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




          3
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
Natural Gas Pipeline Safety Act: 1968
                                                         Regulations Effective Date: 1970




Source: Oil Pipeline Characteristics and Risk Factors:
Illustrations from the Decade of Construction, 2001
                                             5
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 195.452
                                 Industry Reference API 1162

         Dec 15, 2003      ● Gas IMP Rule – 49 CFR 192 Subpart O
                               Industry References: ASME B31.8S


Why is this   • Requirements / Standards are being adopted by other countries
Important?    • Opportunities exist to assist Operators in Integrity Management
              • Long term need for these Services

                                          6
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
Olympic Pipeline Accident – Bellingham, WA




                   8
Olympic Pipeline Accident – Bellingham, WA

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

                   Renton
                   Station
                                        9
Olympic Pipeline Accident – Bellingham, WA
                                           Event                 Tie to IMP Rule
Cherry Point
Refinery                              SCADA Upgrade      - Personal Knowledge & Training
Pipeline
                                                         - Management of Change
Rupture                                                  - Quality Assurance
               Water Treatment Plan   Pressure Rise      - Personal Knowledge & Training
                                      & Restart of P/L
                                      Damage at Water    - Threat ID – 3rd Party Damage
                                      Treatment Plant    - Preventive & Mitigative Measures
                    Whatcom Creek


                                      Smart Pig Run      - Assessment Methods
                                                         - Conducting Assessments
                                                         - Remediation
                 Valve Fails                             - Personal Knowledge & Training
                 to Open
                                      Pipeline Rupture   - Minimize Enviro / Safety Risks
                                                         - Personal Knowledge & Training

                                      Relief Valve       - Management of Change
                                      Failure            - Personal Knowledge & Training
                   Renton
                   Station
                                            10
El Paso Pipeline – Carlsbad, NM Accident




                 11
El Paso Pipeline – Carlsbad, NM Accident


                                    ● 12 Fatalities
                                    ● Cause: Internal Corrosion




Addl Ties to IMP Rule

● Threat: Internal Corrosion
● Cyclic Fatigue:
  Suspension Bridge


                               12
Similar Requirements for Gas & Liquids Pipelines

Hazardous Liquid Pipelines                                 Natural Gas Pipelines
•   49 CFR 195.452                                         •   49 CFR 192 Subpart O
•   Applicable to High Consequence Areas                   •   Applicable to High Consequence Areas
•   Industry Standard: API 1162                            •   Industry Standard: ASME B31.8S
•   Required Elements                                      •   Required Elements
     –   Identify High Consequence Areas                        –   Identify High Consequence Areas
     –   Identify Threats                                       –   Identify Threats
     –   Perform Risk Analysis                                  –   Perform Risk Analysis
     –   Prepare Assessment Plan                                –   Prepare Assessment Plan
     –   Perform Remediation                                    –   Perform Remediation
     –   Perform Continual Evaluation                           –   Perform Continual Evaluation
     –   Maintain Performance Metrics                           –   Maintain Performance Metrics
     –   Implement Preventive & Mitigative Measures             –   Implement Preventive & Mitigative Measures
     –   Utilize Management of Change                           –   Utilize Management of Change
     –   Develop Quality Assurance Program                      –   Develop Quality Assurance Program
     –   Record Keeping                                         –   Record Keeping
     –   Develop Communications Plan                            –   Develop Communications Plan



                                                      13
Key Differences Between Gas & Liquids Pipelines
 Hazardous Liquid Pipelines                               Natural Gas Pipelines
• Maximum 5 Year Assessment Cycle                        • Maximum 7 Year Assessment Cycle
• Product Characteristics                                • Product Characteristics
    –   Liquid run off based on terrain                      –   Local well defined Impact Area
    –   Potential migration in rivers and streams            –   No run off, vertical dispersion
    –   Potential groundwater contamination                  –   No impact to groundwater

• High Consequence Area Definition                       • High Consequence Area Definition
    –   Commercially Navigable Waterway                      –   Method 1: Class Location
    –   High Population Area                                 –   Method 2: Potential Impact Radius
    –   Other Populated Areas                                –   Both Methods Include: Identified Sites
    –   Usually Sensitive Areas

• Remediation Conditions                                 • Remediation Conditions
    –   Immediate                                            –   Immediate
    –   60 Days                                              –   1 Year
    –   180 Days                                             –   Monitor

• Other Considerations                                   • Other Considerations
    –   Runoff Modeling, Potential to Impact                 –   BTU Content Affects Impact Radius

                                                    14
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
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
Identification of High Consequence Areas




       HCA Methods                                      Typically Used
● 1. Class Location                                    Reduces Length
● 2. Potential Impact Circle (PIC)
● Both Include “Identified Sites”




                                     17
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
High Consequence Area – More than 20 Buildings
 Potential Impact
 Circle with more
 than 20 Buildings




                     19
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                          Outdoor Theaters
         Playgrounds                      Stadiums
         Recreational Facilities          Recreational Areas near water
         Camping Grounds                  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             General Stores
       Office Buildings                 Roller Skating Rinks
       Community Centers                4-H Facilities


c)    A Facility occupied by persons who are confined, are of impaired
      mobility, or would be difficult to evacuate
       Hospitals                        Day-Care Facilities
       Prisons                          Retirement Facilities
       Schools                          Assisted-Living Facilities


                                            20
HCA – Identified Site

  Identified Site




         PIR        PIR
                          PIR
   PIR




          21
HCA – Identified Site
      Potential Impact Radius
          PIR  0.69 pd 2

             p = 1200 psi
             d = 20-inch

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




                                                    22
Steps to a Baseline Assessment Plan

      Activity               Purpose                Plan

Threat Identification   Addresses All Threats
   & Evaluation            (9 Categories)




                         Selects Appropriate
Assessment Method        Assessment Method         Baseline
    Selection             for Each Identified   Assessment Plan
                                Threat



                              Prioritized
    Risk Analysis
                            Risk Ranking
   & Prioritization
                           of Assessments




                                 23
Threat Identification
      Prescriptive Approach                                                 Performance Based Approach
                   9 Categories                                                               21 Specific Threats
.   (a)   Time Dependent                                                         (a)   Time Dependent
1          (1)   External Corrosion                                                     (1)    External Corrosion
           (2)   Internal Corrosion                                         1           (2)    Internal Corrosion
2
           (3)   Stress Corrosion Cracking                                  2           (3)    Stress Corrosion Cracking
3
                                                                            3

    (b)   Static or Resident                                                     (b)   Static or Resident
4          (1)   Manufacturing Related Defects                                          (1)    Manufacturing Related Defects
                                                                            4
                       Defective Pipe Seam                                                          Defective Pipe Seam
                       Defective Pipe                                      5                        Defective Pipe
5          (2)   Welding / Fabrication Related                                          (2)    Welding / Fabrication Related
                       Defective Pipe Girth Weld                           6                        Defective Pipe Girth Weld
                       Defective Fabrication Weld                          7                        Defective Fabrication Weld
                       Wrinkle Bend or Buckle                              8                        Wrinkle Bend or Buckle
                       Stripped Threads / Broken           Pipe   /        9                        Stripped Threads / Broken           Pipe   /
                        Coupling Failure                                                              Coupling Failure
6          (3)   Equipment Failures                                                     (3)    Equipment Failures
                       Gasket O-ring failure                               10                       Gasket O-ring failure
                       Control / Relief Equipment Malfunction              11                       Control / Relief Equipment Malfunction
                       Seal / Pump Packing Failure                         12                       Seal / Pump Packing Failure
                       Miscellaneous                                       13                       Miscellaneous


    (c)   Time Independent                                                       (c)   Time Independent
           (1)   Third Party / Mechanical Damage                            14          (1)    Third Party / Mechanical Damage
7                      Damage by 1st, 2nd,or 3rd Parties                   15                       Damage by 1st, 2nd,or 3rd Parties
                       Previously Damaged Pipe                             16                       Previously Damaged Pipe
.                      Vandalism                                                                    Vandalism
8          (2)   Incorrect Operations – Human Error                         17          (2)    Incorrect Operations – Human Error
                       Incorrect Operations                                                         Incorrect Operations
9          (3)   Weather Related and Outside Force                          18          (3)    Weather Related and Outside Force
                       Cold Weather                                        19                       Cold Weather
                       Lightning                                           20                       Lightning
                       Heavy Rains or Floods                               21                       Heavy Rains or Floods
                       Earth Movements                                                              Earth Movements




                                                                       24
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
Risk Analysis & Prioritization



Single Threat:                                        Most Common

Riski = Pi x Ci

Pipeline Segment:
Consider All 9 Threat Categories
         9

Risk = (P1 x C1 )  (P2 x C 2 ) . (P9 x C9 )
        i 1



where:
   P = Probability of failure
   C = Consequence of failure
1 to 9 = Threat Category




                                                 26
Baseline Assessment Plan


 Risk Analysis and                                            HCA                   Assessment Method           Assessment Method
   Prioritization                                            Method                     Selection                   Selection



Risk Risk                                            Section HCA   HCA        HCA Assessment Assessment Assessment Assessment
Rank Score              Pipeline Section             Length Method ID         Miles   1         Date        2         Date
 1   4956    River Road to Griffin Tap                8.7    PIR        105   3.5     ECDA        Jan 2012        ICDA        Jan 2012
 2   3013    Brookside Station to Valve 25            9.8    PIR        65    2.4     ECDA        Mar 2012        ICDA        Mar 2012
 3   2835    Valve 27 to Raven Station                8.3    PIR        78    1.2   Press Test    Aug 2012      Spike Test    Aug 2012
 4   2530    Fairview Station to South River Valve    7.2    PIR        21    2.1    ILI - MFL    Nov 2012       Caliper      Nov 2012
 5   2298    Preston Tap to Valve 20                  6.9    PIR        107   0.9     ECDA       1st Qtr 2013     ICDA       1st Qtr 2013
 6   1756    Larkin Street Trap to Valve 13           8.4    PIR        86    1.6    ILI - MFL   2nd Qtr 2013    Caliper     2nd Qtr 2013
 7   1406    Valve 11 to Edgebrook tap                5.6    PIR        92    0.7    ILI - MFL   2nd Qtr 2013    Caliper      2nd 2013




                                                                   27
Pipeline Integrity Management Trends

         Gas Transmission Integrity Management




Assessment Miles per Year        HCA Repairs per Year

                            28
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
Recent Pipeline Integrity Developments

Pacific Gas and Electric
    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
New PHMSA Advisory Bulletins
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
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
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
Opportunities


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




           33
Edward J. Wiegele
Chief Reasons for Accidents




            35
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                    •    Construction activities include:
         •   GIS Services, database design
             and analysis                            •   Pipeline rehabilitation
         •   Data collection and as-builting         •   Pipeline take up and relay
         •   Establishing operating plans to         •   Hydrostatic testing
             keep pipelines in good working
             order                                   •   Anomaly digs (investigation and repair
                                                         work)
         •   Leveraging technology to
                                                     •   Maintenance work
             monitor and assess conditions
             real time                               •   Call out and emergency work

                                               36
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
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           Engineering
         System Risk                                    Project
         Assessments                                  Management

  Pipeline Integrity
   Assessments                                            Budget
                                                          Controls
   Operations /                   Project
   Maintenance                   Elements
                                                           ROW /
                                                          Permitting
         Repairs

       Commissioning
                                                     Procurement
         & Startup
                       Construction           Logistics
                       Management
                                       38
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
Meeting Business Goals Can Be Difficult




                  40
Assessment Method – ILI Tools

                                     Metal Loss Tools




                                                                    Transverse Field (TFI) MFL –
                                  Compression Wave Ultrasonics –   Circumferential Field for Narrow
MFL Axial Field – Indirect
                                  Liquid Coupled Direct Measure-       Axial Oriented Metal Loss
     Measurement
                                              ment



                                  Crack Detection Tools




Shear Wave Ultrasonics –           Elastic Wave – Wheel Coupled            Emat – Gas Only
    Liquid Coupled                       For Gas or Liquid




                                              41
External Corrosion Direct Assessment




                42
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
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
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
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
Excavation




      47
Evaluation of Pipe




        48
Integrity Management
Non-Destructive Evaluation (NDE)




              49
Coat and Jeep and Backfill – on to next dig




                    50
Integrity Field Repair Methods




             51
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
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
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                          Comply with Safety
 current information     Confidently validate    and Regulatory
   from anywhere         “at-risk” Locations         Laws




                                   54
Current State of Enterprise Integrity Data
                    Cloud
   Delivery Model

                    Server




                             GIS Department       Enterprise            Public
GeoEye Proprietary. © 2012
GeoEye, Inc. All Rights Reserved
                                                User Types
                                                  55
Future State of Enterprise Integrity Data
                    Cloud
   Delivery Model

                    Server




                             GIS Department          Engineering          Operations
GeoEye Proprietary. © 2012
GeoEye, Inc. All Rights Reserved
                                                      User Types
                                                      56
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. © 2012 GeoEye, Inc. All Rights Reserved
                                                     57
Confidently Validate “at-risk” Locations




                   58
Confidently Validate “at-risk” Locations
                                 Access to current 
                              imagery shows pipeline 
                                proximity to critical 
                                   infrastructure




                   59
Safety and Compliance Benefits


 Access up to date,
reliable information

                                                  Avoid fines and
                                                    penalties




                       Avoid cost and
                        negative PR



                                    60
Questions?

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Rebuilding the World's Pipeline Infrastructure

  • 1. Rebuilding the World’s Pipeline Infrastructure William J. Hoff Edward J. Wiegele Group Director , Engineering Services President, Professional Services Gulf Interstate Engineering Company Willbros Engineers (U.S.) LLC
  • 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, 2001 5
  • 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 195.452  Industry Reference API 1162 Dec 15, 2003 ● Gas IMP Rule – 49 CFR 192 Subpart O Industry References: ASME B31.8S Why is this • Requirements / Standards are being adopted by other countries Important? • 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 ● Performing Software Upgrade on SCADA Refinery Computers Pipeline ● Switched Delivery Points Rupture ● Notice pressure rise – considered normal Water Treatment Plan (actually due valve closure) ● SCADA becomes unresponsive ● Electrician takes down pump station manually Whatcom Creek ● Pressure surge backs up the line, surge relief valve fails to open ● Pressure surge causes rupture at water treatment plant (unknown) Valve Fails ● Deleted software upgrade, rebooted SCADA, to Open and restarted pipeline ● Pipeline is restarted ● Additional product is released at rupture site Renton Station 9
  • 10. Olympic Pipeline Accident – Bellingham, WA Event Tie to IMP Rule Cherry Point Refinery SCADA Upgrade - Personal Knowledge & Training Pipeline - Management of Change Rupture - Quality Assurance Water Treatment Plan Pressure Rise - Personal Knowledge & Training & Restart of P/L Damage at Water - Threat ID – 3rd Party Damage Treatment Plant - Preventive & Mitigative Measures Whatcom Creek Smart Pig Run - Assessment Methods - Conducting Assessments - Remediation Valve Fails - Personal Knowledge & Training to Open Pipeline Rupture - Minimize Enviro / Safety Risks - Personal Knowledge & Training Relief Valve - Management of Change Failure - Personal Knowledge & Training Renton Station 10
  • 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 Natural Gas Pipelines • 49 CFR 195.452 • 49 CFR 192 Subpart O • Applicable to High Consequence Areas • Applicable to High Consequence Areas • Industry Standard: API 1162 • Industry Standard: ASME B31.8S • Required Elements • Required Elements – Identify High Consequence Areas – Identify High Consequence Areas – Identify Threats – Identify Threats – Perform Risk Analysis – Perform Risk Analysis – Prepare Assessment Plan – Prepare Assessment Plan – Perform Remediation – Perform Remediation – Perform Continual Evaluation – Perform Continual Evaluation – Maintain Performance Metrics – Maintain Performance Metrics – Implement Preventive & Mitigative Measures – Implement Preventive & Mitigative Measures – Utilize Management of Change – Utilize Management of Change – Develop Quality Assurance Program – Develop Quality Assurance Program – Record Keeping – Record Keeping – Develop Communications Plan – Develop Communications Plan 13
  • 14. Key Differences Between Gas & Liquids Pipelines Hazardous Liquid Pipelines Natural Gas Pipelines • Maximum 5 Year Assessment Cycle • Maximum 7 Year Assessment Cycle • Product Characteristics • Product Characteristics – Liquid run off based on terrain – Local well defined Impact Area – Potential migration in rivers and streams – No run off, vertical dispersion – Potential groundwater contamination – No impact to groundwater • High Consequence Area Definition • High Consequence Area Definition – Commercially Navigable Waterway – Method 1: Class Location – High Population Area – Method 2: Potential Impact Radius – Other Populated Areas – Both Methods Include: Identified Sites – Usually Sensitive Areas • Remediation Conditions • Remediation Conditions – Immediate – Immediate – 60 Days – 1 Year – 180 Days – Monitor • Other Considerations • Other Considerations – Runoff Modeling, Potential to Impact – 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 Typically Used ● 1. Class Location Reduces Length ● 2. Potential Impact Circle (PIC) ● Both Include “Identified Sites” 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  Outdoor Theaters  Playgrounds  Stadiums  Recreational Facilities  Recreational Areas near water  Camping Grounds  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  General Stores  Office Buildings  Roller Skating Rinks  Community Centers  4-H Facilities c) A Facility occupied by persons who are confined, are of impaired mobility, or would be difficult to evacuate  Hospitals  Day-Care Facilities  Prisons  Retirement Facilities  Schools  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 2 p = 1200 psi d = 20-inch PIR  0.69 (1200)20 2 PIR  478 feet PIR = Radius of a Circular Area in Feet Surrounding the Point of Failure Identified Site p = Maximum Allowable Operating Pressure (MAOP) in the pipeline segment in pounds per square inch d = Nominal Diameter of the Pipeline in Inches. 22
  • 23. Steps to a Baseline Assessment Plan Activity Purpose Plan Threat Identification Addresses All Threats & Evaluation (9 Categories) Selects Appropriate Assessment Method Assessment Method Baseline Selection for Each Identified Assessment Plan Threat Prioritized Risk Analysis Risk Ranking & Prioritization of Assessments 23
  • 24. Threat Identification Prescriptive Approach Performance Based Approach 9 Categories 21 Specific Threats . (a) Time Dependent (a) Time Dependent 1 (1) External Corrosion (1) External Corrosion (2) Internal Corrosion 1 (2) Internal Corrosion 2 (3) Stress Corrosion Cracking 2 (3) Stress Corrosion Cracking 3 3 (b) Static or Resident (b) Static or Resident 4 (1) Manufacturing Related Defects (1) Manufacturing Related Defects 4  Defective Pipe Seam  Defective Pipe Seam  Defective Pipe 5  Defective Pipe 5 (2) Welding / Fabrication Related (2) Welding / Fabrication Related  Defective Pipe Girth Weld 6  Defective Pipe Girth Weld  Defective Fabrication Weld 7  Defective Fabrication Weld  Wrinkle Bend or Buckle 8  Wrinkle Bend or Buckle  Stripped Threads / Broken Pipe / 9  Stripped Threads / Broken Pipe / Coupling Failure Coupling Failure 6 (3) Equipment Failures (3) Equipment Failures  Gasket O-ring failure 10  Gasket O-ring failure  Control / Relief Equipment Malfunction 11  Control / Relief Equipment Malfunction  Seal / Pump Packing Failure 12  Seal / Pump Packing Failure  Miscellaneous 13  Miscellaneous (c) Time Independent (c) Time Independent (1) Third Party / Mechanical Damage 14 (1) Third Party / Mechanical Damage 7  Damage by 1st, 2nd,or 3rd Parties 15  Damage by 1st, 2nd,or 3rd Parties  Previously Damaged Pipe 16  Previously Damaged Pipe .  Vandalism  Vandalism 8 (2) Incorrect Operations – Human Error 17 (2) Incorrect Operations – Human Error  Incorrect Operations  Incorrect Operations 9 (3) Weather Related and Outside Force 18 (3) Weather Related and Outside Force  Cold Weather 19  Cold Weather  Lightning 20  Lightning  Heavy Rains or Floods 21  Heavy Rains or Floods  Earth Movements  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 Riski = Pi x Ci Pipeline Segment: Consider All 9 Threat Categories 9 Risk = (P1 x C1 )  (P2 x C 2 ) . (P9 x C9 ) i 1 where: P = Probability of failure C = Consequence of failure 1 to 9 = Threat Category 26
  • 27. Baseline Assessment Plan Risk Analysis and HCA Assessment Method Assessment Method Prioritization Method Selection Selection Risk Risk Section HCA HCA HCA Assessment Assessment Assessment Assessment Rank Score Pipeline Section Length Method ID Miles 1 Date 2 Date 1 4956 River Road to Griffin Tap 8.7 PIR 105 3.5 ECDA Jan 2012 ICDA Jan 2012 2 3013 Brookside Station to Valve 25 9.8 PIR 65 2.4 ECDA Mar 2012 ICDA Mar 2012 3 2835 Valve 27 to Raven Station 8.3 PIR 78 1.2 Press Test Aug 2012 Spike Test Aug 2012 4 2530 Fairview Station to South River Valve 7.2 PIR 21 2.1 ILI - MFL Nov 2012 Caliper Nov 2012 5 2298 Preston Tap to Valve 20 6.9 PIR 107 0.9 ECDA 1st Qtr 2013 ICDA 1st Qtr 2013 6 1756 Larkin Street Trap to Valve 13 8.4 PIR 86 1.6 ILI - MFL 2nd Qtr 2013 Caliper 2nd Qtr 2013 7 1406 Valve 11 to Edgebrook tap 5.6 PIR 92 0.7 ILI - MFL 2nd Qtr 2013 Caliper 2nd 2013 27
  • 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. Recent Pipeline Integrity Developments Pacific Gas and Electric 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. New PHMSA Advisory Bulletins 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 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
  • 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 • Construction activities include: • GIS Services, database design and analysis • Pipeline rehabilitation • Data collection and as-builting • Pipeline take up and relay • Establishing operating plans to • Hydrostatic testing keep pipelines in good working order • Anomaly digs (investigation and repair work) • Leveraging technology to • Maintenance work monitor and assess conditions real time • 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 Engineering System Risk Project Assessments Management Pipeline Integrity Assessments Budget Controls Operations / Project Maintenance Elements ROW / Permitting Repairs Commissioning Procurement & Startup Construction Logistics Management 38
  • 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 Transverse Field (TFI) MFL – Compression Wave Ultrasonics – Circumferential Field for Narrow MFL Axial Field – Indirect Liquid Coupled Direct Measure- Axial Oriented Metal Loss Measurement ment Crack Detection Tools Shear Wave Ultrasonics – Elastic Wave – Wheel Coupled Emat – Gas Only Liquid Coupled For Gas or Liquid 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
  • 50. Coat and Jeep and Backfill – on to next dig 50
  • 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 Comply with Safety current information Confidently validate and Regulatory from anywhere “at-risk” Locations Laws 54
  • 55. Current State of Enterprise Integrity Data Cloud Delivery Model Server GIS Department Enterprise Public GeoEye Proprietary. © 2012 GeoEye, Inc. All Rights Reserved User Types 55
  • 56. Future State of Enterprise Integrity Data Cloud Delivery Model Server GIS Department Engineering Operations GeoEye Proprietary. © 2012 GeoEye, Inc. All Rights Reserved User Types 56
  • 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. © 2012 GeoEye, Inc. All Rights Reserved 57
  • 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