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Internal coating of multiphase pipelines - Requirements for the coating
Article in NACE - International Corrosion Conference Series · January 2010
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Paper No.
10004
2010
INTERNAL COATING OF MULTIPHASE PIPELINES – REQUIREMENTS
FOR THE COATING
Ole Øystein Knudsen
SINTEF Materials and Chemistry
Richard Birkelandsvei 2B
N-7465 Trondheim, Norway
Astrid Bjørgum
SINTEF Materials and Chemistry
Richard Birkelandsvei 2B
N-7465 Trondheim, Norway
Ann Karin Kvernbråten
SINTEF Materials and Chemistry
Richard Birkelandsvei 2B
N-7465 Trondheim, Norway
ABSTRACT
Pressure drop along the pipeline is the main obstacle to transportation of unprocessed or
partly processed multiphase fluids over long distances. Several parameters contribute to pressure drop in
multiphase flow, e.g. liquid hold-up, precipitations, gas-liquid surface drag forces, liquid wetting of pipe
wall and surface roughness. Application of coatings inside the pipeline can reduce pressure drop by
preventing corrosion, preventing precipitations on the pipe wall and modify the pipe wall wetting
properties. Meso scale pressure drop tests have shown that pressure drop is significantly affected by
moderate corrosion, even in multiphase flow, demonstrating that application of internal coatings is
beneficial. However, the coating must have the same lifetime as the pipeline. In this work we have tried
to identify the most important coating degradation mechanisms and to find relevant test methods for
evaluation and qualification of coatings.
©2010 by NACE International. Requests for permission to publish this manuscript in any form, in part or in whole, must be in writing to NACE
International, Publications Division, 1440 South Creek Drive, Houston, Texas 77084. The material presented and the views expressed in this paper are
solely those of the author(s) and are not necessarily endorsed by the Association.
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INTRODUCTION
Pressure drop along the pipeline is the main obstacle to transportation of unprocessed or partly
processed wellstream over long distances. Pressure drop in single phase pipelines is fairly well
understood, and available models are able to predict pressure drop with reasonable accuracy. Surface
roughness is the most important material parameter in this respect. Pressure drop in multiphase flow is
more complicated and less well understood. Several parameters contribute to pressure drop in
multiphase flow, e.g. liquid hold-up, precipitations, gas-liquid surface drag forces, liquid wetting of pipe
wall and surface roughness. Surface roughness in multiphase pipelines mainly depends on corrosion and
deposits and precipitates. Internal corrosion in low alloy steel pipelines due to CO2 is a well studied
phenomenon1. Today such corrosion is primarily controlled by use of corrosion inhibitors. However,
they are not 100% effective and some corrosion will always take place. In order to decrease corrosion,
hydrocarbon wetting of the pipe wall is important. Top of line corrosion due to condensation of water,
insufficient delivery of corrosion inhibitor and insufficient hydrocarbon wetting has in some cases been
a significant problem2.
Application of a coating inside the pipeline may provide an efficient solution to both the corrosion and
the precipitation and deposition problem. The application of internal coatings in order to decrease
pressure drop in multiphase pipelines have been studied in other projects, e.g. the Deepstar project. A
wide range of surface coating materials has been tested with respect to wax deposition, including
plastics, PTFE etc.
In the oil & gas industry there is a certain experience with internal coating of pipelines. Drag reduction
coatings are normally applied in pipelines transporting dry gas. Drill pipes are usually coated in order to
decrease corrosion, but due to short exposure time and the possibility of coating maintenance between
drilling operations, experiences with these coatings are probably less relevant to multiphase pipelines.
The objective with this work has been to understand how organic coatings in multiphase pipelines are
degraded in the wellstream environment.
DOCUMENTED EXPERIENCES WITH INTERNALLY COATED PIPELINES AND TUBING
The Scapa field is located outside Scotland. The field was developed in 1988 as a subsea satellite with a
template linked to the Claymore platform by a pipeline system. The pipeline system consists of two 4.5
km long bundles with a 10” oil production line, a 6” test/utility line and three 3” gas lift lines. The Scapa
pipeline fluid temperature was ca 60°C, the pressure was 2700 kPa at the template and 1000 kPa at the
platform. The gas phase consisted of 7% CO2 and 9 ppm H2S. The flow velocity was 1-2 m/s and the
corrosion rate was calculated to be ca 2 mm/year.
The pipelines were coated in situ after laying, before production start3,4. Cleaning and paint application
was done by multiple passes of two pigs with the cleaning agent or paint locked between them. The 10”
pipeline and the 6” pipeline were connected at the platform by two bends into 9 km long pipelines prior
to cleaning and coating application. Two test spools were also put in the connection loop at the platform,
for coating evaluation and testing after application.
The cleaning was done by combing runs with potable water and hydrochloric acid, removing internal
mill scale and producing a white metal surface. The lines were then dried with methyl ethyl ketone
(MEK) and passivated with phosphoric acid, forming a conversion coating of iron phosphate. Each
coating run took ca 30 minutes with a pig velocity of ca 5 m/s. The coating was allowed to cure for 24
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hours before the next coat was applied. The pipe was heated to 20-24°C by passing a DC current
through the metal.
The coating was an epoxy. Prior to exposure the coating was in very good condition, with a smooth
surface and no defects. An average dry film thickness (DFT) of 220 µm was achieved. The DFT was
generally lower on the welds, due to local topography.
The two test spools in the connection loop on the platform were removed and the coating application
evaluated shortly after application. The bends slowed down and interrupted the smooth movement of the
coating application pigs, which resulted in poor coating quality in the test spools. However, no blistering
was observed after two cycles of decompression. 300 runs with the PU foam pig and 500 runs with the
PU disc pig only resulted in scratching of the coating. 50 runs with the wire brush pig cut through the
coating at the protruding weld roots. After evaluation and testing the two spools were put back into the
pipeline. After two years the two spools were removed again and inspected. Visually the coating was in
good condition. The original holidays at the weld roots showed no evidence of any corrosion. The water
cuts were ca 3 to 15% during the preceding 8 months.
Lauer has reported successful use of internal coatings in a number of on- and offshore pipelines 5.
However, very little information has been given about the coatings, composition of the fluid, conditions
in the pipeline or performance of the coating. Table 1 lists some information for eight different
pipelines.
Table 1: Some pipelines installed with internal coatings 5.
Pipe
diameter Lentgh
Location (in)
(km)
Canada
2.5
Year
Coating Temp.
installed type
(°C)
Epoxy
1972
Phenolic
120
Epoxy
Novalac
1996
110
Epoxy
2000
Novalac
120
Epoxy
1984
Phenolic
80
Epoxy
Phenolic
1991
90
Kuwait
3
3, 4, 6,
10
130
Indonesia
4 and 8
23
Libya
US
onshore
US
offshore
US
offshore
US
offshore
3 and 4
100
3 and 16
14
6
3
2000
6
10
8
10
Pressure
CO2
(kPa)
H2S
700
Trace
51 ppm
35 000
Trace
Trace
15 000
11 %
Trace
7 000
4%
Trace
8 000
1%
90
14 000
10 %
1999
Phenolic
Epoxy
Phenolic
50 ppm
2000
ppm
110
10 000
2.80 %
N/A
1999
Epoxy
90
12 000
3.60 %
N/A
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TEST METHODS FOR INTERNAL PIPELINE COATINGS
The principal mechanisms that may degrade the coating inside the pipeline are assumed to be:




Ageing and subsequent loss of barrier properties or loss of mechanical properties
Decompression blistering
Mechanical degradation due to pigging or erosion
Corrosion at coating damages
The following sections review some published test methods for the listed degradation mechanisms.
Ageing
No test method has been issued for evaluation of ageing properties of coatings in multiphase pipeline
environments. However, exposure tests for coatings to various chemicals have been prepared by ISO6
and ASTM7,8. The coatings are exposed to chemicals that are relevant to the service environment. After
exposure the coatings are evaluated visually with respect to any type of degradation or change in
physical appearance, or testing of mechanical properties can be performed.
The NORSOK M-710 describes an ageing test method for non-metallic sealing materials. It is not a
coating test, but the test environment is relevant for internal pipeline coatings. The material is exposed to
a water phase, a solvent phase and a gas phase. The gas phase is consisting of CH4 and CO2, and for sour
service also H2S. After exposure the materials are evaluated with respect to tensile strength, hardness,
elongation and E-modulus.
Based on the issued standards and properties of the multiphase pipeline environment we are working
with various coating exposures and evaluation methods for barrier properties and mechanical properties.
However, this work is not ready for publication yet.
Decompression blistering
Several standards describe tests for decompression blistering resistance to pressure variation. API RP
5L2 describes both gas and hydraulic decompression tests9. In the gas decompression test the coated
sample is exposed to 8300 kPa nitrogen for 24 hours, before the pressure is released in less than 3
minutes. In the hydraulic test the sample is exposed to a saturated CaCO3 solution at 16 500 kPa for 24
hours before the pressure is quickly released. The samples are evaluated with respect to blistering. ISO
15741 describes similar decompression blistering tests as API RP 5L210, but also a cyclic pressure
variation test.
Mechanical degradation
Jelinek tested coating wear damages by cleaning pigs in a 0.5 m 10” pipe section3,4. The coated pipe
section was exposed to 300 runs with polyurethane (PU) foam pig, 500 runs with hard PU disc bidirectional pig and 100 runs with wire brush. The coating showed good resistance to wear. After 300
runs with PU foam and 500 runs with PU discs the coating thickness was reduced by between 13 and
52%. The 100 runs with the wire brush pig resulted in wear that penetrated the coating, but only at the
welds. The weld root protruded out from the inner pipe surface, which made the welds more vulnerable.
Abrasion resistance improved after exposure at elevated temperature, probably due to post curing.
Three ASTM standards are also relevant for testing wear properties of coatings. The ASTM G99
tribometer involves a ball shaped or a pin upper specimen that slides against a rotating disk as a lower
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specimen11. The results obtained are the coefficient of friction, the amount of wear on the pin and on the
disk and a description of the wear. The ASTM G105 rubber wheel test is used to evaluate the abrasive
wear behavior of materials12. In the test, a plane specimen is loaded against the rim of a rotating rubber
wheel; the abrasive silica slurry is carried up, out of a bath of slurry. The abrasive particles are fed into
the gap between the wheel and specimen and thus abrade it. The ASTM D4060 Taber abrader can also
be used in order to evaluate the wear resistance of the coatings13. In this test the organic coating is
applied on a flat surface, and after curing the surface is abraded by rotating the panel under weighted
abrasive wheels. Abrasion resistance is calculated as loss in weight at specified number of abrasion
cycles.
Corrosion at coating damages
Few of the standards found describe specific corrosion tests for internal pipeline coatings, probably
because they are made for testing coatings for dry gas pipelines where corrosion should be no problem.
The only pipeline coating standard that describes a corrosion test is API RP 5L2, which is using the
ASTM B117 continuous salt spray test. For atmospheric coatings, the salt spray test is heavily criticized
for having low correlation to field exposure. Whether this is the case for internal pipeline coatings as
well has not been investigated, but due to the very different environments in the test and the pipeline this
can be expected.
Jelinek tested the corrosion protection properties of an internal epoxy coating with the following test
method 3: Electrolyte: 8% NaCl, pressure: 100 kPa CO2, temperature: 60°C. The test duration was 60
days. After the test corrosion rate was determined by electrochemical impedance spectroscopy (EIS) and
atomic absorption spectroscopy analysis of iron in the water phase. Testing was performed in the pure
electrolyte and the electrolyte with 30% crude oil. After the test the coating was visually inspected for
undercutting. He concluded that the corrosion rate at coating damages was comparable to uncoated steel.
EXPERIMENTAL
Test panels and coatings
Flat steel panels about 60 mm x 100 mm x 3 mm were cut from carbon steel panels (DIN 17100/UNS
G10150). Prior to coating application, the panels were pre-treated by blast cleaning to Sa 2½ (NACE
No. 2).
Table 2. Coating systems.
Code
Number of coats
A
B
C
D
E
F
1 coat
1 coat
1 coat
1 coat
2 coat
2 coat
Generic type
Solventless epoxy
Solventless epoxy
Solvent borne epoxy
Solventless epoxy
Epoxy + epoxy powder
Epoxy + epoxy powder
The reverse side and bare edges of the different panels were sealed with an epoxy mastic coating. Prior
to corrosion testing, 2 mm scribes were made in the coating, parallel to the longest edge of the samples,
using a horizontal milling machine. Coating C, D, E and F were applied by the coating supplier.
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Corrosion testing
Some of the panels were pre-corroded by salt spray in order to create a crevice between the coating and
the substrate. Our aim was to obtain 3 mm scribe creep corrosion before the autoclave test, but this was
not achieved for all coatings. The purpose with the pre-corrosion was to study whether corrosion
inhibitors were able to penetrate the crevice under the coatings and prevent corrosion.
Corrosion testing was carried out using two identical autoclaves. The panels, three parallels of each
coating system, were placed in each autoclave as shown in Figure 1. A volume of 7.5 - 8 litres
electrolyte was added, resulting in halfway submersion of the scribed panels. The electrolyte was a 5%
NaCl solution, stabilized at pH 4.0 with an acetate buffer. A film forming inhibitor in a concentration of
50 ppm was added to one of the autoclaves. 100 % CO2 was purged through the electrolyte while the
temperature was increased to 60°C and the pressure was increased to 1000 kPa. The electrolyte was
purged with CO2 for one day. pH measurements and CO2 purging were repeated approximately once a
week. After 24 days of exposure, the pH had increased to 4.4 and 4.7 in autoclaves with and without
inhibitor, respectively. The panels were examined visually after 27, 40 and 56 days of exposure. Due to
severe blistering in submerged areas samples A, C, and D were removed after 56 days. The test was
terminated after 81 days for system B, E and F. The electrolytes in the two autoclaves were changed
three times, after 27, 49, and 62 days of exposure.
After testing, the panels were rinsed using a nylon brush and running tap water. The exposed panels
were photographed. Surface topography of corroded panels of coating systems A, C, and D were also
documented by 3D images. Delaminated coating along the scribe was then removed using a scalpel.
Figure 1. Autoclave with coated panels halfway submerged in the chloride
electrolyte. Photographed after the corrosion test was finished.
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Decompression blistering
The coated samples were exposed in an autoclave for 24 hours halfway immersed into the same
electrolyte as used for the corrosion testing. The temperature was 100°C and the autoclave was
pressurized with nitrogen at 15 000 kPa. After 24 hours the temperature in the autoclave was taken down
to 90°C. The pressure was then released at a rate of 2000-4000 kPa/min.
RESULTS AND DISCUSSION
Corrosion
Due to severe blistering in submerged areas, samples A, C, and D were removed from the test after 56
days. The remaining coating systems were exposed for 81 days. After 81 days some blisters were
observed in coating B, while the two-layer coating systems E and F showed no blistering. Increased
coating film thickness and application of two or more coats are known to improve the barrier properties,
and thus increase resistance against osmotic blistering. This obviously was the case in this test as well.
Table 3 shows that the three coatings that developed blisters in the test also were the three thinnest
coatings. Figure 2A shows blistering of coating A after 56 days exposure.
After the test the panels showed deep corrosion attacks in and around the scribe in submerged areas. In
the part of the sample exposed in the gas phase corrosion had not spread outside the original scribe. On
two of the panels the corrosion attack had even penetrated the 3 mm steel panel. Removing the coating
along the scribe showed that the steel substrates were severely attacked by uniform corrosion. Corroded
areas were generally deeper on panels exposed in the test solution without inhibitor, indicating that the
inhibitor had some effect on the corrosion rate. However, the selected inhibitor was not very effective
under the conditions used, which somewhat limited the value of this test.
After removing delaminated coating, the width of the corrosion attacks along the scribe was measured.
Table 3 shows the maximum length of corrosion from scribe for all the samples tested. The results show
that the inhibitor had no effect on the width of the corroded areas. This is primarily explained by the fact
that the inhibitor had a limited effectiveness under the test conditions used. The question whether the
inhibitor is able to penetrate into the crevice under a delaminated coating can therefore not be answered
after this test.
For coating system A and B both pre-corroded and fresh samples were exposed in the autoclaves. There
was no difference in depth of attack or width of affected area between pre-corroded and fresh samples.
Also, the corrosion width was independent on type of coating. Coating A, C and D had less corrosion
than Coating B, E and F, but this was due to the fact that B, E and F were exposed for a longer period of
time than A, C and D.
The corrosion attack under the coatings propagated somewhat differently from what is observed on
coatings in corrosive atmosphere. In corrosive atmosphere the corrosion creeps under the coating,
usually giving rather shallow attacks, and the corrosion products lift the coating from the substrate. In
this test the corrosion seemed rather to propagate by an anodic undermining mechanism, like illustrated
in Figure 3. Looking at the surface of the sample after the test before removal of loose paint, one could
not see how far the corrosion had propagated, because the corrosion products were not pushing the
coating up. The fact that the width of the corrosion attack was independent of type of coating also
suggests that the corrosion mechanism is different from what we find in atmosphere.
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Corrosion creep in atmosphere is normally considered to propagate by a mechanism where the coating
in front of the attack looses adhesion by cathodic disbonding, and that corrosion creeps after when
adhesion is lost14,15. In the autoclave test the samples were exposed in an oxygen free environment, and
earlier studies have shown that cathodic disbonding is very slow in oxygen free environments16. This
may explain why the corrosion seems to propagate by a different mechanism. The rather deep attacks of
general corrosion in and around the scribe also indicate that corrosion inhibitors should have no
problems entering the corrosion front under the coatings, and that we perhaps does not need to fear that
the inhibitor will be ineffective under a delaminating coating. This will be investigated further.
Table 3. Corrosion from scribe after corrosion testing in autoclave.
DFT
[µm]
A
B
C
D
E
F
171 ± 9
311± 11
69 ± 1
91 ± 1
247 ± 2
228 ± 1
A
10 mm
Exposure
[days]
56
81
56
56
81
81
No inhibitor
As painted Pre-rusted
[mm]
[mm]
7.0
7.2
10.7
11.2
7.1
8.1
10.7
10.2
Inhibitor
As painted Pre-rusted
[mm]
[mm]
5.2
5.8
10.8
10.2
6.1
8.4
11.8
11.7
B
10 mm
Figure 2. Coating degradation after corrosion testing. A: Blistering due to low film thickness. B:
Corrosion in coating damage.
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Figure 3. Propagation of corrosion under the coating when submerged in formation water.
Decompression blistering
The results from the decompression test are shown in Table 4. The two powder coatings gave the best
performance in the test. The blisters that appeared on coating E were all superficial and could not be
regarded as a degradation of the coating. Coating B also showed rather good performance in the test.
Coating A had lots of blisters in the submerged part of the sample, but no blisters in the gas phase. This
indicates that the blisters may have been formed during exposure in the electrolyte prior to
decompression. As shown in Figure 2A, coating A was susceptible to blistering when exposed in the
electrolyte. Investigation of cross sections after the test confirmed this, since all the blisters were located
at the steel/coating interface. Hence, coating A gave no decompression blistering. Coating C and D
blistered both in the immersed part and the part exposed in the gas phase. Again the blisters in the
immersed part of the samples were located at the metal coating/interface and most likely appeared
before decompression. However, the blisters above the liquid phase must be due to the decompression.
Figure 4 shows a cross section of a blister in the gas phase of sample B. The picture shows a crack in the
coating between several pores in the coating, about 50-100 µm in diameter. Hence, the blistering seems
to be associated with pores in the coating. During compression the gas may enter these pores, and when
the pressured decreases the gas expands and creates cracks and blisters in the coating. The amount and
density of pores in coating B indicates that the coating was not applied in an optimal manner. The
solvent less epoxies are rather viscous and require high pressure spraying equipment, and for some
products it is also recommended to heat the wet paint in order to decrease the viscosity. The amount of
pores in this film indicates that the paint was too viscous during application.
The decompression rate used in this test is quite high, compared to the decompression rate observed in a
pipeline. During a controlled decompression of a pipeline of some length removal of the fluid takes
several hours, which means that an internal coating will experience much smaller pressure gradients
than in this test. Hence, how much emphasis that should be put on decompression blistering results can
be discussed.
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Table 4. Size and density of blisters in samples after decompression test evaluated according to
ISO 4628-2.
Coating
A
B
C
D
E
F
DFT [µm]
Average
St. dev.
221
5
374
9
56
1
76
3
177
3
131
2
Blistering
Immersed
Gas phase
5 (S4)
0
2 (S2)
2 (S2)
5 (S4)
5 (S4)
5 (S3)
5 (S3)
2 (S2)
2 (S2)
0
0
100 µm
Figure 4. Cross section of sample B after decompression blistering test.
Ageing and wear
Ageing and wear of the coatings are also studied in this work, but will not be reported here.
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CONCLUSIONS
Organic coatings may be applied inside pipelines in order to decrease pressure drop, particularly for long
pipelines. The most important degradation mechanisms are assumed to be:
 Ageing and subsequent loss of barrier properties or loss of mechanical properties
 Decompression blistering
 Mechanical degradation due to pigging or erosion
 Corrosion at coating damages
This work has focused on test methods and degradation mechanisms related to decompression and
corrosion at coating damages.
Corrosion at coating damages was investigated in an autoclave test where coated samples with scribe
were half way immersed in artificial formation water (5% NaCl, pH 4.0) at 60°C in 1000 kPa CO2
atmosphere.
 Corrosion spread from damages in the coating, probably by a uniform CO2 corrosion
mechanism. The corrosion was independent of type of coating or whether the coating had a
delamination around the scribe prior to exposure.
 Coatings below 200 µm dry film thickness developed blisters in the test. Higher film thickness
and multiple coats decreased the tendency to blistering.
 An important issue was to see whether corrosion inhibitors could stop corrosion in the crevice
under a degraded coating. However, no conclusion can be made at present because the selected
inhibitor was rather ineffective. However, the corrosion under the coating did form rather deep
attacks, which should help diffusion of the inhibitor under the degraded coating.
Decompression blistering was investigated in nitrogen atmosphere at 90°C, where the pressure was
decreased from 15 000 kPa to atmospheric pressure at a rate of 2000-4000 kPa per minute.
Decompression blisters were associated with pores in the coatings.
ACKNOWLEDGEMENTS
Thanks to Statoil, Total, Carboline, Jotun, 3M, Tuboscope, AkzoNobel, BrederoShaw and the Research
Council of Norway for financial support of the project.
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paper no. 90254. (Houston, TX: NACE, 1990)
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Transmission Service (2002)
ISO 15741, Paints and varnishes - Friction-reduction coatings for the interior of on- and offshore
steel pipelines for non-corrosive gases (2001)
ASTM G99, Standard Test Method for Wear Testing with a Pin-on-Disk Apparatus (2005)
ASTM G105, Standard Test Method for Conducting Wet Sand/Rubber Wheel Abrasion Tests
(2002)
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Abraser (2007)
B. Reddy, M. Doherty, J. Stykes, Electrochimica Acta (Vol. 49, No. 17-18, 2004). pp. 2965-2972
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