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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
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 Caribbean1,980 mi Western Europe & EU Countries8,318 mi Middle East8,523 mi Africa
17,039 mi Former Soviet Union-Eastern Europe35,546 mi Asia Pacific Region81,572 mi Total
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5
Natural Gas Pipeline Safety Act: 1968Regulations Effective Date: 1970
Source: Oil Pipeline Characteristics and Risk Factors: Illustrations from the Decade of Construction, 2001
Timeline of Key Events
Timeline Event1968 ● 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 OIndustry References: ASME B31.8S
6
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
Incidents Leading to Pipeline Integrity RegulationsOlympic 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
Background to Understanding US Regulations
7
Olympic Pipeline Accident – Bellingham, WA
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Whatcom Creek
Water Treatment Plan
Valve Fails to Open
Pipeline Rupture
Cherry Point Refinery
● 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
Olympic Pipeline Accident – Bellingham, WA
Renton Station
9
Whatcom Creek
Water Treatment Plan
Valve Fails to Open
Pipeline Rupture
Cherry Point Refinery
Event Tie to IMP RuleSCADA Upgrade - Personal Knowledge & Training
- Management of Change- Quality Assurance
Pressure Rise& Restart of P/L
- Personal Knowledge & Training
Damage at Water Treatment Plant
- Threat ID – 3rd Party Damage- Preventive & Mitigative Measures
Smart Pig Run - Assessment Methods- Conducting Assessments- Remediation- Personal Knowledge & Training
Pipeline Rupture - Minimize Enviro / Safety Risks- Personal Knowledge & Training
Relief Valve Failure
- Management of Change- Personal Knowledge & Training
Olympic Pipeline Accident – Bellingham, WA
Renton Station
10
El Paso Pipeline – Carlsbad, NM Accident
11
● 12 Fatalities
● Cause: Internal Corrosion
Addl Ties to IMP Rule
● Threat: Internal Corrosion
● Cyclic Fatigue: Suspension Bridge
El Paso Pipeline – Carlsbad, NM Accident
12
Hazardous Liquid Pipelines• 49 CFR 195.452• 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
Similar Requirements for Gas & Liquids Pipelines
13
• 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
• 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
Hazardous Liquid Pipelines Natural Gas PipelinesKey Differences Between Gas & Liquids Pipelines
14
Discussion of Natural Gas Pipeline Integrity Rule
● 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?
Filtering Criteria
15
Gas Transmission Pipelines
a) Identification of HCAsb) Baseline Assessment Planc) Threat Identificationd) Direct Assessment Plane) Remediationf) Continual Evaluation & Assessmentg) Confirmatory Direct Assessmenth) Preventive & Mitigative Measuresi) Performance Planj) Record Keepingk) Management of Changel) Quality Assurancem) Communications Plann) Procedure to provide risk analysis & IMP to Regulators upon requesto) Minimizing environmental / safety risks p) Identification of new HCAs
16
Gas IntegrityManagement Program
Required Program Elements
Identification of High Consequence Areas
17
HCA Methods● 1. Class Location● 2. Potential Impact Circle (PIC)● Both Include “Identified Sites”
Typically UsedReduces Length
High Consequence Areas – PIR Method
18
269.0 pdPIR
PIR = Radius of a Circular Area in FeetSurrounding the Point of Failure
p = Maximum Allowable OperatingPressure (MAOP) in the pipelinesegment in pounds per square inch
d = Nominal Diameter of the Pipeline inInches.
19
High Consequence Area – More than 20 BuildingsPotential Impact Circle with more than 20 Buildings
Identified Sites
20
(a) An Outside Area or Open Structure that is occupied by twenty (20) ormore 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 atleast five (5) days a week for ten (10) weeks in any twelve (12)-monthperiod. (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 impairedmobility, or would be difficult to evacuate Hospitals Prisons Schools
Day-Care Facilities Retirement Facilities Assisted-Living Facilities
21
HCA – Identified Site
Identified Site
PIR PIR
PIR PIR
HCA – Identified Site
22
269.0 pdPIR
PIR = Radius of a Circular Area in FeetSurrounding the Point of Failure
p = Maximum Allowable OperatingPressure (MAOP) in the pipelinesegment in pounds per square inch
d = Nominal Diameter of the Pipeline inInches.
Potential Impact Radius
220)1200(69.0PIR
feetPIR 478
p = 1200 psid = 20-inch
Identified Site
Steps to a Baseline Assessment Plan
Threat Identification& Evaluation
Addresses All Threats(9 Categories)
Baseline Assessment Plan
Assessment MethodSelection
Risk Analysis& Prioritization
Selects AppropriateAssessment Methodfor Each Identified
Threat
PrioritizedRisk Ranking
of Assessments
23
PurposeActivity Plan
Threat IdentificationPrescriptive Approach
9 CategoriesPerformance Based Approach
21 Specific Threats.123
4
5
6
7
.8
9
(a) 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
(c) Time Independent(1) Third Party / Mechanical Damage
Damage by 1st, 2nd,or 3rd 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
123
45
6789
10111213
141516
17
18192021
(a) 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
(c) Time Independent(1) Third Party / Mechanical Damage
Damage by 1st, 2nd,or 3rd 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
Assessment Method Selection
25
• 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
Risk Analysis & Prioritization
26
where:P = Probability of failureC = Consequence of failure
1 to 9 = Threat Category
Single Threat:
Riski = Pi x Ci
Pipeline Segment:Consider All 9 Threat Categories
Risk =
9
1992211 )C x (P . )C x (P )C x (P
i
Most Common
Baseline Assessment Plan
27
RiskRank
RiskScore Pipeline Section
SectionLength
HCAMethod
HCAID
HCAMiles
Assessment 1
AssessmentDate
Assessment 2
AssessmentDate
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
Risk Analysis and Prioritization
Assessment Method Selection
Assessment Method Selection
HCA Method
Pipeline Integrity Management Trends
28
Gas Transmission Integrity Management
HCA Repairs per YearAssessment Miles per Year
• Remediation• Pipeline Retrofitting for Inline Inspection Tools• Direct Assessment• Hydrostatic Testing• Pipeline Replacement• Automatic Shut Off / Remote Control Valves• Preventative and Mitigative Measures
Opportunities
29
Recent Pipeline Integrity Developments
Pacific Gas and ElectricSan Bruno, CA - September 2010Natural Gas Pipeline RuptureFatalities: 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
January 10, 2011Establish 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, 2012Verification of Records• New annual reporting requirements for Gas Operators (2013)• Report progress toward verification of records• Records must be “Traceable, Verifiable, and Complete”
New PHMSA Advisory Bulletins
31
PODS – IPLOCA Work Group
32
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”
• Pipeline Data Gathering• Records Validation• MAOP Validation• Geographic Information System Development• Field Verification
Opportunities
33
Edward J. Wiegele
Chief Reasons for Accidents
35
What is Pipeline Integrity Management & Maintenance?
• 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
• 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
• Program design• Program execution
(assessments/reviews)• Follow-on engineering &
construction
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
Construction Management
Logistics
Procurement
ROW / Permitting
Engineering
Project Management
Budget Controls
Commissioning& Startup
Re-building a pipeline system requires consideration of more elements than a new construction project
Re-building a pipeline system requires consideration of more elements than a new construction project
38
Pipeline Integrity Assessments
Pipeline Integrity Assessments
System Risk AssessmentsSystem Risk Assessments
Pipeline GIS Mapping and
Records
Pipeline GIS Mapping and
Records
Operations / MaintenanceOperations / Maintenance
RepairsRepairs
Project ElementsProject
Elements
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
MFL Axial Field – IndirectMeasurement
Compression Wave Ultrasonics –Liquid Coupled Direct Measure-
ment
Transverse Field (TFI) MFL –Circumferential Field for Narrow
Axial Oriented Metal Loss
Shear Wave Ultrasonics –Liquid Coupled
Emat – Gas OnlyElastic Wave – Wheel CoupledFor Gas or Liquid
41
Crack Detection Tools
Metal Loss Tools
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
• There is a defined process to determine the location of the integrity work which is influenced by and dependent on:
44
Pipeline Integrity Process – Where To Take Action
• 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
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 ManagementNon-Destructive Evaluation (NDE)
49
Coat and Jeep and Backfill – on to next dig
50
Integrity Field Repair Methods
51
• 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
Hydrotesting and Pipeline Replacements
Tracking the Work - Correcting the Data
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
Centerline AdjustmentCenterline Adjustment
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 anywhereConfidently validate “at-risk” Locations
Comply with Safety and Regulatory
Laws
54
Current State of Enterprise Integrity Data
User Types
GIS Department Enterprise Public
Del
iver
y M
odel
Ser
ver
Clo
ud
GeoEye Proprietary. © 2012 GeoEye, Inc. All Rights Reserved
55
Future State of Enterprise Integrity Data
User Types
Del
iver
y M
odel
Ser
ver
Clo
ud
GIS Department Engineering Operations
56
GeoEye Proprietary. © 2012 GeoEye, Inc. All Rights Reserved
Integrity Information Needs to be in the Hands of Operators and Service Providers
57
Access from laptops, tablets, smart
phones and other portable devices.
GeoEye Proprietary. © 2012 GeoEye, Inc. All Rights Reserved
Confidently Validate “at-risk” Locations
58
Confidently Validate “at-risk” Locations
59
Access to current imagery shows pipeline proximity to critical
infrastructure
Safety and Compliance Benefits
Access up to date, reliable information
Avoid cost and negative PR
Avoid fines and penalties
60
Questions?