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Hevle Enhancing Pipeline Integrity With Early Detection of Internal
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Transcript of Hevle Enhancing Pipeline Integrity With Early Detection of Internal
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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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