1. Enhancing Pipeline Integrity with Early Detection of Internal Corrosion
Drew Hevle NACE Houston Section Principal Corrosion Engineer June 9, 2009 El Paso Corporation

2. 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

3. 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

4. Internal Corrosion Cell
Electrolyte
Cathode
Anode
Metallic path

5. 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

6. 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

7. 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

8. 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

9. 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

10. 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

11. 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

12. 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

13. 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)

14. Liquid and Solid Sampling
Onsite testing
Test for water pH
Temperature
Alkalinity
Dissolved H2S
Bacteria culture

15. Liquid and Solid Sampling
Laboratory testing
Test for water
Compositional analysis
Alkalinity pH
Conductivity
Salts
Corrosion products
Other tests

16. Gas sampling Water vapor Oxygen Carbon dioxide Hydrogen sulfide
Other tests

17. 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)

18. 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

19. 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

20. Trust everyone, but cut the cards.
Integrity Assessment
Trust everyone, but cut the cards.
- W. C. Fields

21. 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

22. 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.

23. 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)

24. 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

25. 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

26. Summary
The best solution is to keep the water out of the pipe

27. Questions?

28. Enhancing Pipeline Integrity with Early Detection of Internal Corrosion
Pipeline Integrity Management Conference
March 30th – April 1st 2009, Houston, Texas