Rebuilding the World s Pipeline Infrastructure

Transcription

1 Rebuilding the World s Pipeline Infrastructure William J. Hoff Group Director, Engineering Services Gulf Interstate Engineering Company Edward J. Wiegele President, Professional Services Willbros Engineers (U.S.) LLC

2 William J. Hoff

3 US Pipeline Infrastructure 3

4 International Pipelines Beyond North America Source: Pipeline & Gas Journal's Mid-Year International Pipeline Report 10,166 mi South & Central America and Caribbean 1,980 mi Western Europe & EU Countries 8,318 mi Middle East 8,523 mi Africa 17,039 mi Former Soviet Union-Eastern Europe 35,546 mi Asia Pacific Region 81,572 mi Total 4

5 Natural Gas Pipeline Safety Act: 1968 Regulations Effective Date: 1970 Source: Oil Pipeline Characteristics and Risk Factors: Illustrations from the Decade of Construction,

6 Timeline of Key Events Timeline Event 1968 US Passes Natural Gas Pipeline Safety Act Pipeline Safety Provisions Become Law 1970 Gas Pipeline Safety Regulations Developed Effective Date for All Gas Operators 1979 US Passes Hazardous Liquid Pipeline Safety Act For All US Liquid Operators Dec 1, 2000 Liquids IMP Rule 49 CFR Industry Reference API 1162 Dec 15, 2003 Gas IMP Rule 49 CFR 192 Subpart O Industry References: ASME B31.8S Why is this Important? Requirements / Standards are being adopted by other countries Opportunities exist to assist Operators in Integrity Management Long term need for these Services 6

7 Background to Understanding US Regulations Incidents Leading to Pipeline Integrity Regulations Olympic Pipeline Bellingham Washington - June 1999 Gasoline Pipeline Rupture Fatalities: 3 young boys El Paso Pipeline Carlsbad, New Mexico - August 2000 Natural Gas Pipeline Rupture Fatalities: 12 7

8 Olympic Pipeline Accident Bellingham, WA 8

9 Olympic Pipeline Accident Bellingham, WA Cherry Point Refinery Pipeline Rupture Water Treatment Plan Whatcom Creek Valve Fails to Open Performing Software Upgrade on SCADA Computers Switched Delivery Points Notice pressure rise considered normal (actually due valve closure) SCADA becomes unresponsive Electrician takes down pump station manually Pressure surge backs up the line, surge relief valve fails to open Pressure surge causes rupture at water treatment plant (unknown) Deleted software upgrade, rebooted SCADA, and restarted pipeline Pipeline is restarted Additional product is released at rupture site Renton Station 9

10 Olympic Pipeline Accident Bellingham, WA Cherry Point Refinery Pipeline Rupture Event SCADA Upgrade Tie to IMP Rule - Personal Knowledge & Training - Management of Change - Quality Assurance Water Treatment Plan Whatcom Creek Pressure Rise & Restart of P/L Damage at Water Treatment Plant - Personal Knowledge & Training - Threat ID 3 rd Party Damage - Preventive & Mitigative Measures Valve Fails to Open Smart Pig Run Pipeline Rupture - Assessment Methods - Conducting Assessments - Remediation - Personal Knowledge & Training - Minimize Enviro / Safety Risks - Personal Knowledge & Training Renton Station Relief Valve Failure 10 - Management of Change - Personal Knowledge & Training

11 El Paso Pipeline Carlsbad, NM Accident 11

12 El Paso Pipeline Carlsbad, NM Accident 12 Fatalities Cause: Internal Corrosion Addl Ties to IMP Rule Threat: Internal Corrosion Cyclic Fatigue: Suspension Bridge 12

13 Similar Requirements for Gas & Liquids Pipelines Hazardous Liquid Pipelines 49 CFR Applicable to High Consequence Areas Industry Standard: API 1162 Required Elements Identify High Consequence Areas Identify Threats Perform Risk Analysis Prepare Assessment Plan Perform Remediation Perform Continual Evaluation Maintain Performance Metrics Implement Preventive & Mitigative Measures Utilize Management of Change Develop Quality Assurance Program Record Keeping Develop Communications Plan Natural Gas Pipelines 49 CFR 192 Subpart O Applicable to High Consequence Areas Industry Standard: ASME B31.8S Required Elements Identify High Consequence Areas Identify Threats Perform Risk Analysis Prepare Assessment Plan Perform Remediation Perform Continual Evaluation Maintain Performance Metrics Implement Preventive & Mitigative Measures Utilize Management of Change Develop Quality Assurance Program Record Keeping Develop Communications Plan 13

14 Key Differences Between Gas & Liquids Pipelines Hazardous Liquid Pipelines Maximum 5 Year Assessment Cycle Product Characteristics Liquid run off based on terrain Potential migration in rivers and streams Potential groundwater contamination High Consequence Area Definition Commercially Navigable Waterway High Population Area Other Populated Areas Usually Sensitive Areas Remediation Conditions Immediate 60 Days 180 Days Other Considerations Runoff Modeling, Potential to Impact Natural Gas Pipelines Maximum 7 Year Assessment Cycle Product Characteristics Local well defined Impact Area No run off, vertical dispersion No impact to groundwater High Consequence Area Definition Method 1: Class Location Method 2: Potential Impact Radius Both Methods Include: Identified Sites Remediation Conditions Immediate 1 Year Monitor Other Considerations BTU Content Affects Impact Radius 14

15 Discussion of Natural Gas Pipeline Integrity Rule Filtering Criteria Gas Transmission Pipelines Is the pipeline system subject to 49 CFR 192? Does it have Transmission Pipe per 192.3? Have High Consequence Areas been identified on the system? 15

16 Gas Integrity Management Program Required Program Elements a) Identification of HCAs b) Baseline Assessment Plan c) Threat Identification d) Direct Assessment Plan e) Remediation f) Continual Evaluation & Assessment g) Confirmatory Direct Assessment h) Preventive & Mitigative Measures i) Performance Plan j) Record Keeping k) Management of Change l) Quality Assurance m) Communications Plan n) Procedure to provide risk analysis & IMP to Regulators upon request o) Minimizing environmental / safety risks p) Identification of new HCAs 16

17 Identification of High Consequence Areas HCA Methods 1. Class Location 2. Potential Impact Circle (PIC) Both Include Identified Sites Typically Used Reduces Length 17

18 High Consequence Areas PIR Method PIR 0.69 pd 2 PIR = Radius of a Circular Area in Feet Surrounding the Point of Failure p = Maximum Allowable Operating Pressure (MAOP) in the pipeline segment in pounds per square inch d = Nominal Diameter of the Pipeline in Inches. 18

19 High Consequence Area More than 20 Buildings Potential Impact Circle with more than 20 Buildings 19

20 Identified Sites (a) An Outside Area or Open Structure that is occupied by twenty (20) or more persons on at least 50 days in any twelve (12)-month period. (The days need not be consecutive.) Beaches Playgrounds Recreational Facilities Camping Grounds Outdoor Theaters Stadiums Recreational Areas near water Areas Outside a Religious Facility b) (b) A Building that is occupied by twenty (20) or more persons on at least five (5) days a week for ten (10) weeks in any twelve (12)-month period. (The days and weeks need not be consecutive.) Religious Facilities Office Buildings Community Centers General Stores Roller Skating Rinks 4-H Facilities c) A Facility occupied by persons who are confined, are of impaired mobility, or would be difficult to evacuate Hospitals Prisons Schools Day-Care Facilities Retirement Facilities Assisted-Living Facilities 20

21 HCA Identified Site Identified Site PIR PIR PIR PIR 21

22 HCA Identified Site Potential Impact Radius PIR 0.69 pd p = 1200 psi d = 20-inch 2 PIR (1200)20 PIR 478 feet PIR = Radius of a Circular Area in Feet Surrounding the Point of Failure p = Maximum Allowable Operating Pressure (MAOP) in the pipeline segment in pounds per square inch Identified Site d = Nominal Diameter of the Pipeline in Inches. 22

23 Steps to a Baseline Assessment Plan Activity Purpose Plan Threat Identification & Evaluation Addresses All Threats (9 Categories) Assessment Method Selection Selects Appropriate Assessment Method for Each Identified Threat Baseline Assessment Plan Risk Analysis & Prioritization Prioritized Risk Ranking of Assessments 23

24 Threat Identification (a) Prescriptive Approach 9 Categories Time Dependent (1) External Corrosion (2) Internal Corrosion (3) Stress Corrosion Cracking Performance Based Approach (a) 21 Specific Threats Time Dependent (1) External Corrosion (2) Internal Corrosion (3) Stress Corrosion Cracking (b) Static or Resident (1) Manufacturing Related Defects Defective Pipe Seam Defective Pipe (2) Welding / Fabrication Related Defective Pipe Girth Weld Defective Fabrication Weld Wrinkle Bend or Buckle Stripped Threads / Broken Pipe / Coupling Failure (3) Equipment Failures Gasket O-ring failure Control / Relief Equipment Malfunction Seal / Pump Packing Failure Miscellaneous (b) Static or Resident (1) Manufacturing Related Defects Defective Pipe Seam Defective Pipe (2) Welding / Fabrication Related Defective Pipe Girth Weld Defective Fabrication Weld Wrinkle Bend or Buckle Stripped Threads / Broken Pipe / Coupling Failure (3) Equipment Failures Gasket O-ring failure Control / Relief Equipment Malfunction Seal / Pump Packing Failure Miscellaneous (c) Time Independent (1) Third Party / Mechanical Damage Damage by 1 st,2 nd,or 3 rd Parties Previously Damaged Pipe Vandalism (2) Incorrect Operations Human Error Incorrect Operations (3) Weather Related and Outside Force Cold Weather Lightning Heavy Rains or Floods Earth Movements (c) Time Independent (1) Third Party / Mechanical Damage Damage by 1 st,2 nd,or 3 rd Parties Previously Damaged Pipe Vandalism (2) Incorrect Operations Human Error Incorrect Operations (3) Weather Related and Outside Force Cold Weather Lightning Heavy Rains or Floods Earth Movements 24

25 Assessment Method Selection Inline Inspection Metal Loss Tools Crack Detection Tools Caliper / Geometry Tools Pressure Test 49 CFR 192 Subpart J Pressure Test Spike Test Direct Assessment External Corrosion Direct Assessment Internal Corrosion Direct Assessment Stress Corrosion Cracking Direct Assessment Other Approved Technology 25

26 Risk Analysis & Prioritization Single Threat: Most Common Risk i = P i x C i Pipeline Segment: Consider All 9 Threat Categories Risk = (P1 x C 1) (P2 x C2).(P9 x C9) where: P = Probability of failure C = Consequence of failure = Threat Category 1 to 9 9 i 1 26

27 Baseline Assessment Plan Risk Analysis and Prioritization HCA Method Assessment Method Selection Assessment Method Selection Risk Rank Risk Score Pipeline Section Section Length HCA Method HCA ID HCA Miles Assessment 1 Assessment Date Assessment 2 Assessment Date River Road to Griffin Tap 8.7 PIR ECDA Jan 2012 ICDA Jan Brookside Station to Valve PIR ECDA Mar 2012 ICDA Mar Valve 27 to Raven Station 8.3 PIR Press Test Aug 2012 Spike Test Aug Fairview Station to South River Valve 7.2 PIR ILI - MFL Nov 2012 Caliper Nov Preston Tap to Valve PIR ECDA 1 st Qtr 2013 ICDA 1 st Qtr Larkin Street Trap to Valve PIR ILI - MFL 2 nd Qtr 2013 Caliper 2 nd Qtr Valve 11 to Edgebrook tap 5.6 PIR ILI - MFL 2 nd Qtr 2013 Caliper 2 nd

28 Pipeline Integrity Management Trends Gas Transmission Integrity Management Assessment Miles per Year HCA Repairs per Year 28

29 Opportunities Remediation Pipeline Retrofitting for Inline Inspection Tools Direct Assessment Hydrostatic Testing Pipeline Replacement Automatic Shut Off / Remote Control Valves Preventative and Mitigative Measures 29

30 Pacific Gas and Electric Recent Pipeline Integrity Developments San Bruno, CA - September 2010 Natural Gas Pipeline Rupture Fatalities: 8 National Transportation Safety Board (NTSB) Probable Cause Inadequate Quality Assurance during a pipeline relocation Inadequate Pipeline Integrity Management Program Incomplete and inaccurate pipeline information Did not consider the design & materials in risk assessment Failed to consider welded seam cracks in risk assessment Assessment method was unable to detect welded seam defects Integrity Program reviews were superficial - No Improvements made 30

31 January 10, 2011 Establish MAOP using Record Evidence Perform detailed Threat and Risk Analysis Use accurate data especially to determine MAOP Use Risk Analysis: Assessment Selection Preventive & Mitigative Measures May 7, 2012 New PHMSA Advisory Bulletins Verification of Records New annual reporting requirements for Gas Operators (2013) Report progress toward verification of records Records must be Traceable, Verifiable, and Complete 31

32 PODS IPLOCA Work Group Formed to: Develop Industry Standards Data Standards for New Pipeline Construction Data structure specifically designed for Design & Construction Improved data management over entire life cycle Common format for data and metadata Material tracking and traceability As-built survey / progress tracking during construction Common database deliverable to Operator Ability to assure data is Traceable, Verifiable, and Complete 32

33 Opportunities Pipeline Data Gathering Records Validation MAOP Validation Geographic Information System Development Field Verification 33

34 Edward J. Wiegele

35 Chief Reasons for Accidents 35

36 What is Pipeline Integrity Management & Maintenance? Program design Program execution (assessments/reviews) Follow-on engineering & construction Engineering activities include: IMP design & O&M manual development Risk analysis System integrity validation and assessment ILI program design and implementation GIS Services, database design and analysis Data collection and as-builting Establishing operating plans to keep pipelines in good working order Leveraging technology to monitor and assess conditions real time Construction activities include: Pipeline rehabilitation Pipeline take up and relay Hydrostatic testing Anomaly digs (investigation and repair work) Maintenance work Call out and emergency work 36

37 Why is this important? With the stringent regulations in US, the market for pipeline construction on existing pipelines and facilities is expanding at a rapid rate In global markets where there are few regulations related to integrity, the existing infrastructure will need attention This market will grow world wide, and if the incident rate increases it will accelerate 37

38 Work to Re-Build the Pipeline Infrastructure Re-building a pipeline system requires consideration of more elements than a new construction project Pipeline GIS Mapping and Records System Risk Assessments Engineering Project Management Pipeline Integrity Assessments Operations / Maintenance Repairs Project Elements Budget Controls ROW / Permitting Commissioning & Startup Construction Management 38 Logistics Procurement

39 Challenges to gaining clear, timely visibility into pipeline integrity Traditional pipeline integrity analysis process Disparate systems and data Dated views of assets Uneven field data updates No single version of the truth Repairs not tracked 39

40 Meeting Business Goals Can Be Difficult 40

41 Assessment Method ILI Tools Metal Loss Tools MFL Axial Field Indirect Measurement Compression Wave Ultrasonics Liquid Coupled Direct Measurement Transverse Field (TFI) MFL Circumferential Field for Narrow Axial Oriented Metal Loss Crack Detection Tools Shear Wave Ultrasonics Liquid Coupled Elastic Wave Wheel Coupled For Gas or Liquid Emat Gas Only 41

42 External Corrosion Direct Assessment 42

43 Assessing Unpiggable Pipelines through Direct Assessment The Direct Assessment Process is suitable for ECDA, ICDA and SCCDA. Data is mined or created at each step is also being provided back to GIS database to further enhance and provide an integrity driven deliverable for future risk calculations. 1) Pre-Assessment: incorporating various field and operation data gathering, data integration, and analysis and validating that DA is an acceptable assessment method 2) Indirect Inspection: combination of above ground tools and calculations to flag possible corrosion sites (calls), based on the evaluation or extrapolation of the data acquired during Pre-Assessment 3) Direct Examination: excavation and direct assessment to confirm corrosion at the identified sites, and remediation as defined in regulation 4) Post Assessment: determine if direct assessment sites are representative of the conditions of the pipeline, and what activities needs to be conducted moving forward based on the findings from the previous steps 43

44 Pipeline Integrity Process Where To Take Action There is a defined process to determine the location of the integrity work which is influenced by and dependent on: Assessment of the operating conditions of the line GIS/integrity management data analysis Results from ILI or Direct Assessments Field verification digs Environmental conditions around the line Probability of failure Consequence of failure Accuracy of data and imagery Population density 44

45 Construction work is extensive One company in the US plans to spend $1B USD/year for 10 years on an 8000 mile system Making lines piggable Hydrostatic testing Anomaly repairs from ILI runs and ECDA work Pipeline replacements Additional valves to improve shut down response times New controls systems Improvements to corrosion control systems This type of work extended around the world represents a tremendous amount of activity well into the future 45

46 Digs and Repairs The following is an example of an actual process for construction activities that are required following integrity assessments where a pipeline is in need of attention Costs to assess and repair represent a significant cost advantage over replacement of the pipeline and are preferred by most operators Repairs are less disruptive to the environment Proper assessment methods provide accurate dig and repair locations 46

47 Excavation 47

48 Evaluation of Pipe 48

49 Integrity Management Non-Destructive Evaluation (NDE) 49

50 Coat and Jeep and Backfill on to next dig 50

51 Integrity Field Repair Methods 51

52 Hydrotesting and Pipeline Replacements Strength testing is an option vs. replacement Smaller distances but multiple locations Take up and relay or offset and relay Interconnections and service disruptions are a significant issue Coordination with Owner company operations critical

53 Tracking the Work - Correcting the Data Centerline Adjustment Blue is where the centerline was moved based on surveys and the Red line is where the original centerline existed from the digitization process from the maps. The heavy set blue line is attributed to the PCM survey and was utilized to further adjust the extends of the pipeline segment. 53

54 Technology ensures improved visibility of condition of pipeline assets The operators need secure and intuitive enterprise wide access to one version of the truth. Access to accurate and current information from anywhere Confidently validate at-risk Locations Comply with Safety and Regulatory Laws 54

57 Integrity Information Needs to be in the Hands of Operators and Service Providers Access from laptops, tablets, smart phones and other portable devices. GeoEye Proprietary GeoEye, Inc. All Rights Reserved 57

58 Confidently Validate at-risk Locations 58

59 Confidently Validate at-risk Locations Access to current imagery shows pipeline proximity to critical infrastructure 59

60 Safety and Compliance Benefits Access up to date, reliable information Avoid fines and penalties Avoid cost and negative PR 60

61 Questions?