Slides from a presentation by Bill Hoff, Director, Engineering Group, Gulf Interstate Engineering Company and Edward J. Wiegele, President, Professional Services, Willbros Engineers (U.S.), LLC at the 2012 International Pipeline & Offshore Contractors Association Convention in Istanbul.
Transform Your Kitchen Essential Tips for Renovations in Launceston
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
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
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
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
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
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
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
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