PIPELINE INTEGRITY MANAGEMENTEXTERNAL CORROSION DIRECT ASSESSMENT

API INSPECTOR PERSPECTIVE

by John T. Schmidt

John T. Schmidt

• Over thirty-seven years experience in corrosion control

and pipeline integrity

• Active member of National Association of Corrosion

Engineers – International (NACE) and serves as officer of

various committees related to pipeline integrity

• Participated in the development of the NACE Standard

Recommended Practice, “Pipeline External Corrosion

Direct Assessment Methodology”

• Instructor - “Pipeline Corrosion Integrity Management”,

NACE

PIPELINE INTEGRITY MANAGEMENTAPI INSPECTOR PERSPECTIVE

• Introduction to Pipeline Integrity

- Threats to Pipeline Integrity

• Regulations

• Standards

• Integrity Assessment Methods- Pressure Test

- Inline Inspection

- Direct Assessment* External Corrosion Direct Assessment (ECDA)

• API Inspector Roles and Responsibilities

WHY PIPELINE INTEGRITY MANAGEMENT?

PIPELINE INTEGRITY MANAGEMENT

Current regulations in the United States require

operators of onshore transmission pipelines to have

measures in place to improve safety and to allocate

resources effectively to identify potential threats that

could result in failures or incidents, analyze risks and

reduce those risks, and to ensure properly trained and

qualified operations personnel.

These regulations were mandated by the U.S. Office of

Pipeline Safety as a result of several significant pipe

failures that resulted in fatalities and/or damage to the

environment or property.

A summary of current regulations and practices will be

presented as well as timelines, and opportunities for API

inspectors.

NORTH AMERICA PIPELINE INFRASTRUCTURE

ONSHORE HAZARDOUS LIQUID PIPELINES

Pipeline Hazardous Materials Safety Administration (PHMSA)

• Regulates about 173,000 miles of hazardous liquid pipelines

• Exceptions: Onshore production, refining, or manufacturing facilities; associated storage or in-plant piping; low pressure rural gathering lines less than 6-inches diamter and not in a unusually sensitive environmental area

• 76,000 are in High Consequence Area (HCA)

• Commercially navigable waterway

• High-population area

• Other populated area

• Proposed changes to HCA definition

• Commercially navigable waterway -> “Navigable waterway” or “Waters of the United States”

• Major road crossings and/or railways

ONSHORE NATURAL GAS TRANSMISSION PIPELINES

• PHMSA regulates about 292,000 miles of gas transmission pipelines

• About 19,100 are in High Consequence Area (HCA)

• Potential Impact Radius – Death, injury, or significant property damage

• 20 or more structures intended for human occupancy

• Buildings housing populations of limited mobility

• Buildings that would be hard to evacuate

• Buildings and outside areas occupied by more than 20 persons on a specified minimum number of days each year

DISTRIBUTION PIPELINE INTEGRITY MANAGEMENT

PHMSA regulates about 2,066,000 miles of distribution mains and service pipelines

• DIMP rule published on December 4, 2009; Effective date –February 12, 2010. Integrity Management Plans by August 2, 2011

• Significant differences in system design and local conditons than transmission pipeline systems

• No HCAs – Entire pipelines

PIPELINE INTEGRITY

Pipeline integrity is the state of a pipeline with respect to public safety, environmental protection, and operational reliability.

Materials &

Construction

Defects

Corrosion &

Cracking

Mechanisms

Mechanical

Damage

Operations Earth ForcesWeather Related

Effects

Device Failures

& Malfunctions

Other

ConditionsThreats to Pipeline Integrity

REGULATIONS

• August, 1968, Pipeline Safety Act

• August, 1971, 49 CFR 192 for Natural Gas

• August, 1975, 49 CFR 195 for Hazardous Liquids

• 1997 - NACE FCW, Oakbrook IL

• Corrosion/99 – San Antonio, TX

• May, 2001, Integrity Management Rule for Liquids > 500 miles

• February, 2002, Integrity Management Rule for Liquids < 500 miles

• October, 2002, Operator Qualification Rule

• December, 2002, Pipeline Safety Improvement Act

• January, 2004, Integrity Management Rule for Gas

• 2006, Pipeline Integrity, Protection, Enforcement, and Safety Act of 2006 (PIPES)

STANDARDS

Primary standards relating to pipeline integrity management include:

•ASME B31.8S, American Society of Mechanical Engineers, “Managing System Integrity of Gas Pipelines”

• API 1160, American Petroleum Institute, “Managing System Integrity for Hazardous Liquid Pipelines”

• NACE SP0502, NACE International Standard Practice, “Pipeline External Corrosion Direct Assessment Methodology”

API STANDARDS

• API 1160 - “Managing System Integrity for Hazardous Liquid Pipelines”

Developed in response to amendments to 49 CFR 195 about Pipeline Integrity Management in HCAs

•API 570 - “Piping Inspection Code: Inspection, Repair, Alteration, and Reconstruction”

•API 579 – “Fitness for Service”

API 1160 – MANAGING SYSTEM INTEGRITY FOR HAZARDOUS LIQUID PIPELINES 1/2

• Identification and documentation of HCAs and the influence of pipeline segments on these areas

• Data gathering, analyses, and integration, including a comprehensive listing of the types of data to collect

• Risk assessment, validation, and prioritization

• Initial baseline assessment plan development and implementation

• Determination of subsequent inspection interval/frequency

• Pipeline anomaly types and tools for detection

• Mitigation options and repair methods, including a comprehensive listing of commonly used permanent pipeline repair techniques

API 1160 – MANAGING SYSTEM INTEGRITY FOR HAZARDOUS LIQUID PIPELINES 2/2

• Preventative and rehabilitation measures

• Detection and minimization of pipeline releases

• Integrity management of pipeline pump stations and terminals, including mitigation options, design considerations, corrosion control and tanks

• Performance measures and audits

• Managing change and updating the pipeline integrity program

• Comprehensive appendices on anomaly types/causes/concerns and repair strategies

• Standard data entry fields

API INSPECTOR ROLEOPERATOR QUALIFICATION

“To assure safety in the transport of hazardous gases and liquids in the nation's pipelines, pipeline operators who perform covered tasks must be qualified”

US Department of Transportation

Pipeline and Hazardous Materials Safety Administration

API INSPECTOR ROLEOPERATOR QUALIFICATION

• Covered Tasks– Changes

– Re-evaluation intervals

• Personnel evaluations– Standard

– Post accident/incident

– For Cause evaluations

• Non-qualified personnel

• Training

• Abnormal Operating Conditions (AOC)

INTEGRITY ASSESSMENT METHODS

• Pressure testing that entails the use of water or gas to pressurize the pipeline segment. Pressure testing is based on the supposition that, after defects are removed that failed above the maximum operating pressure (MOP), the line is safe to operate at the MOP and below.

• Inline Inspection (ILI) that entails the running of “smart pigs” to evaluate the pipe conditions pertaining to internal and external corrosion, crack-like defects, and deformation.

• Direct Assessment, a structured, multi-step evaluation including excavation to examine and identify potential problem areas relating to internal corrosion (ICDA), external corrosion (ECDA), and stress corrosion cracking (SCCDA).

• Other Technology (requires notification to PHMSA)

INTEGRITY ASSESSMENT METHODSINLINE INSPECTION

Geometry

Magnetic FluxLeakage

INTEGRITY ASSESSMENT METHODSLIMITATIONS

Pressure Testing

• The pipeline must be taken out of service

• Only the critical flaws leading to failure at the time of testing are identified; sub-critical flaws are not identified

• A large volume of water must be used and then disposed of in accordance with environmental regulations

• Introduction of water into the pipeline creates a corrosion risk; the pipeline must be dried before it can be returned to service

• Pressure testing is destructive

INTEGRITY ASSESSMENT METHODSLIMITATIONS

Inline Inspection

Roughly 1/3 of the 335,000 miles of global pipelines are unpiggable because of a variety of issues:

• Mechanical characteristics of the pipe

• Grade, type of welds, length, internal diameter (multi-diameter), elevation profile, restrictions, bends, ovalities, valves, unbarred tees

• Launchers and receivers

• Pipe cleanliness

• Product

• Gas, liquid

• Aggressiveness of the product

• Flow rate, pressure, temperature

• Pipe cleanliness

EXTERNAL CORROSION DIRECT ASSESSMENT

External Corrosion Direct Assessment (ECDA) is a four-step process that combines Pre-Assessment, Indirect Inspections, Direct Examinations, and Post Assessment to evaluate the impact of external corrosion on the integrity of a pipeline.

START

Pre-Assessment

IndirectInspections

DirectExaminations

Post-Assessment

END

API INSPECTOR ROLEECDA ADVANTAGES

• No disruption of service

• Can be performed on select portions of pipelines

• Not limited by pipeline configuration

• Improves pipeline integrity by reducing external corrosion threats

ECDAACCEPTANCE CRITERIA

• Greater than 80% predictive capability– Similar to ILI

• Ability to Establish Root Cause Mechanism– Unlike ILI which can’t distinguish

• Ability to establish and utilize defect growth models to establish safe operating conditions

• Ability to repair and mitigate defects before they become injurious

API INSPECTOR ROLEECDA

• Pre-Assessment– Data collection

• Pipe related

• Construction Related

• Soils/Environmental

• Corrosion Protection

• Pipeline Operations

– ECDA feasibility for pipeline

– ECDA region identification

– Indirect inspection tool selection

API INSPECTOR ROLEECDA - INDIRECT INSPECTIONS

Identify coating faults and areas where corrosion activity may have or may be occurring

• Global Positioning Survey (GPS)• Close-Interval-Survey (CIS)• Current Voltage Gradient Surveys (ACVG and DCVG)• Pearson• AC Current Attenuation Surveys• Soil resistivity

API INSPECTOR TASKSECDA - INDIRECT INSPECTIONS

Close-Interval-Survey (CIS)

Direct Current Voltage

Gradient (DCVG)

API INSPECTOR TASKSECDA - INDIRECT INSPECTIONS

AC Current Attenuation

(Electromagnetic)

Provide an

assessment of

the overall quality

of external pipeline coating

and to identify coating flaws

API INSPECTOR ROLEECDA - DIRECT EXAMINATIONS

• Direct Assessments– Excavate and collect data where corrosion most

likely

– Categorize indications

– Characterize coating and corrosion anomalies

– Establish corrosion severity for remaining strength analysis

– Determine root-cause

– In-process evaluation, re-categorization, guidelines on number of direct examinations

API INSPECTOR ROLEECDA - DIRECT EXAMINATIONS

• GPS location

• Pipe-to-Electrolyte potentials

• Measurement of soil resistivity

• Soil sample collection

• Water sample collection

• Photographic documentation

API INSPECTOR ROLEECDA - DIRECT EXAMINATIONS

COATING DAMAGE AND CORROSION DEPTH MEASUREMENTS

• Data for other integrity analyses– Microbiologically Influenced Corrosion (MIC)– Stress Corrosion Cracking (SCC)

• Identification of coating type• Assessment of coating condition• Measurement of coating thickness• Assessment of coating adhesion• Mapping of coating degradation (blisters,

disbondment, etc.)

API INSPECTOR ROLEECDA - DIRECT EXAMINATIONS

COATING DAMAGE AND CORROSION DEPTH MEASUREMENTS

• Corrosion product data collection• Identification of corrosion defects• Mapping and measurement of

corrosion defects• Photographic documentation• Magnetic particle testing for cracks,

ultrasonic thickness testing for internal defects, etc.

• Linear Polarization Resistance (LPR) measurements

API INSPECTOR TASKSECDA - DIRECT EXAMINATIONS

API INSPECTOR TASKSECDA - DIRECT EXAMINATIONS

• Microbiologically Influenced Corrosion Testing– Anaerobic bacteria (ANA)

– Acid-producing bacteria (APB)

– Iron-related bacteria (IRB)

– Low nutrient bacteria (LNB)

– Sulfate-reducing bacteria (SRB)

• Corrosion Product Testing– Calcium

– Carbonates

– Ferric iron (Fe3+)

– Ferrous iron (Fe2+)

– pH

– Sulfide

API INSPECTOR TASKSECDA – POST ASSESSMENT

• Assessment of ECDA Effectiveness

• Remaining Life Calculations– ASME B31G– RSTRENG– CorLAS– DnV RP-F10

• Root cause determination– Low CP– Interference– MIC– Disbonded coatings

• Reassessment Intervals

Questions???

John T. SchmidtStress Engineering Services, Inc.13800 Westfair East DriveHouston, Texas 77041-1101John.Schmidt@Stress.com281.955.2900