Consumers paid $90,000 penalty and USIC provided $160,000 worth of project staking services to Consumers Energy 18

19 Top Enforcement Issues in Violations of (a): Each transmission line valve that might be required during any emergency must be inspected and partially operated at intervals not exceeding 15 months, but at least once each calendar year. 17 Violations of R (b): An operator shall retain the following test record information: (b) The class location existing at the time of the test of the area in which the pipeline is located. 16 Violations of R (a): An operator shall retain the following test record information: (a) The proposed maximum operating pressure of the pipeline. 19

20 Top Enforcement Issues in Violations of (a): Establishment of MAOP; primarily associated with high-five pressure record retention. 16 Violations of (a) : Each operator shall prepare and follow for each pipeline, a manual of written procedures for conducting operations and maintenance activities and for emergency response. 20

21 Damage Prevention Statistics 2014 Total # of locate request: 799,384 Number of Pipeline Damages: 3,659 Damages per thousand tickets: 4.6 Number of violations issued: 3 under under PA 174 (damage prevention law, effective April 2014) Amount of fines collected: $0 Number 1 reason for damages? 21

22 Natural Gas Distribution Pipeline Excavation Damages 4,000 3,500 3,000 Number of Excvation Damages 2,500 2,000 1,500 1, Source: Annual Distribution Reports. Form PHMSA F

23 Number of Excavation Tickets Natural Gas Distribution Pipeline Excavation Tickets 900, , , , , , , , , Source: Annual Distribution Reports. Form PHMSA F

24 Excvation Damages per 1000 tickets Natural Gas Distribution Pipeline Damages per Ticket Michigan National Source: Annual Distribution Reports. Form PHMSA F

25 2014 Distribution Pipeline Excavation Leak Summary Mains Excavation Leaks 372 Leaks / 100 Miles of Main Services Excavation Leaks 2,741 Leaks / 1000 Services Source: 2014 Annual Distribution Reports. Form PHMSA F

26 Number of Leaks Natural Gas Distribution Pipeline Leaks Caused by Excavation Damage 3,500 3,000 2,500 2,000 1,500 Mains Services 1, Source: Annual Distribution Reports. Form PHMSA F

27 Leaks / 100 Miles of Main Natural Gas Distribution Pipeline Excavation Leaks / 100 Miles of Main Source: Annual Distribution Reports. Form PHMSA F

28 Leaks / 1000 Services Natural Gas Distribution Pipeline Excavation Leaks / 1000 Services Source: Annual Distribution Reports. Form PHMSA F

29 Significant Incidents Overview 21 incidents that met PHMSA reporting criteria (2) Corrosion Failure (2) Natural Force Damage (6) Excavation Damage (3) Other Outside Force Damage (6) Equipment Failure (2) Incorrect Operation $9,286,634 in reported property damage MMCF gas released unintentionally 9 Injuries 0 Fatalities

30 Significant Incidents Corrosion Failure Description Cause as determined by state if known Preventable? Yes/No F I Gas Lost (MMCF) Cost Pipeline leak Pipeline rupture A leak detected on a 10-inch steel pipeline in a storage field was found to be a hole in the girth weld caused by internal corrosion. Rupture of 22-inch transmission line caused stress corrosion cracking $88, $3,150,000 30

31 Significant Incidents Natural Force Damage Description Cause as determined by state if known Preventable? Yes/No F I Gas Lost (MMCF) Cost Release of gas Structure fire Pilot sensing vale froze due to cold weather conditions, causing valve to actuate Ice and snow buildup on the roof of structures slid off and struck the gas meter, resulting in the release of gas that migrated into the structure and ignited $ $52,290 31

32 Significant Incidents Excavation Damage Description House fire Third-party damage Third-party damage on transmission system First-party damage Third-party damage Third-party damage Cause as determined by state if known Preventable? Yes/No Leak on a 2-inch steel main was determined to have been previously damaged during the installation of a water main. An electrical contractor damaged the 6-inch distribution main. Facilities were marked, but it has not been determined if markings and excavation practices were adequate. An excavator operating a tile trencher damaged a 20- inch transmission pipeline. A locate request ticket was submitted, but excavation began prior to the start date of the ticket; the facilities were not marked. Backhoe operator damaged a steel service line. The facility was marked correctly, but the excavator failed to use hand tools where required. A farmer removing stumps with an excavator damaged an 8-inch distribution main. A locate request ticket was not submitted; the excavator was aware of the pipeline, but assumed the cover to be deeper than it actually was. A contractor directional boring telecommunication facilities damaged a 6-inch steel main. Locate tickets were submitted and completed; the likely cause of damage was determined to be inadequate markings. F I Gas Lost (MMCF) Cost $112, $74, $280, $ $150, $63,904 32

33 Significant Incidents Other Outside Force Damage Description Cause as determined by state if known Preventable? Yes/No F I Gas Lost (MMCF) Cost House fire House explosion Leak on service line caused a house fire. The cause of the leak was determined to be electrical arcing between the service line and a grounding cable. A locked service valve at the meter that was broken indicated that unauthorized use of gas had occurred; source of ignition is undetermined $52, $33,348 Building explosion A vehicle struck and damaged a meter manifold $52,236 33

34 Significant Incidents Equipment Failure Description Overpressure event Release of gas Fire at compressor station Overpressure events on distribution and transmission pipelines Overpressure and release of gas Over odorization of gas Cause as determined by state if known Preventable? Yes/No Malfunction of pilot valve, in part due to cold weather conditions. A fire sensor detected an event and triggered the ESD. Blowdown valves did not operate properly and required manual operation to isolate station. Check valve failure for the dehydration system reboiler caused high-pressure gas to leak into glycol system, resulting in release of steam, glycol, gas, and a subsequent fire. Liquids in gas stream resulted in failure of a regulator station at a city gate, causing an overpressure event; further downstream liquids in gas stream resulted in failure of a 2 nd regulator station on the distribution system, causing an overpressure event. Debris in gas stream resulted in failure at regulator station, causing an overpressure event that resulted in venting of gas. Malfunction of computer equipment resulted in high flow signals, causing excess odorant injected into system and resulting in 610 leak complaints F I Gas Lost (MMCF) Cost $ $3, $73, $102, $586, $87,250 34

35 Significant Incidents Incorrect Operation Description Cause as determined by state if known Preventable? Yes/No F I Gas Lost (MMCF) Cost Pipeline rupture Release of gas Rupture of underground compressor station piping was caused by a mixture of air and gas during pressurization that ignited and overpressured the pipe. A company operator attempting to clear system alarms turned power off to the Uninterruptible Power Supply system at a compressor station. The loss of power to the blowdown valve solenoids caused the valves to actuate and vent gas to atmosphere $4,320, $60 35

36 Significant Incident Internal corrosion caused a leak on a storage field girth weld. Operating at 417 psig; was operating at 1350 psig 3½ months earlier.

37 Significant Incident

38 Significant Incident

39 Significant Incident

40 Significant Incident Transmission line rupture following operating pressure increase from approximately 720 to 805 psig. 200 evacuated homes Pipe characteristics: 22 pipe Coal tar enamel coating Origin: 21 feet segment of pipe installed in 1960 (pipeline constructed in 1949) Pipe wall. Saturated wet environment

41 Significant Incident

42 Significant Incident

43 Significant Incidents Operator changed gas flow through route within a station. Free Flow Conditions. Gas passed through several different sized pipe diameters. Pinch point caused ice formation. This combined with cold weather caused a relief valve to open partially. Gas release of 15 MMcf.

44 Significant Incident Snow/ice buildup on roof fell onto gas meter, causing a leak which led to ignition. Furnace located right inside wall from gas meter.

45 Significant Incident

46 Significant Incident House fire; gas leak found on main 45 from house. Fire started in downstairs utility room. Property damages $112,580. After the fire, gas was detected at an exterior building wall and inside the basement. Evidence of previous excavation damage to main.

47 Significant Incident

48 Significant Incident Third-party damage. 750 psig 20 transmission. Farmer s contractor was plowing in drain tile 4 deep. Miss Dig was called, but did not wait 3 days to start. Control Room isolated with remote control valves within minutes.

49 47,000 lb. tiling machine completely flipped over. Significant Incident

50 Significant Incident Third-party damage. 300 psig eight-inch main. Farmer was removing tree stumps with loader bucket. Incorrectly identified emergency valve failed to isolate section. Gas was blowing for approximately 18 hours.

51 Significant Incident Third-party damage Six-inch 200 psig main Horizontal directional drill Initial isolation failure Gas blowing ~29 hours 6.4 MMcf gas loss

52 Significant Incident Residential Structure Explosion Rental property was vacant and between tenants. Structure was illegally occupied and injuries ensued. Water heater and furnace were stolen after previous tenants moved out.

53 Significant Incident Unknown condition of fuel line. Lockwing valve was locked closed after previous tenants moved out. Lockwing was found to be broken and in the open position during the incident. Incident due to tampering with DOT jurisdictional facilities.

54 Significant Incident Flame sensor unit triggered compressor station ESD. One of four block valves closed and all four blowdown valves opened. Three of four block valves failed to close due to frozen pilots MMcf gas loss.

55 Significant Incident

56 Significant Incident Debris moving through distribution system caused double regulator failure. Working-monitor regulator station. Caused 139 psig pressure on a 60 psig system. 120 miles of distribution main and 7,010 gas services overpressured.

57 Significant Incident

58 Significant Incident

59 Significant Incident

60 Significant Incident

61 Significant Incident Over-odorization at gate station: NJEX falsely sensed gas flow rate increase from 300 Mcf/hr to 8 MMcf/hr 610 leak calls responded to Cost: $87,000

62 Significant Incident Pipeline rupture. 20 transmission within compressor station. Operator was purging pipeline after repair of thirdparty damage. Inadequate purging procedure allowed a combustible mixture of gas and air in the pipe.

63 Significant Incident tee found 230 away.

64 Special Permits Requested/Granted Special Permit Request Description: A waiver of compliance with the specification for plastic pipe (ASTM D 2513) Operator: WMRE of Michigan Status: MPSC Order issued approving waiver in September 2012 MPSC Staff provided notification to PHMSA Multiple requests for additional information by PHMSA in 2013 Received PHMSA statement of no objection in April 2014 Construction and testing activities completed on system in 2014 and 2015 Further system limitations and requirements agreed upon based on test results to satisfy waiver conditions

65 Workload Issues Inspector turnover. Gathering line operators require disproportionate amount of effort compared to the pipeline miles operated. 21 federally reportable incidents in 2014 requiring investigation, report generation, and non-compliance activities. Increased number of probable violations increases lag time of compliance actions. 65

66 Other State Program Concerns PHMSA TQ instructors. Staffing formula. Pending regulations. Implementation of revised Rule Suspension funds. Damage prevention position. 66

67 2014 Program Accomplishments Inspections focused on Control Room Management, gathering line determination and follow up, Integrity Management Programs, and incident investigation as necessary. Significant efforts to issue reports, violations, recommendations related to major incident investigations and complaints. Rules governing pipeline safety in Michigan were revised to incorporate federal standards into the Michigan Rules. The rules were filed with the Michigan Secretary of State on December 23,

68 2014 Program Accomplishments Staff hosted a PHMSA TQ Seminar in 2014 that was well received by pipeline operators who attended. Hiring two new inspectors to fill vacant positions due to employee attrition and program expansion. Other inspectors continued progressing toward meeting their core training requirements, with two inspectors changing from Category II to I based on their training and experience. 68

69 2014 Program Accomplishments Staff began implementation of Public Act 174 of 2013 related to Damage Prevention. Effective April 1, 2014, the MPSC became the agency responsible for enforcement of damage prevention. Staff began establishing a process for handling damage prevention complaints and collection of data related to events involving the damage of underground facilities. 69

70 2015 Outlook / Areas of Emphasis Complete Operator Qualification Plan inspections using PHMSA Form 14. Complete Integrity Management inspections for intrastate transmission line operators beginning with Protocol A and then if applicable, the entire federal inspection form. Staffing a new position for the underground damage prevention program with other pipeline safety inspection activities assigned as time allows. Continuing to implement the process for damage complaints. Collecting damage data related to incidents of underground facility damage with analysis and summary of data collected made publicly available. 70

71 2015 Outlook / Areas of Emphasis Working on promulgation of rules for the administration of PA174. Implement an updated version of the pipeline safety database program as used with Minnesota. Work on further enhancements to the pipeline safety database program, including modifications for the collection of excavation damage data and enforcement of damage prevention. Publish "Guide to the Michigan Gas Safety Standards" that incorporates the 23rd edition of the Michigan Gas Safety Standards that became effective late Continue to work toward development of a quantitative risk-based inspection process. 71

72 Any Questions?