Corrosion Detection on Buried Transmission

Pipelines with Micro-Linear Polarization Resistance

Sensors

Bernard Laskowski, Ph.D.

Analatom, Inc.

Background – Regulatory & Industry

Direct Assessment (DA) is identified in the Gas Pipeline Integrity Management Rule as

an acceptable method for evaluating the integrity of a pipeline segment.

The rule requires a four step process for external corrosion direct assessment (ECDA)

Step One: Pre-assessment - determine the feasibility of using ECDA for a segment, identify

ECDA regions, and identify two indirect examination tools to be used on the ECDA region.

Step Two: Indirect Examination - identify indications of potential external corrosion, classify the

severity of those indications, and determine urgency for their excavation and direct

examination.

Step Three: Direct Examination - examine the condition of the pipe and its environment,

determine actions to be taken should corrosion defects be found, and identify and address root

causes.

Step Four: Post Assessment - determine a segment’s remaining life, its re-assessment

interval, and the effectiveness of using ECDA as an assessment method.

Quoted from U.S. DOT Fact Sheet: Direct Assessment (DA) - Gas Pipelines

Buried natural gas steel pipes are usually cathodically protected and coated

ECDA technologies are significantly challenged at cased sections

Background – Analatom, Inc.

Located in Sunnyvale, CA of Silicon Valley

Founded in 1980

Managed 97 university, government and private industry contracts in microscopic physics, atomic and molecular interactions and device simulations

“A Structural Health Monitoring Company”

Team with Experiment

Objective & Benefits

Determine the feasibility of using micro-linear polarization resistance (μLPR) sensors to monitor corrosion on live pipelines.

- Range of detection of each sensor

- Performance on buried, cathodically protected pipe

Focus on areas of pipe as needed

Measure corrosion rates instantaneously in situ

Qualify as Direct Examination if detection range is acceptable

Achieve integrity assessments on hard to reach locations such as cased crossings

Rely on commercially proven use in structural health monitoring

Minimize R&D risk with only a successful adaptation of an existing technology

Project Tasks & Schedule

Project Task Percent Complete

May 2012

June 2012

July 2012

Aug. 2012

Sept. 2012

Oct. 2012

Nov. 2012

Dec. 2012

Task 1) Identify Pipeline Materials & Coating

100%

Task 2) Design Experiment, Prepare Mock Pipeline, & Fabricate Sensors

100%

Task 3) Apply Defects to Coating

100%

Task 4) Experiment Assembly

100%

Task 5) Identify Field Conditions

100%

Task 6) Conduct Test

100%

Task 7) Assess Degradation

100%

Task 8) Correlate Degradation to Sensor Data

100%

Final Report & Project Review 90%

Funder Advisory & In-Kind

1. Answers to Questionnaire & KO meeting – Project Advisory Group

Materials selection for pipe and sensors

Moisture/drying cycles, temperature, soil properties, cathodic protection

2. Expertise in cathodic protection and accelerated corrosion - CHG&E

Environmental test chamber and CP design recommendations

3. Specifications & Procurement info for coating services – SoCal

FBE by Commercial Coating Services Int. to industry standards (14 - 16 mils)

Field patch material (3M Scotchcoat Liquid Epoxy Coating 323)

4. Mock-up Pipe, sensor material and welding labor – Questar

3 foot section of 6” API 5L Grade B line pipe

12”x12” API 5L Grade B line pipe section

Sensor Technology – As Applied to Buried Pipe Micro-linear polarization resistance (μLPR) sensors fabricated from same material as

structure.

Monitors electrochemical potential and current between electrode pairs.

Defect causes delamination of coating, allowing micro-fluidic electrolyte flow.

FBE Coating

Steel Surface

Micro-

Fluid

LPR Sensor

Kapton Tape

Epoxy

Cathodic Protection (Voltage)

Capillary Forces (Delamination)

μLPR Sensors Fabrication Shim stock currently unavailable

API 5L Grade-B steel

12” x 12” curved plate

12” x 1.3” wafers

Scaling production will be accomplished by working with a foundry.

Chemical Etching 300 µm electrodes

300 µm spacing

10 mil thickness

Sensors mounted onto 2 mil Kapton (polyimide)

Sensors mounted onto flex cables.

Micro-Sensor Fabrication

Sensor Technology – Mounting on Natural Gas Pipelines

36” section of API 5L Grade B steel pipe acquired for evaluation.

Pipe was coated with 15 mils of fusion bonded epoxy (FBE).

Areas of FBE were removed to expose bare metal for sensor installation.

Sensors were mounted with industrial strength epoxy

Sensors were recoated with Scotchkote Liquid Epoxy 323 (“field patch”).

Defect Placement

Two defects measuring 1/8th inch were installed. One on weld joint and one on seam with nearest sensors spaced 0.375, 1.625, and 4.125-in away.

Additionally, a sensor was placed along the seam in the middle of the pipe and a bare sensor placed on the opposing side of the pipe, as control sensors.

Pipe with attached sensors was placed inside environmentally controlled soil. Weld Defect

Seam Defect

Environmental Chamber Operation Chamber filled with soil

with pH of 5 - 6.

Wet cycles lasted 7 days.

Dry cycles lasted 7 days and involved:

- sparging 10 liters/min 100ºC dry air through soil

- 750 W heat lamps.

Week 1 Week 2 Week 3 Week 4

Wet Cycle

Dry Cycle

Soil Moisture

Se

ns

or

Su

rfa

ce

Lo

ss

[m

m]

Sensor

Surface Loss

Results - Corrosion Observed on Bare Sensor

Bare sensor (#4) began oxidizing on day 5. Corrosion increased dramatically with moisture from first wet cycle.

Sensor surface lost 25 µm or 10% in 17 days.

Other sensors cycled for 35 days without LPR activity.

Corrosion potential was increased by holding the chamber in a wet cycle and raising the temperature with the heat lamps.

Increases diffusion

Improves reaction kinetics

Results - Corrosion Observed Along Pipe Seam

Corrosion detected on μLPR sensors on day 49.

Chamber placed back on wet/dry cycling regime.

Surface loss on seam sensors was:

Sensor # Distance from

Seam Defect

Sensor Surface

Loss

8 0.375-in 128 nm

7 1.25-in 150 nm

6 4.215-in 158 nm

5 18-in 7 nm

Se

ns

or

Su

rfa

ce

Lo

ss

[m

m]

Sensor

Surface Loss

Results - Corrosion Adjacent to Weld Joint Corrosion occurred an order

of magnitude higher along the seam, likely due to positioning in the chamber

Sensitive nature of measurements allows small surface losses to be identified.

Sensors correlate with moisture

Sensor surface lost at weld was:

Sensor # Distance from

Weld Defect

Sensor Surface

Loss

1 0.375-in 11.0 nm

2 1.25-in 1.9 nm

3 4.215-in 3.2 nm

Se

ns

or

Su

rfa

ce

Lo

ss

[m

m]

Sensor

Surface Loss

Sensor Response to Cathodic Protection

A separate experiment was performed to determine if sensors detected cathodic

protection.

Impressed current cathodic protection was applied to the pipe using a 100 mV

polarization potential in accordance with NACE SP01-69.

Current interruption tests demonstrated a 100 mV polarization potential was achieved

when 5.9 mA was applied.

Weld Joint Sensor Responses to Cathodic Protection

Experiment started with system

hyperpolarized at 850 mV above the native

corrosion potential.

Protection was interrupted at day 1, and

remained off until day 7.

On day 7, a 100 mV polarization potential

was applied in accordance with NACE

SP01-69.

Sensor exposed directly to soil (bare)

detected an average corrosion rate of 2

mm/year.

This experiment showed:

3/8-in from defect

1 5/8-in from defect

4 1/8-in from defect

Bare Sensor

mm

/ye

ar

mm

/ye

ar

mm

/ye

ar

mm

/ye

ar

Distance from

Weld Defect

Average Corrosion Rate

with CP Off

Corrosion Rate After 4

Days with CP On

3/8-in 4.4x10-3 mm/year 5.3x10-4 mm/year

1 5/8-in 1.9x10-5 mm/year 1.0x10-7 mm/year

4 1/8-in 1.7x10-5 mm/year 4.8x10-6 mm/year

Seam Sensor Responses to Cathodic Protection

Experiment started with system

hyperpolarized at 850 mV above the native

corrosion potential.

Protection was interrupted at day 1, and

remained off until day 7.

On day 7, a 100 mV polarization potential

was applied in accordance with NACE

SP01-69.

This experiment showed:

3/8-in from defect

1 5/8-in from defect

4 1/8-in from defect

18-in from defect

mm

/ye

ar

mm

/ye

ar

mm

/ye

ar

mm

/ye

ar

Distance from

Seam Defect

Average Corrosion Rate

with CP Off

Corrosion Rate After 4

Days with CP On

3/8-in 0.03 mm/year 5.5x10-3 mm/year

1 5/8-in 1.6x10-5 mm/year 5.8x10-6 mm/year

4 1/8-in 1.1x10-5 mm/year 6.3x10-6 mm/year

18-in 5.7x10-5 mm/year 5.4x10-6 mm/year

Results - Post Experimental Examination

No evidence of “field patch”

failure or undercutting of coating

was present.

Bare sensor and defects visually

revealed significant amounts of

corrosion had occurred, but no

blistering of coatings was

present.

Removal of FBE revealed

corrosion activity was visually

only at defect sites, which is

supported by nanometer amounts

of corrosion observed on

sensors.

Practicality of measuring

nanometers of pipe corrosion

prevented sensor-pipe data

correlation.

Weld Defect Seam Defect

Weld

Defect

Seam Defect

Mounting locations

after FBE removal

Conclusions

µLPR sensors can be installed on natural gas pipelines without effecting integrity of

fusion-bonded epoxy coating.

Order of magnitude increase in corrosion along the seam defect vs. weld defect.

Little corrosion activity occurred on the pipe. - Surface losses of 130 nm and 11 nm detected near defects over the course of the experiment.

- Small amounts of corrosion seen due to FBE coating quality and timeframe of experiment.

Small amounts of corrosion can be detected over relatively long distances on pipes. - Corrosion measured 18-in from the seam defect.

- Likely can be measured at greater distances.

Cathodic protection did not cause any noise or other adverse effects on sensor.

Corrosion sensors responded to the presence of cathodic protection. - When 850 mV above the corrosion potential was applied all sensors detected no corrosion.

- Cessation of the impressed current caused the sensors to begin showing electrochemical reactions

taking place on the pipe. The magnitude of corrosion varied by location relative to the defect site.

- Application of a 100 mV polarization potential, in accordance with NACE SP01-69, resulted in

corrosion rates falling an order of magnitude or greater in 4 days.