Ppt in-line Inspection Symposium

In-Line Inspection Symposium

Michelle CookeInterim Deputy Executive Director for Safety

California Public Utilities CommissionJune 24, 2011

1

22

Bruce Nestleroth, Battelle

Nondestructive Pipeline Inspection

Using Pigs -101

33

Outline

• What is a pig?• Operation of a pig• Types of pigs• Pig performance measures• General thoughts on pigging

44

So WhatSo What’’s a PIG?s a PIG?

• Pigs are– Autonomous devices sent into and retrieved from a pipe– propelled by product flow

• Original use in pipelines:– Cleaning out debris, batching in liquid pipeline, dewatering a line after a

hydrotest

• Now, more commonly used to describe a device for the nondestructive inspection for pipelines anomalies from the inside– Pig is not an acronym: pipeline inspection gizmo, gauge, gadget, etc

• Pigs get their name from the grunting and squealing sound they make while travelling through a pipeline

55

Classes of pigsClasses of pigs

55

The The ““IntelligentIntelligent”” pigspigs

The The ““UtilityUtility”” pigspigs

CleaningCleaning BatchingBatching

66

Anatomy of an Intelligent Pig

Drive

Cup

Data Data RecordingRecording

Sources and Sources and SensorsSensors BatteriesBatteries

UniversalUniversalTow LinksTow Links

OdometerOdometerWheelsWheels

VentedVentedCentering CupsCentering Cups

77

Driving a pig• Big difference between pigging natural gas and liquid lines

– Pigs go with the flow in liquid lines

• For gas lines, the front cup seal off flow and differential pressure drives the pig– For a 24 inch pig, a differential pressure from the front of the pig to the

back of 10 psi provides 5000 pounds of driving force

• Gas pressure is also important, the driving force is spongy at low pressure, stiff at high pressure– Very difficult to pig at pressures below 200 psi, typically easy for

pressures above 600 psi

• The optimal speed is 3-6 mph– Not every pipeline operates at this flow rate

88

Speed bumps, potholes and sandpaper• At every girth weld, good welding practice requires a small amount of

weld material flow into the pipe.– This acts like a speed bump to the pig, jarring recording equipment

– For a low pressure gas line, the pig can stop until the pressure gets high enough to force the pig past.

• For MFL and other sensors, the closer the sensor is to the pipe wall, the better the signal. Springs force the sensors to ride the surface, even right after girth welds.– Potholes – Tee fittings will try to rip the sensors from the pig.

– Sandpaper – In the inside surface of a pipe is very rough. Sensors have hardened steel or ceramic wear surfaces.

• The polyurethane cups have to be hard enough to not be worn down by the pipe and soft enough to pass the girth welds smoothly.

• Many engineering challenges.

99

Pig Launchers and Receivers

1010

Unpiggable pipeline(a pipeline that cannot be pigged) • Not all pipelines can be successfully pigged

– Companies strive to make their pigs work perfectly the first time.– Achieve this 90% of the time.

• Many pipelines were built before pigs were first used– In the 1970’s, only 30% of interstate gas pipelines could be pigged.

• What makes lines unpiggable?– Size on size Tee’s, branches.– Bore restrictions, often built into pipelines before pigging was common

- Small valves- Valves not fully open- Diameter reductions after large customers- Large dents- Backing rings at girth welds

– Sharp bends, miter bends, vertical sections– Excessive dirt and debris

• The first time a pipeline is pigged, with diameter is tested with gage pigs, caliper pigs and dummy pigs (no sensors or data recording).

1111

1212

How many measurements? The setup• Inspection grid – density of acquiring data

Axial and circumferential resolution• Axial – how often all sensors are

measured. Every 0.x inches• Circumferential – number of sensors

Axial

Axial

Axial

Typical values• Axial – Every 0.1inches (2.5mm)• Circumferential

• 3 to 4 sensors per inch• ~ 240 sensors in a 24 inch line

• 30-40 measurements per square inch

1313

How many measurements? The math

Problem:– Two hundred miles of 42 inch diameter pipe– A high resolution pig: Sensors every 1/3 inch around the

circumference– Data acquired in 0.1 inch intervals

Solution:– 42 inches * pi * 3 (sensors per inch) = 400 sensor– 400 sensors * 200 miles * 63,360 in/mile * 10

measurements per inch – 50,688,000,000 data points x 2 bytes /data point= 100 Gigabytes

1414

Data display and analysis

• Data analysis is a labor intensive process– Automated programs perform limited tasks

- Detect pipeline features: welds, valves, branch connections

• Human eyes examine everything that is left since it is a potential anomaly– Junior staff separate the anomalies types

- Corrosion, dents,

And size isolated anomalies– Senior staff QC and size the more difficult anomalies

- Examine in parallel deformation and previous pig data

• Processing a typical run takes about 1-3 months

1515

Types of pigs

1616

Geometry Tools

• Also referred to as– Caliper Tools– Deformation tools

• Measure the local diameter• Measures dents, buckles and ovalities in pipelines• Detects girth welds, wall internal thickness

changes and installations (e.g. main line valves, T-junctions, etc.)

1717

Mapping Tools

• Determine 3-D position of the pipeline.• Inertial navigation - gyroscopes and accelerometers• Measures angular and

velocity changes in X, Y and Z coordinates between reference locations.

X

ZY

1818

Magnetic Flux Leakage:The most common inspection pig

Backing Iron

SensorBrushesSN SNMagnet Magnet

SN

1919

History of MFL PigsHistory of MFL Pigs

1964: First commercial MFL pig 1964: First commercial MFL pig -- inspected bottom portion of inspected bottom portion of pipelinepipeline1966: First full1966: First full--circumference MFL pigcircumference MFL pig1971: Other vendors introduce low1971: Other vendors introduce low--resolution MFL pigsresolution MFL pigs1978: First high1978: First high--resolution MFL pig for off shore pipelinesresolution MFL pig for off shore pipelines19861986--96: Other vendors introduce high96: Other vendors introduce high--resolution MFL pigsresolution MFL pigs1997: Pigs for multiple diameter, by1997: Pigs for multiple diameter, by--pass high flow rates, and pass high flow rates, and other previously other previously unpiggableunpiggable conditionsconditions1998: First circumferential (transverse field) MFL pig1998: First circumferential (transverse field) MFL pig20032003--present: Development of inspection capability for assessing present: Development of inspection capability for assessing mechanical damagemechanical damage

2020

Wide Defect – strong flux leakage

Flux Lines In Pipe

Pipe

Leakage Flux

Narrow Defect – flux stays in the pipe

Flux leakage 101

• The flux leakage function of corrosion depth, but also extent• Wide corrosion produces a strong flux leakage• MFL can’t find cracks in the same direction as the flux

2121

Flux leakage 102

Flux

0.0

-2.0

2.0 -2.00.0

2.0

Circumferential (inches)Axial (inches)

Pipe OD

Pipe ID

80

60

40

20

0

Flux

• Flux spreads around pit– Round pits look elliptical– Blurs images

6 in

6 in

6 in

6 in

2222

Circumferential MFL PigCircumferential MFL Pig

Magnet NS

Sens

ors

Bac

king

Iron

Magnet NS

2323

0 10 20 30 40 50 60 70 80

120

100

80

60

40

20

0

50% Deep4 in. Long3 in. Wide



Sign

al Am

plitu

de (g

auss

)

Distance (inches)

8 mph

2.5 mph

VelocityEffects

Flux Leakage 103: Velocity

2424

Ultrasonic Metal Loss Tool

25252525

Ultrasonic PigsUltrasonic Pigs

Need liquid in the pipelineNeed liquid in the pipelineCan be configured to look forCan be configured to look for

Metal LossMetal LossCracksCracks

1986: First ultrasonic pig for corrosion in liquid 1986: First ultrasonic pig for corrosion in liquid lines. More followed in the 1990slines. More followed in the 1990s1997: Ultrasonic angle1997: Ultrasonic angle--beam crack detection pigbeam crack detection pig20042004--present: Commercial EMAT pigspresent: Commercial EMAT pigs

2626

Emerging EMAT

• Electromagnetic Acoustic Transducer– An ultrasonic method that works in gas lines– Typically work lower 10x lower frequency than conventional

ultrasonic. Higher frequency means better resolution.• New? Initial discovery and fundamental research by

Rockwell Science Center in the 1960’s– Difficult to make EMAT Sensors rugged

MagnetMagnet

2828

Detection Details , Part 1

Can the pig find a particular anomaly?The answer is always yes, butDepends on the anomaly size, depth and extent importantDepends on the pipeline condition

material variationsproximity to pipeline featuresdebris and depositsconstruction practices

Will the pig find small, inconsequential anomalies Yes, lots of them. This information is useful.

Compare one pig run to the nextInformation can be useful for preventative maintenance

2929

Detection Details, Part 2

Will the pig detect anomalies where there are none? Probably.

There will be false calls.

Will the pig detect anomalies the pig was not specifically designed to find? Yes

Probability of detection may be low.This information is good for pipeline maintenance.

3030

Detection: How small of a defect ?Pipe or Data Recording Noise

6060

6565

7070

7575

8080

8585

9090

100100 110110 120120 130130 140140 150150 160160 170170 180180 190190 200200

Distance (inches)Distance (inches)

Flux

Lea

kage

(gau

ss)

Flux

Lea

kage

(gau

ss)

Pull 1Pull 1 Pull 2Pull 2 Pull 3Pull 3 Pull 4Pull 4

5%x1x1 (a Quarter)5%x1x1 (a Quarter)

10%x1x110%x1x1

20%x1x120%x1x1

3131

Sizing confirmation

Rep

orte

d D

epth

(% w

all t

hick

ness

)R

epor

ted

Dep

th (%

wal

l thi

ckne

ss)

Measured Depth (% wall thickness)Measured Depth (% wall thickness)

MFL Predict

ion Too Small

MFL Predict

ion Too Small

Safety Conce

rn

Safety Conce

rn

MFL Predict

ion Too

Big

MFL Predict

ion Too

Big

Repair W

astes

$$$

Repair W

astes

$$$

The inspector in the ditch says:The inspector in the ditch says:

Pig

say

s:P

ig s

ays:

A typical depth sizing specification is ±10% Thickness

3232

Summary

• Pigs are sophisticated devices that are rugged and reliable. Every pipeline presents a unique challenge.

• Pigs do at inspection speeds of miles per hour, what a person would be challenged to do in the ditch in an hour.

• Pigs find many anomalies that are not critical. But these help pipeline companies peek into the future.

• Pigs are like diamonds. Rarely perfect, but valuable even with flaws.

Magnetic Flux Leakage Inspections Tom Bubenik, DNV

© Det Norske Veritas AS. All rights reserved.

Tom Bubenik, Det Norske Veritas (DNV) USA

MFL Overview

Presentation Outline

1. MFL History2. MFL Principles

3. MFL Signals

4. Magnetization Direction5. Axial and Circumferential MFL

6. Recap and Conclusions



MFL Overview

1. MFL History

1960 1970 1980 1990 2000 2010 2020

First commercial

pig First “high- resolution” pigs First spiral

MFL pig

First dual capability MFL/caliper pigFirst reduced

port pigsFirst circumferential

(transverse) MFL

Mechanical damage pig trials



MFL Overview

2. MFL Basics

Flux lines show the strength and direction of a magnetic field

Some materials are easier to magnetize than others



MFL Overview

When it can, flux moves from materials that harder to magnetize to those that are easier to magnetize

Steel is easy to magnetize: flux “prefers” the steel rather than air

As the steel becomes saturated with magnetism, some flux begins to leak

MFL Basics



MFL Overview

MFL Basics

Near a pipe wall, most flux is carried by the steel.

Where metal loss is present, some flux “leaks” out

The strength and shape of the leaking flux helps determine anomaly dimensions



MFL Overview

MFL Application

A typical MFL tool (pig) has magnetizers and sensors

Multiple sets of sensors are mounted between multiple magnetizers

Sensors measure leakage near the pipe wall

Increase in flux leakage indicates metal loss Photograph from “Magnetic Flux Leakage (MFL) Technology For Natural

Gas Pipeline Inspection”, Nestleroth and Bubenik,



MFL Overview

3. MFL Signals

Definitions of data:- Squiggles –

sensor readings recorded on a smart pig- Viewable ‘raw’

data –

color plots showing the sensor readings in a format people can grasp

- Spreadsheets –

summaries of analysis results

WHEN DOES DATA ≠

DATA?



MFL Overview

Individual Sensor Traces

Line plots of individual sensor readings (most information)



MFL Overview

Viewable ‘Raw’ Data

Colorized representations – easier to see, less detail than squiggles

Clean PipeGreen represents background signals

ID/OD

Line Map

MFL Data



MFL Overview

MFL Signals - Corrosion

‘Raw’ data – highlights where anomalies exist

Yellows and reds = leaking flux

Blues and blacks = decreases in flux



MFL Overview

Different anomalies, different signals

Differentiation is critical

Metal Loss

Dents

Metal Gain



MFL Overview

Odometer Distance

Distance to Closest AGM or Reference Feature

Feature Description

Spreadsheets – Processed Results

Processed results- Summarizes

results with simple descriptions

Shows- Where - What - Estimated length,

depth, and width

Basis for dig and remediation decisions



MFL Overview

Data Recap

Data means different things to different people

Analyses are done on sensor readings (squiggles) and ‘raw’ data plots

Spreadsheets are summaries

Squiggles

‘Raw’ Data Plots

SpreadsheetsActions

&Decisions



MFL Overview

4. Magnetization Direction

MFL works a lot better when the metal loss cuts across flux lines – it’s a lot like placing a rock in a stream of water. If the rock is wide, water splashes. If it’s long and skinny, nothing much happens.



MFL Overview

Signal Characteristics

Flowing Water Rock

Water (flux lines) flows over and around the rock.

In an MFL smart pig, the sensors measure the leakage (flow) over the anomaly and the changes in flux around the edges



MFL Overview

Different geometries, Different capabilities

Most pigs magnetize in the axial direction

These pigs are more sensitive to wide anomalies – those that cut across flux lines -than narrow ones

Good detection, as long as anomaly has width and volume



MFL Overview

5. Axial MFL

Axial MFL is best at finding/sizing anomalies in this region



MFL Overview

Axial MFL

Detects and sizes anomalies that cut across flux lines

Most effective on anomalies with volume (metal loss)

Not as sensitive to long narrow anomalies



MFL Overview

Circumferential MFL Tools

Mid 1990s – First prototype - Used different sensors and

stronger magnets

More complicated than axial MFL- More sensors and magnetizers- More analysis required

Less inspection mileage (experience) than axial MFL



MFL Overview

OffsetBrushes/Sensors

Courtesy of PII

Circumferential Tool



MFL Overview

Where Circumferential MFL Works Best

Circumferential MFL is best at finding/sizing anomalies in this region

Axial MFL is best at finding/sizing anomalies in this region



MFL Overview

Circumferential MFL Crack Tool Summary

Field applied at right angles to axis

Good detection, as long as anomaly cuts across flux lines.

Sensitive to defect orientation. Generally requires a volumetric anomaly.



MFL Overview

Wrap Up

MFL- Oldest inspection technology –

lots of

experience - Widely used in gas pipelines –

a

workhorse

Complementary Capabilities (Axial and Circumferential)- Axial MFL: Wide anomalies- Circumferential MFL: Long anomalies

AXIALAXIALCIRCCIRC



MFL Overview

Conclusions

Using MFL requires understanding, experience, and expertise:- Signal analysis- Pipeline characteristic- Inspection tool characteristics

Axial / circumferential = different strengths and weaknesses- Also true of hydrotests and other

assessment methods

No assessment, MFL or hydrotesting, is perfect

MFLMFLHYDROHYDRO



MFL Overview

For more information please contact:

Tom Bubenik

[email protected]

DNV USA

614-761-1214

www.dnvusa.com

http://www.dnvusa.com/



MFL Overview

Safeguarding life, property and the environment

www.dnv.com

Application of Integrity Assessment

Michael J. Rosenfeld, PE

Kiefner & Associates, Inc.

Presented to CPUC, June 24, 2011

What will be presented

•

Concept of a critical defect

•

Relationship between defect size and failure pressure

•

Ability of hydrostatic test to eliminate defects

•

Ability of in‐line inspection to identify defects

•

Alternative of in the ditch examination

What are we looking for when performing integrity assessment?

•

We are looking for defects that are near critical today or that could become

critical before the next inspection

•

In the context of pipe where a prior pressure test has not been verified, the

concern is with manufacturing defects in the pipe seam

What is a critical defect?

•

A critical defect is one that can cause the pipe to fail at normal operating pressure

•

A significant noncritical flaw can reduce the safety margin of the pipe at normal operating

pressure, or it could become critical before the next inspection

•

Minor flaws in the pipe do not cause the pipe to fail at normal operating pressure now or

before the next assessment, if ever

Relationship between flaw size and failure pressure

•

An inverse relationship exists between applied stress and tolerable flaw size

•

Pipe operating at low stress can tolerate large flaws•

Pipe operating at high stress can tolerate only small

flaws

Example•

Consider 24”

OD x 0.250”

WT, 1950’s vintage X46

pipe operating at 50% SMYS (about 475 psig)

Flaws having a depth and

length below the red line are

too small to fail at the

operating pressure

Flaws having a depth and

length below the red line are

too small to fail at the

operating pressure

Concept of leak vs rupture

•

A leak is a small hole or crack that remains stable. Although contents do escape, the pipe

remains intact and can still hold pressure.

•

A rupture is a gross failure of the pipe consisting of a large opening or fracture. The

pipe cannot hold pressure, and a large quantity of contents are released suddenly.

Concept of leak vs rupture

Critical flaw size for example pipe operating at 50% SMYS

Flaws above the gray

dashed line (short but

deep) will fail as a leak

Flaws above the gray

dashed line (short but

deep) will fail as a leak

Flaws below the gray dashed

line (long but shallow) will fail

as a rupture

Flaws below the gray dashed

line (long but shallow) will fail

as a rupture

Flaws with depth and length above

the pressure test lines would

be

discovered by pressure testing.


the pressure test lines would

be


Flaws with depth and length below

the pressure test lines would not be



the pressure test lines would not be


Effectiveness of pressure testing of example pipe


the

ILI sensitivity lines would

be discovered

by ILI using transverse MFL tools.


the

ILI sensitivity lines would

be discovered

by ILI using transverse MFL tools.


the ILI

sensitivity lines would not be discovered by ILI

using transverse MFL tools.


the ILI

sensitivity lines would not be discovered by ILI

using transverse MFL tools.

Effectiveness of transverse magnetic ILI for example pipe

Comparison of effectiveness of hydrotest and ILI

ILI by TFI or CMFL tools is

more sensitive than pressure

testing for defect sizes of

interest.

ILI by TFI or CMFL tools is

more sensitive than pressure

testing for defect sizes of

interest.

What this means

•

ILI using circumferential MFL can be expected to find large seam anomalies that are

susceptible to failure at operating stresses

•

Ability to detect subcritical defects that could ever fail by rupture is as good or better than

hydrostatic pressure test to standard levels

•

Especially true for pipelines operating at moderate stress levels, e.g. Class 2, 3, & 4

Nondestructive examination

•

Sizing and characterizing flaws using TFI or CMFL tool is not as good as desired –

will

require excavating all suspect anomalies

•

All digs of anomalies indicated by ILI will require nondestructive examination (NDE) in

the ditch to prove up the indicated condition or conclude that it is not harmful

Nondestructive examination

•

Various NDE techniques can be employed in the ditch, including:

–

Magnetic particle testing (MT), good for detecting external surface‐breaking cracks

–

Ultrasonic testing (UT) using angle beam or phased array, good for internal detection and

sizing of cracks

–

Radiographic testing (RT), good for detecting volumetric defects, thickness and geometric

variations, some cracks, and weld defects

In the ditch NDE alternative assessment

•

NDE can be as good as or better than ILI or HT

•

NDE widely used to evaluate other critical services: pressure vessels, aircraft, bridges

•

Could serve as the sole assessment technique for short segments where the entire pipe can be excavated for examination, or already is

above ground

In the ditch NDE alternative assessment

•

The chosen NDE method should be repeatable, verifiable, and appropriate for the

type of defect of concern

•

More than one method will likely be needed

•

Procedures and technicians must be qualified

Comparison of assessmentsAssessment Benefits Limitations

Hydrotest •Appropriate for wide

range of defect types and

conditions•Predictable results•High certainty within

limit of tested stress level

•Line must be taken out of service•Does not inform about flaws that

do not fail during test•Water inside pipe a problem•Not effective for small defects

In‐line

inspection•As effective as HT for

detecting large defects•Better than HT for

smaller defects•No service interruption

•Line must be piggable•Many anomaly digs necessary•More than one tool type may be

necessary•Not effective for very small defects

In‐ditch

NDE•More accurate than ILI•No service interruption

•Line must be exposed•Operator skill dependent•Only practical over limited lengths

Summary

•

Critical defect sizes can be determined•

Hydrotest is very capable of detecting

significant defects that could rupture, less so for leaks

•

ILI is as good as HT for detecting defects that could rupture, finds other flaws that HT does not

•

NDE could be effective where pipe can be exposed

End of presentation. Your comments are welcome.

U.S. Department of TransportationPipeline and Hazardous Materials Safety Administration

PHMSAPHMSA Office of Pipeline SafetyOffice of Pipeline Safety

Zach Barrett Zach Barrett

Director, State ProgramsDirector, State Programs


PHMSA MissionPHMSA Mission

To ensure the safe, reliable, and

environmentally sound operation of the

Nation’s pipeline transportation system.




0

10

20

30

40

50

60

70

80

90

100

1986 1988 1990 1992 1994 1996 1998 2000 2002 2004 2006 2008 2010Calendar Year

Pipeline Incidents w/Death or Major Injury (1986‐2010)

Data: DOT/PHMSA Pipeline Incident Data (as of Jan. 19, 2011)

Long‐term trend (average10% decline every 3 years)


InIn--line Inspection and the Regulationsline Inspection and the Regulations• May 12, 1994 – PHMSA passed regulations requiring

new transmission pipelines and pipeline replacements to be designed to allow the passage of internal inspection tools (Pigs)

• Exemptions were provided for transmission pipelines in conjunction with distribution systems in Class 4 locations.

• The intent was to make transmission pipelines able to accommodate internal inspection tools over time.


InIn--line Inspection and the Regulationsline Inspection and the Regulations• December 2000 – PHMSA issued Liquid Integrity

Management Regulation.

• Requiring operators to assess integrity threats to their pipelines by February 2009 using:

– Internal inspection tools

– Pressure test

– Direct assessment

– Other technology


InIn--line Inspection and the Regulationsline Inspection and the Regulations• Until the Liquid Integrity Management regulations

there were no regulations requiring pipeline operators to run internal inspection tools in their pipelines.

• Many operators utilized internal inspection tools, however, they typically did not run the tools on a set interval.


InIn--line Inspection and the Regulationsline Inspection and the Regulations• January 2004 – PHMSA issued Gas Integrity

Management Regulation.

• Required operators to assess integrity threats to their pipelines by December 2012 using:

– Internal inspection tools

– Pressure test

– Direct assessment

– Other technology


InIn--line Inspection and the Regulationsline Inspection and the Regulations• Some gas operators had made use of internal

inspection tools, however, they typically did not utilize the tools on a set interval.

• Gas Integrity Management rule requires operators to assess their pipelines on a continuing basis with reassessments set at 7 year intervals.


Gas Integrity ManagementGas Integrity Management• Gas Integrity Management Results 2004-2009:

– Immediate Repairs (1,052)

– Scheduled Repairs (2,239)

– Total Repairs in HCAs (3,291)


Gas Integrity ManagementGas Integrity Management• Of the approximately 292,000 miles of gas

transmission pipeline approximately 140,000 miles have been assessed due to the Gas Integrity Management Rule despite there being only 19,100 (7% of total) miles of pipeline in HCAs.

• The repairs to the pipelines outside of HCAs are not included in the information provided in the previous slide.

• PHMSA does not collect information on the type of assessment tools utilized, however, internal inspection tools are believed to be responsible for the vast majority of pipeline assessments.


Gas Integrity ManagementGas Integrity Management• Gas Integrity Management requires operators to assess threats to

integrity

– External Corrosion, Internal Corrosion, and Stress Corrosion Cracking are time dependant threats which must be assessed if present.

– Manufacturing and Construction Defects (Seam Defects) can be considered as stable (no assessment required) on a pipeline if:

• Pipeline has been pressure tested to Subpart J or

• Pressure in pipeline does not exceed the high pressure the pipeline has experienced in the 5 years prior to the HCA’s identification or

• The pipe does not have a history of seam failure

• There are no interacting threats on the seam


Gas Integrity ManagementGas Integrity Management• PHMSA Integrity Management regulations recognize the value

pipeline assessment by internal inspection tools

– 192.921(a)(1) identifies internal inspection tools as a method to assess corrosion and other integrity threats which the pipeline section is susceptible.

• Internal Inspection Tools are typically used to address the integrity threats of internal and external corrosion for gas pipelines.

• They have also been used on a limited basis to assess cracking in longitudinal seams and identified excavation damage to pipelines.


Gas Integrity ManagementGas Integrity Management

• Pressure Testing

– 192.921(a)(2) identifies pressure testing to Subpart J as a means of assessing corrosion and other integrity threats which the pipeline section is susceptible.

• Pressure testing is predominately used to assess the integrity of longitudinal seams, but is also appropriate for assessing corrosion.

• Subpart J allows testing with gas, inert gas, air, or water.

– Restrictions on stress levels if testing with test medium other than water.


Pros and ConsPros and Cons• Pressure Testing

– Pressure Testing is a longstanding methodology for assuring pipeline integrity

– Pressure Testing will grow all critical anomalies to failure providing a margin of safety between the test pressure and the maximum allowable operating pressure

– Pressure Testing will not provide information to characterize other defects in the pipeline

– Some concern for pressure reversals

– Would result in customer outages for single-feed systems

– Would require construction to put in test headers

– If residual liquid is left in the pipeline could cause customer outages or operational issues


Pros and ConsPros and Cons• Internal Inspection Tools

– Proven tool for assessing internal and external corrosion

– Can identify cracks in longitudinal seams

– Can identify dents in the pipeline and their orientation

– Provides interacting threat information such as corrosion aligned with longitudinal seams or top-side dents aligned with other underground facilities

– Not widely used in gas pipelines to assess longitudinal seams

– Might not find some tight cracks with little separation and may have issues with sizing cracks for repair

– May require extensive retrofitting of pipeline to be utilized


Questions?Questions?

SoCalGas/SDG&E In-line Inspection Implementation & Operator’s

Perspective

Doug Schneider

98

1.

Overview of a retrofit and in-line inspection

2.

Show what data are collected and how they are validated and used

3.

Challenges

Main Objectives

1.


2.


3.

Challenges

Main Objectives

Project Planning

»

Obtain Permits (critical path)

»

DetermineLauncher/Receiver sites Temporary or permanent

»

Design and Engineering Review

»

Field Construction for Launchers/Receivers

Retrofitting Operations

Before inspection can occur, lines must be retrofitted

Retrofitting Operations

Smart pig ready to go to work

Pig Tracking»

Each pig that is inserted into our pipeline has a transmitter onboard

»

Transmitter allows vendor to track pig as it travels down the pipeline

»

The data are used to help determine run speeds

http://www.pigging.com/index.cfm?id=3&equipID=54

Speed Excursions

Sensor Lift Off Due to Debris Field

Run Acceptance

» Vendor and company will confirm “good- run”

If acceptable – demobilize equipment and return system to normal operating conditionsRe-run if unacceptable

» Vendor performs data analysis

» Report typically issued in 60-90 days

1.


2.


3.

Challenges

Main Objectives

Direct Examination

Excavate pipe and collect dataValidate reported anomalies Determine action for integrity conditionMake repairs as requiredPerform root cause analysisDocument resultsAssess ILI tool performance

Typical Dig Sheet

System Map

Protecting the Workforce

Protecting the Environment

Data Analysis from Field Measurements

»Data are reviewed to verify ILI performance

»Used to determine repair/remediation requirements

ILI Remediation Objectives» Address current & future uncertainty of ILI

data» Confirm potentially hazardous anomalies are

addressed» Check that all repairs are complete» Document remediation activities to support

future re-inspection work» Conservative approach to repairs

Typical “Band” Repair Over a Defect

Prevention & Mitigation»

P&M evaluation performed

»

Applicable P&M measures assigned based on information gathered

»

Examples P&M activitiesPipe replacementPipe recoatCathodic protection system enhancementsSimilar segment evaluation

1.


2.


3.

Challenges

Main Objectives

In-Line Inspection Planning Challenges

»

Interruptions must be carefully planned»

Customers may have limited time frame where service interruption can be tolerated; planning and construction of additional facilities may be required

»

Gas supply must be considered»

Permitting requirements can be significant –

traffic control,

night work, environmental issues, etc.»

Availability of qualified contractors

» Robotic ILI technology now commercially available

» Advantages of Robotic PigsSmall footprint for launch/receiver assembliesPreviously unpiggable sections are now possibleSmall diameter range commercially available (diameter range: 6-8 inch)Medium and large diameter tools projected to follow in 2012 (diameter range: 10-12 inch & 20-22 inch)

Low Flow Pipeline Challenges

Preparation for Launch

Hot Tap Launch

Robotic In-line Inspection

Thank You

Documents

Ppt in-line Inspection Symposium