rebuilding the world’s pipeline infrastructure - iploca · rebuilding the world’s pipeline...

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

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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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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

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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

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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


Renton Station

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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


Renton Station

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El Paso Pipeline – Carlsbad, NM Accident

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● 12 Fatalities

● Cause: Internal Corrosion

Addl Ties to IMP Rule

● Threat: Internal Corrosion

● Cyclic Fatigue: Suspension Bridge

El Paso Pipeline – Carlsbad, NM Accident

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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

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• 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

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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

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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

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Gas IntegrityManagement Program

Required Program Elements

Identification of High Consequence Areas

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

Typically UsedReduces Length

High Consequence Areas – PIR Method

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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.

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

Identified Sites

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(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

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HCA – Identified Site

Identified Site

PIR PIR

PIR PIR

HCA – Identified Site

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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

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PurposeActivity Plan

Threat IdentificationPrescriptive Approach

9 CategoriesPerformance Based Approach

21 Specific Threats.123

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5

6

7

.8

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(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

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6789

10111213

141516

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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

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Assessment Method Selection

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• 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

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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

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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



HCA Method

Pipeline Integrity Management Trends

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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

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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

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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

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PODS – IPLOCA Work Group

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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

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Edward J. Wiegele

Chief Reasons for Accidents

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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

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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

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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

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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

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Meeting Business Goals Can Be Difficult

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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

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Crack Detection Tools

Metal Loss Tools

External Corrosion Direct Assessment

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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

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• There is a defined process to determine the location of the integrity work which is influenced by and dependent on:

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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

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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

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Excavation

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Evaluation of Pipe

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Integrity ManagementNon-Destructive Evaluation (NDE)

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Coat and Jeep and Backfill – on to next dig

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Integrity Field Repair Methods

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• 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.

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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

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Future State of Enterprise Integrity Data

User Types

Del

iver

y M

odel

Ser

ver

Clo

ud

GIS Department Engineering Operations

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Integrity Information Needs to be in the Hands of Operators and Service Providers

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Access from laptops, tablets, smart

phones and other portable devices.


Confidently Validate “at-risk” Locations

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Confidently Validate “at-risk” Locations

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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

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Questions?

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