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

Disclaimer

This presentation discusses components of an internal corrosion control program for natural gas and hazardous liquid pipeline systems

It 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

Anode Cathode

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 inputs

Automated testing at inputs and in flow stream

Liquid 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 standards

Product quality enforcement actions

Customer quality assurance valves

Tracing the source and correcting problems

Dehydration and liquid removal

Effective 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 vapor

Oxygen

Carbon dioxide

Hydrogen sulfide

Other tests

Internal Corrosion Mitigation

Remove water/corrosive constituents

Chemical 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 rare

If 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 locations

Inspection 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