Transmission Integrity Planning Best Practices

Transcription

1 Transmission Integrity Planning Best Practices Paul Amato V.P. of Engineering, Operation, Environmental, Health and Safety Matthew Bell Engineering Specialist, Cathodic Protection

2 Company Profile Commenced Operations in 1991 Headquarters in Shelton, CT 95 employees (20 field operating personnel) 24/7 Gas Control monitoring Remote operated valve sites, meters and compressor stations Comprehensive integrity programs Extensive aerial, ground, and in-line inspection programs Primary Markets Connecticut Long Island New York City 1.6 Bcf/d Physical Receipt Capability TransCanada = 1.2 Bcf/d Algonquin = 0.4 Bcf/d Piping 414-mile of 30 and 24 pipeline MAOP = 1440 psig Pipeline Interconnects: TransCanada Dominion Tennessee (200 and 300 lines) Algonquin 7 Compressor Stations 115,900 HP

3 Class Location Pipeline miles by DOT class Location Type Length Total New York Class miles Class miles Class miles Class miles Subtotal miles Connecticut Class miles Class miles Class miles Class miles Subtotal miles Total miles A class location unit is an onshore area that extends 660ft on either side of the centreline of any continuous 1-mile length of pipeline. Class 1 an offshore area or a location that has 10 or fewer buildings intended for human occupancy Class 2 location that has more then 10 but fewer than 46 buildings intended for human occupancy Class 3 Location that has 46 or more buildings intended for human occupancy or an area where within 300 of pipeline that is occupied by 20 or more persons at least 5 days a week for 10 weeks in any 12 month period Class 4 location where buildings with 4 or more stories are prevalent

4 HCA Areas 10% of Total Mileage Pipeline miles by DOT class Location Type Length HCA New York Class miles Class miles Class miles Class miles Subtotal miles Connecticut Class miles Class miles Class miles Class miles Subtotal miles Total miles

5 Iroquois IMP Personnel-Broad Engagement Executive VP of Engineering, Operations & EH&S IMP Program Manager Director of Engineering Services Engineering Services Integrity Engineer, GIS/CAD Specialist, Corrosion Engineer Field Operations Manager, Area Manager, Field Technicians ROW Right of Way Manager Legal Corporate Communications EH&S

6 Identifying HCA 1. The area within a potential impact circle containing: I. 20 or more buildings intended for human occupancy II. An Identified site 2. Where a PIC is calculated the length of HCA extends axially along the length of the pipeline from the first and last site identified with 20 or more buildings

7 Identifying HCA

8 Identifying HCA Calculate Potential Impact Radius Example: 30 pipeline with 1440 PSI MAOP PIR = 786ft Iroquois includes a 40 buffer to account for GPS inaccuracies.

9 Identifying HCA HCA Covered Segment

10 IMP Prescriptive vs Performance Based Pipeline Integrity Regulations 49 CFR 192 Subpart O provides for two types of IMPs Prescriptive Conform to the requirements of 49 CFR 192 Subpart O without deviation. Performance Based May deviate from certain requirements provided exceptional performance can be demonstrated under its IMP. Iroquois has chosen to follow the prescriptive approach

11 Interstate Natural Gas Association of America Action Plan to Build Confidence in Pipeline Safety July 2011 Expand Risk Management beyond HCAs (100% population in PIR by 2030) Raise the Standards for Corrosion Anomaly Management Demonstrate Fitness for Service on Pre-Regulation Pipelines Shorten Pipeline Isolation Response time to One Hour Improve Integrity Management Communication and Data Implement the Pipelines and Informed Planning Alliance Guidance Evaluate, Refine and Improve Threat Assessment and Mitigation Foster a Culture of Continuous Improvement Engage Public Officials and Emergency Response

12 Inline Inspection Iroquois Main Line and 24 extension were designed to allow ILI PIG launchers and Receivers installed during original construction Three 12 laterals were modified to accommodate ILI. Two of the three laterals contained HCAs Sweeps were added to the ends of the laterals A portable PIG L&R is utilized for the 12 laterals L&R are being installed to allow ILI on 36 loop in non- HCA area.

13 Inline Inspection Tool Selection High Resolution Magnetic Flux Leakage - MFL External/Internal Metal Loss Geometry Tool Dents and Buckles only tool capable of sizing dents and buckles XYZ Tool Provides sub-meter GPS coordinates Used in conjunction with surveyed control points - AGM

14 Inline Inspection IGTS is divided into 10 sections for ILI, 8 of the 10 sections contain HCAs All HCAs have been inspected multiple times 7 year reassessment interval 99.6% of the IGTS has been inspected using ILI ILI will be complete on 100% of the piping system by 2017 (INGAA commitment 100% of people within the PIR by 2030) IGTS will continue to inspect and analyze all segments regardless if it s a HCA or non-hca. Anomalies inside and outside HCA's are evaluated with the same engineering criteria

15 ILI Tool Calibration/Confirmation Digs At least one bell hole examination is scheduled for each tool run. Confirms that the tool operated within specified tolerances. When no immediate, one year, or monitor conditions exist the excavation location is selected at the discretion of the Integrity Engineer. Consideration is given to anomaly type as well as feasibility of excavation.

16 Tool Tolerance or Corrosion Growth

17 Tool Tolerance Vs. Corrosion Growth Two inspection each with a tolerance of ±10% wt with an 80% confidence level For actual 20% wall loss pitting corrosion you can be 80% confident that the MFL tool will measure between 10% and 30% wall loss.

18 Corrosion Growth Analysis Vendor analyzed signals External corrosion feature with maximum verified corrosion growth rate of XX mils/year

19 Corrosion Growth Analysis Vendor analyzed signals External corrosion feature with no clear evidence of growth

20 Corrosion Growth Rate Accuracy Statistics stated in vendor report clamed that for two tool runs each with a ±10% wt accuracy and 80% confidence the maximum corrosion growth confidence level of 95% would require an increase in reported depth of 18% wt for a general corrosion feature.

21 Risk Modeling Iroquois utilizes a 3 rd party for risk modeling Data inputs used for risk modeling Pipe features (wall thickness, welding technique, coating ) ILI data Cathodic protection annual survey and CIS data One call data Pipeline route location HCA and Class Direct inspection results Interacting Threats Operational practices (maintenance procedures) Construction methods (onshore, offshore, HDD, ) Operating conditions (pressures, gas quality ) Consequences of failures (safety, environmental, economic)

22 Risk Modeling The model will break down the data and provide numerical probability statistics for each threat. It also determines consequential risks based off of the safety, environmental, and economic impacts. The product of the probability and consequence determines the overall risk score, per mainline valve segment. Iroquois IMP Personnel review the data to determine areas of improvement to reduce various risk elements.

23 Risk Model

24 Continuous Monitoring Monitoring for new construction, unauthorized excavation or equipment near the pipeline, sink holes or erosion. Weekly Aerial patrols where feasible Weekly line inspections when aerial patrols are not feasible Long Island and the Bronx Annual line walk and leak survey for all piping and facilities. Continuous monitoring feeds into house counts for Class Location Studies as well as identifying new HCAs.

25 Summary Iroquois has long history if Integrity Management / Continuous Improvement ILI Program continues to try and exceed regulations and best practices (good for safety and business) Due to initial construction issues, Executive commitment to safety, integrity and reshaping the perception of Iroquois