Pipeline Coating

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As pipelines are either buried underground or underwater, they need protection against external corrosion due to environmental factors like water, salts etc.

INDEX

  1. Pipeline Corrosion and Coatings
  2. 3LPE Coating
  3. CTE Coating
  4. Comparison of Pipeline Coatings
  5. Pipeline Holiday Detection
  6. Pipeline Field Joint Coating

Pipeline Corrosion and Coatings

Onshore Pipelines

  1. All metallic buried pipelines including duplex material pipelines, shall be coated externally.
  2. Pipelines shall be coated externally by a suitable  anti-corrosion    coating, supplemented  by  cathodic  protection.
  3. Ensure  that  adequate  cathodic  protection can be demonstrated at all times, pipelines shall be electrically isolated individually from the plants to which they are connected.
  4. The design of cathodic protection for onshore pipelines shall be carried out in accordance with company standard.
  5. Pipelines installed above ground should be coated or  the   design   of   the  pipeline  supports  should  be  such  as  to  prevent  pipeline  corrosion  at  the  support points.
  6. NOTE: Short life pipelines (e.g. flowlines) may be installed   above   ground,   without   anti- corrosion  coating,  when  experience  can show that such arrangement does not lead to external corrosion (e.g. in dry climates).
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Offshore Pipelines

  1. All metallic buried pipelines including duplex material pipelines, shall be coated externally material pipelines, shall be coated externally by a suitable    anti-corrosion    coating, supplemented  by  cathodic  protection for the part of the system below the water level.
  2. Impressed current for cathodic protection of offshore pipelines is not recommended.
  3. To ensure that adequate cathodic protection can be demonstrated, pipelines should be electrically isolated individually from platforms.
  4. Alternatively mathematical modelling may be used to achieve confidence that adequate cathodic protection can be achieved in which case electrical isolation is omitted.
  5. The sections of the pipeline located at the air/water interface (e.g. splash and spray zones) are critical with regard to external corrosion and special coating or claddings should be used (e.g. vulcanised polychloroprene, external cupro-nickel cladding).

 General Notes

  1. The sections of the pipeline that are externally insulated (either for thermal requirements or fire protection) should be designed to prevent ingress of water in the annulus between the pipeline and the insulation, and should be inspectable for external corrosion.
  2. Apart from the field joint areas, factory applied linepipe coatings, as opposed to field applied coatings, should be used.
  3. Cathodic overprotection in terms of differential potential shall be avoided. Duplex stainless steels and high grade carbon steels (above X60) are particularly sensitive to hydrogen embrittlement caused by excessive cathodic protection voltage.
  4. Electrical isolation of pipelines from plants or platforms should be by means of monoblock isolating joints located above ground or above water. The joints, preferably to be installed in an inclined or vertical position, shall be capable of withstanding any mechanical loads resulting from the adjacent pipework configuration.
  5. When the transported fluid is conductive (e.g. high water cut), the length of the isolating joint required to achieve sufficient electrical isolation may be too large, and an internally coated isolating spool is preferred (refer to DEP 30.10.73.31-Gen.).

 Internal Corrosion

  1. Linings may be used for internal corrosion protection, provided the lining material does not degrade following long-term exposure to the transported fluid, at the pipeline pressure and temperature conditions.
  2. Care is required to ensure continuity of the lining at the joints.
  3. Polyethylene linings are susceptible to attack  by aromatics,  and to  permeation of  any dissolved gas in the transported fluid.
  4. To prevent lining collapse when the  pipeline is depressurised, the permeated gas should be relieved from the annulus.
  5. Internal coatings  shall  not  be  used  for  the  purpose  of  preventing corrosion,  because holidays in the coating cannot be completely avoided.
  6. In some situations, internal coatings may be applied for internal corrosion mitigation, when the expected leaks are deemed acceptable, following a review of the safety and environmental aspects.
  7. Internal paint markings for individual pipe identification should not be used when corrosive conditions will be present in service.
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Provisions for corrosion monitoring

  1. For buried or submerged pipelines, the occurrence of coating damage is normally monitored by cathodic protection measurements (refer to DEP 30.10.73.31-Gen.).
  2. If the pipeline is made of corrosion resistant material (e.g. duplex, GRP, cladsteel), there is normally no need to monitor for internal corrosion.
  3. For carbon steel pipelines, the control of internal corrosion is normally by applying a tight control on the process  parameters  (e.g. water dewpoint in gas transmission  systems, injection of corrosion inhibitor).
  4. Corrosion probes and corrosion coupons cannot be relied upon to provide a definite assessment of the pipeline condition, nor to demonstrate that internal corrosion is not occurring.
  5. Some indication of internal corrosion in the pipeline may be given by an analysis of debris recovered following a pigging operation; this technique is qualitative and is not able to provide any estimate of corrosion rates.
  6. When corrosive conditions which may lead to significant corrosion damage are present, either internally or externally, a complete inspection of the pipeline should be carried out using intelligent pigging.
  7. Intelligent pigging should also be used when the criticality of the pipeline is such that proof of continued integrity is required.

 Internal Coatings

  1. Internal coatings, such as fusion bonded epoxy or two pack phenolic epoxy paint (flow coat), may be used in the following situations: to limit corrosion during transit and storage, to facilitate precommissioning, to reduce hydraulic friction losses, pig wear and the formation of pyrophoric dust.
  2. Pyrophoric dust (FeS) may be produced in natural gas pipelines, when the gas contains H2S (even in small quantities), under specific conditions.
  3. FeS will form when the gas is in contact with bare steel pipe over a sufficient period, and the water vapour content of the gas is in excess of 60 percent of the content corresponding to the water dew point.
  4. FeS may create operational problems, particularly at pressure reduction stations; it is a hazard when it comes in contact with air, e.g. when it is recovered at a pig receiver (self ignition).
  5. Finally, the dust can  accumulate at  isolating flanges  and, since  it is conductive, render them ineffective.
  6. When pyrophoric dust is expected, internal coating of the pipeline is strongly recommended (coating at the field welds, however, is not required).

External Coating Types

  1. 3LE Coating / 1 Layer FBE
  2. CTE Coating

Coating Process

  1. Bare pipe visual inspection : Pipe no., Heat No. Length, Dia, Thickness, bevel and body damages like dents, gauges etc.
  2. Shot blasting and visual inspection : Roughness check on body, body dents and gauges.
  3. Preheating of pipes to 200 deg c by induction coil or gas oven.
  4. Uniform application of epoxy.
  5. Complete other coats. Check temperature of extruders, PE Film, Adhesive Film, Coal Tar Enamel etc.
  6. Cool coated pipes in cooling tunnel and perform visual inspection of coated pipes. Check cooling water temperature, visual damage to coating, coating thickness etc.

 Coat Testing

  1. Check for holiday at 25 KV for 3LPE Coating and 15KV for CTE Coating.
  2. Mark pipes for teting e.g. peel test, AP Test, Impact Test etc and coating repair.

 External Painting

  1. Paint coating.
  2. Mark details.

Youtube Videos

Pipe Cleaning & Coating Shot Blasting Machines :

3LPE Coating

  1. It’s a 3 Layer Polyethelene Coating / FBE Coating.
  2. 1st Layer : Fusion Bonded Epoxy – 50 Microns (200 to 300 Microns – FBE Coating)
  3. 2nd Layer : Side extrusion adhesive (LDPE) – 200 to 300 Microns.
  4. 3rd Layer : Side extrusion polyethelene (LDPE/MDPE/HDPE) > 2 MM.

Youtube Videos

3 Layer Polyethylene Coating (3LPE) – Pipe Coating :

3LPE coating production video :

CTE Coating

  • It’s a Coal Tar Enamel (CTE) Coating.
  • 1st Coat : Coal Tar Primer – 50 to 75 Microns.
  • 2nd Coat : 1st hot coal tar enamel layer with inner wrap > 1mm
  • 3rd Coat : 2nd hot coal tar enamel layer with inner wrap > 1mm
  • Final Coat : Coal tar impregnated outer wrap – 600 to 750 Microns.

Comparison of Pipeline Coatings

Factor CTE 3LPE 3LPP FBE
Service Conditions
Temperature Upto 45C Upto 65C Upto 110C Upto 110C
Anti Corrosion Properties
Resistance To Moisture Good Very Good Excellent Good
Cathodic Disbondment Fair Good Good Good
Electric Properties
Coating Resistance Good Excellent Excellent Excellent
Cathodic Protection design
Current Density High Low Low Low
Mechanical Properties
Resistance to Impact Poor Very good Excellent Fair
Resistance to Peel Fair Excellent Superior than PE
Resistance to Soil Stresses Fair Excellent Excellent Excellent
Elongation Fair Excellent Excellent
Long Term Ageing
Heat and Light Ageing Fair Very Good Very Good Very Good
Application and Field Repair
Ease of Application Easy Relatively Difficult Relatively Difficult Relatively Difficult
Damages during handling and Transportation High Low Low High
Ease of field Repair Difficult Easy for small repair, Cumbersome for larger repair Easy for small repair, Cumbersome for Larger Repair Easy for small repair, Cumbersome for Larger Repair

Pipeline Holiday Detection

Holiday detection means testing the coating of pipeline with 15 KV or 25 KV Voltage for any pores in coating.

Youtube Videos

In-Plant Holiday Detector ISOTEST act P2 – Porosity Testing of FBE and 3LPE/PP Pipe Coatings :

Holiday Detector :

Holiday Detection at site :

Holiday Detector (Detector de Porosidad) PCWI :

Pipeline Field Joint Coating

  1. The cut-back areas of Coated Pipes where weld joints are made are to be Coated by Field Joint Coating.
  2. Field joint coating material is heat shrinkable wraparound sleeve used as anticorrosion coating of buried onshore pipeline.
  3. Sleeve consist of radiation cross-linked, thermally stabilized, ultraviolet resistant semi-rigid polyolefin backing with a uniform thickness of high shear strength thermoplastic/co-melt adhesive .
  4. The joint coating system shall consist of a solvent free epoxy primer applied to the pipe surface prior to sleeve application.
  5. The surface area is blast cleaned to SA-2.5 followed by Pre-heating of pipe surface, application of epoxy primer and application of sleeve by heat shrinking.
  6. Each sleeve joint is inspected by means of a full circle holiday detector set to DC voltage at 25 KV (Pipe surface temperature below 50 degree Celsius) and thickness of sleeve checked.
  7. One out of 50 joints coating or one coating out of every day production shall be tested to establish peel strength on steel and factory applied coating.

Youtube Videos

Pipe Induction Heating/Coating :

PIH – Pipeline Induction Heat :

Welding and Coating of Steel Pipe :

One thought on “Pipeline Coating”

  1. I didn’t know that pipelines needed protection against external corrosion. There always seems to be a problem that needs to be fixed because of environmental factors. At least there are specialist that exist to solve these problems.

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