Enhancing Pipeline Integrity with Early Detection of Internal Corrosion

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