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
Anode
Cathode
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 BSW 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 arent 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

29
(No Transcript)