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El PasoCorporation

Enhancing Pipeline Integrity withEarly Detection of Internal Corrosion

Drew Hevle NACE Houston SectionPrincipal Corrosion Engineer June 9, 2009El Paso Corporation

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Disclaimer

This presentation discusses components ofan internal corrosion control program fornatural gas and hazardous liquid pipelinesystems

It is not a discussion of the policies andpractices of any particular pipeline operator

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Internal Corrosion

Four things are necessary in order for acorrosion cell to form:

Anode

Cathode

Electrolyte

Metallic pathFor internal corrosion to occur, an electrolyte(usually liquid water) must be present

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Internal Corrosion Cell

AnodeCathode

Metallic path

Electrolyte

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Sources of Water

Natural gas transmission pipelines typicallytransport tariff-quality gas, or dry gas

Gas quality specifications designate a maximum

moisture vapor content at a level where liquid waterwill not condense in the pipeline system undernormal operating conditions

Natural gas pipelines that transport hydrocarbon

liquids and hazardous liquids pipelines typicallyallow BS&W including liquid water

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Sources of Water

Water accidentally introduced into the pipeline

Upsets of liquid water at system inputs fromproduction or storage

High water vapor that allows liquid water tocondense under operating conditions

Failures to dehydration equipment can introducewater, water vapor, and glycol, which is hygroscopic

Maintenance pigging and gas flow can move waterto unexpected places

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Sources of Water

Water intentionally introduced into thepipeline

Hydrotesting (long exposures, water quality,dewatering effectiveness)

Water used to carry chemical treatments

Self-inflicted (cleaning, management of

pyrophoric materials, maintenance ofdehydration equipment)

Methanol injection to prevent freezing

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Testing for water

Product quality monitoring at system inputs

Automated testing at inputs and in flow

streamLiquid sampling (drips, pigging operations,vessels, sample pots)

Testing for increases in water vapor content

can identify areas of liquid holdup

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Prevention

Facilities design (filter/separators)

Appropriate product quality standards

Product quality enforcement actionsCustomer quality assurance valves

Tracing the source and correcting problems

Dehydration and liquid removalEffective de-watering following hydrotesting

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Removing Water

Re-absorption into gas stream

Maintenance pigging

Flow velocityLine sweeping (increased velocities [but not toohigh])

Liquid removal devices such as pipeline drips,

filters, separators, slug catchers If these devices arent properly maintained, then you

are simply moving the corrosion from the pipeline tothe liquid removal device

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Removing Water

Conditions that may prevent water removal

Repeated upsets

Biomass

Glycol can absorb water from low levels of watervapor

Low/no flow

Poor design, such as crevices, dead legs and

diameter changes Sediment accumulation

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If You Find Water

Determine if it is an upset or persistent condition

Determine the extent of pipeline affected

Remove the water, if practical

Gas and hydrocarbon liquids are not corrosive.Water may not be corrosive; pure condensed waterhas a very low conductivity

Corrosive constituents in gas and liquids can

accelerate corrosion rates

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If You Find Water

Perform testing on water to determinecorrosivity

Monitor with coupons/probes/othertechnology to determine if it is corrosive

If the condition is persistent and the water iscorrosive, implement a mitigation program

Use chemical analysis to trace possibleoffenders (e.g. glycol)

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Liquid and Solid Sampling

Onsite testing

Test for water

pH

Temperature

Alkalinity

Dissolved H2S

Bacteria culture

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Liquid and Solid Sampling

Laboratory testing

Test for water

Compositional analysisAlkalinity

pH

Conductivity

Salts

Corrosion products

Other tests

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Gas sampling

Water vapor

Oxygen

Carbon dioxideHydrogen sulfide

Other tests

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Internal Corrosion Mitigation

Remove water/corrosive constituents

Chemical treatment (batch or injection)

Internally coat (not a great option withoutcathodic protection, in many cases)

Cathodic protection (usually not practicalexcept for vessels/tanks)

Material selection (usually not practical)

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Internal Corrosion Mitigation

Mitigation systems have to be monitored. Forexample, for a chemical injection system:

Check pumps periodically to ensure proper

operation

Compare specified chemical injection rates withactual chemical consumption

Test the chemical periodically to ensure that you are

receiving the proper chemical at the specifiedconcentration

Monitor downstream for residuals to ensure properdistribution of chemical

Monitor with coupons to ensure that the chemical iseffective

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Measuring Corrosion Rates

In dry gas transmission pipelines, it is difficult toidentify areas likely to have measurable corrosionrates, since the presence of water is extremely rare

If likely locations for internal corrosion can beidentified, they can be monitored with coupons,probes, ultrasonic thickness measurements,ultrasonic thickness arrays, hydrogen permeation,electrochemical noise, etc.

Advancements in ILI data technologies allowcalculation of internal corrosion rates across moresignificant intervals

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Integrity Assessment

Trust everyone,but cut the cards.

- W. C. Fields

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Integrity Assessments

Ultrasonic thickness measurements at keylocations

Inspection of internal surface of the pipewhen the pipe is open

Repairs

Pig launchers/receivers

Meter tubes

Vessels

Tanks

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Integrity Assessments

Inspection for internal corrosion where historicalaccumulations of liquid water may have occurred:

PHMSA Advisory Bulletin ADB-00-02

Drips, deadlegs, and sags, fittings and/or "stabbed"connections, operating temperature and pressure,water content, carbon dioxide and hydrogen sulfidecontent, carbon dioxide partial pressure, presence ofoxygen and/or bacteria, and sediment deposits, low

spots, sharp bends, sudden diameter changes, andfittings that restrict flow or velocity.

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Integrity Assessments

Periodic integrity assessments

ILI

ICDA

Pressure testing

Most effective prediction models forpipelines are incorporated into the ICDA

standards (DG-ICDA, LP-ICDA, WG-ICDA)

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Integrated programs

An internal corrosion control program is part ofintegrity management

The internal corrosion control program should

prevent internal corrosion from occurring, and givethe operator an idea of where and how muchinternal corrosion may have occurred

Feedback of the results of integrity inspections to

the internal corrosion control program is essentialto ensure that the program is effective

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Summary

An internal corrosion control programconsists of many components, includingmonitoring, prevention, maintenance,

mitigation, and integrity assessment.Each component is necessary to a varyingdegree depending on the product beingcarried, operating history, operatingconditions, risk, and expected life.

An internal corrosion control program mustbe tailored to specific pipeline conditions

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Summary

The best solution is to keep the water out ofthe pipe

El Paso Corporation

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El PasoCorporation

Questions?

El Paso Corporation

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El PasoCorporation

Enhancing Pipeline Integrity withEarly Detection of Internal Corrosion

Pipeline Integrity Management Conference

March 30thApril 1st 2009, Houston, Texas

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