2. INTERNAL
COATINGS
on
the
rise
N
atural gas transmission pipelines are critical elements of infrastructure. They supply not only energy, nationally and trans-nationally, but
can be viewed as strategic components required for a country or region’s long-term sustainable growth and development.
The operation and pumping costs of a gas transmission pipeline are significant, and the capacity of gas delivered by the pipeline
largely depends on three key design parameters – pipeline diameter, length and surface roughness.
In recognising these factors, the concept of internally lining gas pipelines was developed, providing enhanced flow and, therefore, reduced
operational costs. The application of a two component, solvent-based, red oxide epoxy to the internal surface of non-corrosive gas transmission
pipelines was first carried out in the late 1950s.
An increasing number of international oil and gas companies, such as CNPC, Shell, BP, Total, Gazprom, Statoil and Reliance, now recognise the
benefits of internally coating their pipeline assets in both an onshore and offshore environment and are specifying the use of a single coat, thin
film internal flow efficiency coating. Surprisingly, such coatings are still not as widely used as some would think, despite the significant and wide-
reaching benefits that they can offer. It is interesting to note that more than 60% of the top 20 largest oil and gas companies (by revenue in 2015)
now specify internal flow coatings.
The
real
inside
story on
internal flow
coatings for
gas pipelines,
as revealed by
Craig Thomas,
Senior Consultant, UK.
Figure 1. Pipe
stack formed from
large diameter
coated pipes,
creating a smooth,
low friction
internal surface.
48
3. During an interview with Noru Tsalic, Senior Consultant (2016),
Tsalic confirmed that “circa 71% of newly-coated steel pipes for
gas applications were provided with an internal epoxy lining”
in 2015, falling two percentage points since 2010. However, he
predicted that the general trend is one of increase and forecasted
76% by 2019. “Raw material consumption [of] liquid epoxy
formations for internal flow efficiency and corrosion protection”
totalled approximately 14.3 million l in 2015 and is expected to
increase to 16 million l by 2019.
According to the NGSA, gas transmission lines can vary in
diametrical size from 6 - 48 in. with most interstate pipelines
measuring 24 - 36 in. This would also be the most common
diameter range of national and transnational transmission pipelines
on a global scale.
From market research carried out, industry knowledge gained
over several decades and taking into account the above, it is
estimated that 85% of these “internal epoxy linings” were internal
flow coatings used for large diameter (24 - 48 in.) transmission lines
transporting non-corrosive gas, meaning that 60% of all “newly-
coated steel pipe for gas application” was lined in 2015 with what
can be considered a ‘true internal flow coating’.
Penetration in this area of pipe coating has been rapid in the
last 10 years, surging in the last 5 - 7 years compared to figures seen
at the stages of early adoption and during a slow yet sustained
growth period between 1960 - 2005. It is strongly believed that the
usage figure will continue to rise driven by a specification-fuelled
shift from uncoated to coated pipelines and a larger number of
pipe coating manufacturers to fulfil this demand.
In addition to enhanced flow and increased throughput, there
are many other economic and technical benefits available to
pipeline asset owners, specifiers and pipe coaters:
)) Corrosion protection in storage.
)) Optimised precommissioning.
)) More effective pigging.
)) Lower energy costs at pumping and compressor stations.
)) Reduced energy requirements – lower CO2
emissions.
)) Lower capital costs – less steel due to optimised pipeline
diameter.
)) Sealed surfaced – product purity.
)) Rapid payback.
)) Reduced valve maintenance.
)) More environmentally-friendly – high(er) solids materials –
lower volatile organic compound (VOC) content.
Surface roughness of an internal flow coating has been
excluded from the above list of key benefits, as the industry – for
many decades – has focused on the flow enhancement brought
about by application of a thin film epoxy coating; this coating
having a lower surface roughness than the uncoated steel pipe.
The advent of high(er) solids materials has seen it catapulted to a
major flow coating benefit, even to a point when levels of surface
roughness are now appearing in pipeline design specifications,
which has both positives and negatives. For this reason, surface
roughness will be treated as a separate topic in this article.
Enhanced flow/increased throughput
Oil and gas companies have identified that increases in capacity
of 14 - 21% and higher are achievable by internally coating their
non-corrosive gas transmission pipelines. It is generally accepted
that a 1% increase in throughput provides justification to apply an
internal coating from a cost perspective.
Data is available to illustrate that a reduction in the roughness
of the steel pipe surface (uncoated vs coated) can lead to
increased flow of gas in the pipeline and therefore improved
capacity.
An effectiveness study conducted by NOVA Corp in 1994
created justification for the use of an internal flow coating for a
new 152 km x 48 in. high pressure gas pipeline, estimating savings
of CAN$2.8 million (CAN$4.2 million at today’s dollar value) in
operational costs over the economic life of the pipeline asset.
Following technical and economic studies carried out by
Petrobras in 1999, it decided to internally coat 1800 km of 32 in.
pipe and 470 km of 24 in. pipe for its GASBOL pipeline, measuring
3150 km x 16 - 32 in. in size.
One noteworthy conclusion that can be drawn from a study
carried out by Zamorano in 2002, is that the capacity of a 530 km
coated section of the 20 in. dia. GasAtacama gas pipeline located
in Argentina-Chile, was considerably greater (at high pressure) than
the uncoated section.
Research by Y. Charron et al. (2005) drew particular attention
to the fact that “the use of relatively smooth [internal pipe]
coatings (2 μm) provides a considerable saving in capital and
operating costs compared to relatively rough coatings (20 μm).”
Comments were made that savings would be even more significant
at a higher pressure. A surface roughness of 20 μm Rz can also be
equated to a (slightly) corroded steel pipe, which can increase to
around 50 μm after storage; a blasted steel surface before coating
having a profile of 35 - 75 μm.
It is important to note and understand the word ‘relative’ and
the order of magnitude of flow enhancement relative to surface
roughness. The most significant improvements in flow efficiency
will be seen in coated compared to uncoated pipelines. Further
flow enhancement can be now delivered using a higher solids
coating compared to the original solvent-based systems, but the
percentage improvement is much less dramatic.
Corrosion protection in storage and during
precommissioning
NOVA Corp determined that significant deterioration of the
surface roughness of uncoated steel pipe takes place during
storage due to atmospheric oxidation and that an internal flow
coating protects against this corrosion as well as mitigates the
risk of any corrosive materials that may be contained in the
transported media.
Marine regulations now prohibit the disposal during
precommissioning of millscale and rust debris into the sea.
Common industry practice is now to blast clean the pipes and
apply an internal flow coating. This prevents rust from re-forming
SEPTEMBER 2016 / Reprinted from World Pipelines
4. on the steel surface in storage or during transportation, thus
eliminating the need for major additional precommissioning
work, which can be substantial in terms of time and cost,
particularly for pipes stored in a marine environment and used in
offshore construction.
When uncoated offshore pipelines are flooded with seawater,
the extent of corrosion can be substantial. In 2006, J. Grover
reported that an estimated 157 000 kg of corrosion debris was
removed from a 167 km section of 36 in. dia. pipe with a wall
thickness of 14.3 mm only 12 weeks after immersion in tropical
sea water. Grover stated: “Internal coating should be considered
not just on the merits of flow efficiency, but also for corrosion
protection and ease of cleaning and drying.”
Offshore gas pipelines can be immersed and filled with
seawater for six months or more, awaiting precommissioning.
The internal flow coating must, therefore, perform under such
pre-service conditions and this is where the corrosion protection
characteristic of the product can become important.
Design parameters of offshore pipelines can vary
considerably as can the environmental conditions, in which
they are constructed. As a result, it is difficult
to provide specific, yet meaningful, case study
data. It is, nevertheless, possible to provide an
estimation of an order of magnitude of corrosion
debris that could be created from a larger thicker
walled, uncoated offshore pipeline (370 km x 48 in.,
WT: 25.4 mm) after a period of six months – the
pipeline having been flooded with seawater. It can
be estimated using the same rates of corrosion
and identical engineering calculations to the above
report that five to six times the weight of corrosion
products might have to be removed by pigging
during the precommissioning phase; in simple
terms, approximately 864 000 kg.
Optimum precommissioning –
improved effectiveness, reduced
costs and time
The use of an internal flow coating provides for
easier and faster precommissioning of an offshore
pipeline after construction, bringing about more
rapid drying after hydrostatic testing. Uncoated
pipe can contain many tonnes of millscale and
corrosion products, which are costly and time
consuming to remove. By reducing the occurrence
of delays to the forecasted transmission start date
due to ‘problematic’ precommissioning, the coating
can pay for itself on this benefit alone.
Testing and robotic inspection procedures
are greatly simplified through the use of an
internal pipe coating, which aids movement of the
equipment along the pipeline over considerable
distances due to a smoother wall surface than
would naturally occur.
In 1994, Statoil reported that pigging on single
sections of the Zeepipe pipeline in the North
Sea of more than 992 km was feasible, provided
that “the line is internally coated and sufficient
precautions are taken during construction.” The
initial development phase of the 810 km x 40 in.
Zeepipe was internally coated with a thin film
epoxy coating. According to extensive studies,
this meant the whole pipeline could be pigged
in a single operation, eliminating the need for an
intermediate platform, originally planned to allow
the line to be pigged in two sections. The internal
joints (68 000) and pipe cutbacks (100 mm) were
Figure 2. Steel pipes lined with an internal flow efficiency coating at a large
storage yard in Australia. Image courtesy of Great Southern Press/DBP.
Figure 3. Uncoated steel pipe containing millscale and corrosion products.
Reprinted from World Pipelines / SEPTEMBER 2016
5. not coated, which amounted to 12 800 m
of uncoated steel.
It is now generally accepted that the
main surface of the steel pipe should be
coated to improve flow and protect from
corrosion. But what about the internal
joints? Every 12 m along a pipeline, there
is typically an uncoated internal field
joint. If a pipeline measuring 750 km x 36
in. with a 150 mm cutback is examined,
this translates into 62 500 joints and an
unprotected surface area of 53 750 m2
,
which can be subject to corrosion attack.
This is substantial and pipeline owners
and specifiers should critically review the
need to coat in the future. There are now
a number of companies that carry out
such internal joint coating to a very high
standard using robotic equipment.
In 2005, Statoil reported that it made
the decision to apply an internal epoxy coating to the Langeled
gas pipeline in the North Sea in order to increase transport
capacity as well as to reduce pig wear, claiming also that the
volume of millscale and corrosion products was reduced. In the
absence of an internal lining, it stated that extra pigging would
have been required. Statoil estimated that pigging distances of
800 km could be feasible, where carefully designed and built
pigs were used in combination with a smooth surface created
by the internal flow coating. The report went on to declare:
“Internal coating of the line was also beneficial (in regard
to drying), leaving less free water in the pipeline due to the
smooth swabbing action of the pigs.”
It is stated that pipeline cleaning can have a substantial
impact on both precommissioning and long-term reliability of
the pipeline asset. The volume of debris that can form impacts
on the precommissioning timeline to dry the pipeline, as it tends
to trap moisture. Corrosion products are very erosive, which can
cause damage to valves, flowmeters and regulators, according to
A. Barden’s article, ‘Preparation is everything’ in World Pipelines,
October 2006. “Many operators are so concerned about this
issue that they have decided to internally coat the pipe just to
mitigate against these problems.”
Lower energy costs at pump and compressor
stations
Industry analysis shows that pumping and compression costs
can be dramatically reduced over the lifetime of a pipeline by
applying an internal flow coating. It may also be possible to
engender further project cost savings by reducing the number of
compressor stations, compressor size or compressor capacity.
The 2002 Zamorano study also determined that fuel gas
costs for the compressor stations alone, which were situated
along the 1200 km length of the 20 in. dia. GasAtacama pipeline
were 26.9% lower on the coated section compared to the
uncoated section.
In a 2005 report, Shell Global Solutions disclosed it had
had positive experiences with the use of internal flow coatings
leading to associated CAPEX savings. Shell cited an example
relating to a 250 km gas pipeline required to transport 300
million ft3
/d. For an uncoated pipeline with an assumed surface
roughness of 50 μm, a pipe with an OD of 26 in. would be
required, where with a pipe that has been internally coated
reducing surface roughness by 80% to 10 μm, a 24 in. OD pipe
would be sufficient. This represents a potential cost saving of 5%
and a CAPEX saving of 2 - 3% on total pipeline cost.
In Norway, 35% of offshore-generated energy is used to
power gas export compressors. E. Sletfjerding et al. (1999)
reported that the use of internal efficiency coatings to reduce
the operating cost of compressor stations is important.
Surface roughness
It is a well-known and widely reported fact that internal flow
coatings reduction the friction in gas pipelines.
Surface roughness and pressure drop data pertaining to
coated and uncoated pipe have showed the “drag reducing
effect of [a] pipeline coating,” according to Sletfjerding et al. At
a Reynolds number of 1 x 107
, the friction factor (pressure drop)
in a coated pipe with a surface roughness of 5.79 μm Rz was
31% lower than in an uncoated steel pipe (surface roughness:
21.66 μm Rz). This translated into an increase in transport
capacity of the pipeline of 21%.
What is less widely known within the industry, is the
‘appropriate value’ for coating surface roughness to be used in
the various stages of planning, design and operation.
Based on a plethora of studies conducted over several
decades, it can be said that coated pipe will always have a
lower surface roughness than uncoated (corroded or blasted)
steel pipe. But what will be the effect of a higher solids flow
coating with lower surface roughness (1 - 3 μm Rz) compared
to a solvent-based flow coating (5 - 10 μm Rz) on throughput?
This is still a relative unknown, except to say that further flow
enhancement will of course be delivered, but the percentage
improvement will be much less dramatic than for coated vs
uncoated and has yet to be quantified.
Figure 4. Internally flow coated pipe being laid at the pipeline right-of-way.
SEPTEMBER 2016 / Reprinted from World Pipelines
6. Current international standards, such as API RP 5L2 and ISO
15741, do not make any reference to the surface roughness of the
applied coating. One key reason is the variability of application.
Other reasons, according to Charron et al., are variable operating
conditions and the difficulty to link surface roughness to hydraulic
roughness. Notwithstanding these important facts, the surface
roughness of internal flow coatings has started to be specified.
The consequence of a low surface roughness figure being
specified for a coating is that this then becomes a pass/fail criteria
for every pipe that is produced for that project. Perfect panel
preparation and coating application is very difficult to continuously
achieve in a coating laboratory, but what about in a coating
plant? Whilst there are many high quality factories in existence,
such uninterrupted application perfection is incredibly difficult
to achieve. If low and continuously repeatable coating surface
roughness in a pipeline is so critical to optimised flow efficiency,
it could be argued that such specifications should also call for the
internal joints to be coated.
Conclusion
Over the last six decades, internal flow coatings have clearly
demonstrated performance excellence and are now widely used
and specified. It is predicted that flow coating use and volumes
will continue to rise over the next 3 - 5 years, as more and more
pipeline asset owners seek to specify. Areas of interest for the
industry are currently moving from solvent-based to higher solids
coatings, the coating of internal joints and the implication of
specification of coating surface roughness.
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Reprinted from World Pipelines / SEPTEMBER 2016
