El Paso Corporation Enhancing Pipeline Integrity with Early Detection of Internal Corrosion Drew Hevle NACE Houston Section Principal Corrosion Engineer June 9, 2009 El Paso Corporation
Mar 31, 2015
El Paso Corporation
Enhancing Pipeline Integrity with Early Detection of Internal Corrosion
Drew Hevle NACE Houston SectionPrincipal Corrosion Engineer June 9, 2009El Paso Corporation
Disclaimer
This presentation discusses components of an internal corrosion control program for natural gas and hazardous liquid pipeline systemsIt is not a discussion of the policies and practices of any particular pipeline operator
Internal Corrosion
Four things are necessary in order for a corrosion cell to form: Anode Cathode Electrolyte Metallic path
For internal corrosion to occur, an electrolyte (usually liquid water) must be present
Internal Corrosion Cell
AnodeCathode
Metallic path
Electrolyte
Sources of Water
Natural gas transmission pipelines typically transport tariff-quality gas, or “dry gas”
Gas quality specifications designate a maximum moisture vapor content at a level where liquid water will not condense in the pipeline system under normal operating conditions
Natural gas pipelines that transport hydrocarbon liquids and hazardous liquids pipelines typically allow BS&W including liquid water
Sources of Water
Water accidentally introduced into the pipeline Upsets of liquid water at system inputs from
production or storage High water vapor that allows liquid water to
condense under operating conditions Failures to dehydration equipment can introduce
water, water vapor, and glycol, which is hygroscopic Maintenance pigging and gas flow can move water
to unexpected places
Sources of Water
Water intentionally introduced into the pipeline Hydrotesting (long exposures, water quality,
dewatering effectiveness) Water used to carry chemical treatments Self-inflicted (cleaning, management of
pyrophoric materials, maintenance of dehydration equipment)
Methanol injection to prevent freezing
Testing for water
Product quality monitoring at system inputsAutomated 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
Prevention
Facilities design (filter/separators)Appropriate product quality standardsProduct quality enforcement actionsCustomer quality assurance valvesTracing the source and correcting problemsDehydration and liquid removalEffective de-watering following hydrotesting
Removing Water
Re-absorption into gas stream
Maintenance pigging
Flow velocity
Line sweeping (increased velocities [but not too high])
Liquid removal devices such as pipeline drips, filters, separators, slug catchers If these devices aren’t properly maintained, then you
are simply moving the corrosion from the pipeline to the liquid removal device
Removing Water
Conditions that may prevent water removal Repeated upsets Biomass Glycol can absorb water from low levels of water
vapor Low/no flow Poor design, such as crevices, dead legs and
diameter changes Sediment accumulation
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 water has a very low conductivity
Corrosive constituents in gas and liquids can accelerate corrosion rates
If You Find Water
Perform testing on water to determine corrosivity
Monitor with coupons/probes/other technology to determine if it is corrosive
If the condition is persistent and the water is corrosive, implement a mitigation program
Use chemical analysis to trace possible offenders (e.g. glycol)
Liquid and Solid Sampling
Onsite testing Test for water pH Temperature Alkalinity Dissolved H2S Bacteria culture
Liquid and Solid Sampling
Laboratory testing Test for water Compositional analysis Alkalinity pH Conductivity Salts Corrosion products Other tests
Gas sampling
Water vaporOxygenCarbon dioxideHydrogen sulfideOther tests
Internal Corrosion Mitigation
Remove water/corrosive constituentsChemical treatment (batch or injection)Internally coat (not a great option without cathodic protection, in many cases)Cathodic protection (usually not practical except for vessels/tanks)Material selection (usually not practical)
Internal Corrosion Mitigation
Mitigation systems have to be monitored. For example, for a chemical injection system: Check pumps periodically to ensure proper operation Compare specified chemical injection rates with actual
chemical consumption Test the chemical periodically to ensure that you are
receiving the proper chemical at the specified concentration Monitor downstream for residuals to ensure proper
distribution of chemical Monitor with coupons to ensure that the chemical is effective
Measuring Corrosion Rates
In dry gas transmission pipelines, it is difficult to identify areas likely to have measurable corrosion rates, since the presence of water is extremely rareIf likely locations for internal corrosion can be identified, they can be monitored with coupons, probes, ultrasonic thickness measurements, ultrasonic thickness arrays, hydrogen permeation, electrochemical noise, etc.Advancements in ILI data technologies allow calculation of internal corrosion rates across more significant intervals
Integrity Assessment
Trust everyone, but cut the cards.
- W. C. Fields
Integrity Assessments
Ultrasonic thickness measurements at key locationsInspection of internal surface of the pipe when the pipe is open Repairs Pig launchers/receivers Meter tubes Vessels Tanks
Integrity Assessments
Inspection for internal corrosion where historical accumulations 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 sulfide content, carbon dioxide partial pressure, presence of oxygen and/or bacteria, and sediment deposits, low spots, sharp bends, sudden diameter changes, and fittings that restrict flow or velocity.
Integrity Assessments
Periodic integrity assessments ILI ICDA Pressure testing
Most effective prediction models for pipelines are incorporated into the ICDA standards (DG-ICDA, LP-ICDA, WG-ICDA)
Integrated programs
An internal corrosion control program is part of integrity management
The internal corrosion control program should prevent internal corrosion from occurring, and give the operator an idea of where and how much internal corrosion may have occurred
Feedback of the results of integrity inspections to the internal corrosion control program is essential to ensure that the program is effective
Summary
An internal corrosion control program consists of many components, including monitoring, prevention, maintenance, mitigation, and integrity assessment.Each component is necessary to a varying degree depending on the product being carried, operating history, operating conditions, risk, and expected life.An internal corrosion control program must be tailored to specific pipeline conditions
Summary
The best solution is to keep the water out of the pipe
El Paso Corporation
Questions?
El Paso Corporation
Enhancing Pipeline Integrity with Early Detection of Internal Corrosion
Pipeline Integrity Management Conference
March 30th – April 1st 2009, Houston, Texas