OTC 16026
The Benefits of Using Internal Plastic Coatings on Chrome Tubulars
Robert S. Lauer/Tuboscope, A Varco Company
Copyright 2004, Offshore Technology Conference
This paper was prepared for presentation at the Offshore Technology Conference held in
Houston, Texas, U.S.A., 3–6 May 2004.
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Abstract
Chromium alloy tubulars are fast becoming the material of
choice for environments where CO 2 corrosion is of concern.
Prior to this point, internal plastic coatings had been one of the
main ways of controlling corrosion on carbon steel for similar
type applications. As the concern about corrosion has
minimized with the chrome tubing, internal plastic coatings
are being used in new and innovative ways to increase the
efficiency of the overall well dynamics, as well as protect the
tubing from flow assurance concerns as well as ancillary
corrosion concerns as the well matures. The use of internally
coated chrome tubing for improved hydraulic efficiency is
gaining momentum in the industry. This use of internal plastic
coating has proven tremendous economic advantages in
improved flow, decreased utility consumption or decreased
construction costs. In addition to this, internal coatings have
proven a positive effectiveness with respect to the deposition
mitigation aspects of flow assurance in conjunction with or as
a stand-alone treatment. A completely un-expected benefit
has been the protection of the chrome tubing from other forms
of corrosion. This value was determined not by theory or
laboratory data, but by actual statistical analysis of the
inspection reports from the used material. As the costs to drill,
complete, and produce a well increase, and as the industry
moves into deeper water, it is imperative to have either
multiple systems to ensure protection or to have systems that
will perform multiple functions. Protecting and maximizing
the usage of these assets is becoming key.
Introduction
Corrosion and effective corrosion control can mean the
difference between a successful operation and an expensive oil
and or gas well. The cost of different types of corrosion
mitigation treatments in conjunction with the costs of shutting
in a well, working it over to pull the tubing, or fishing the
tubing can be huge. It is these costs as well as real and
perceived problems with existing methods of treatment
(chemical inhibition, composite materials, organic and
inorganic coatings) that has lead the industry into finding
alternative methods of protection. The use of corrosion
resistant alloys (CRA) is becoming an industry standard,
where economically feasible, for handling potential corrosion
concerns as well has offering increased erosional velocity
capability. Most of the CRA’s are manufactured by alloying
differing levels of elements; such as chromium, molybdenum,
or nickel with iron. The expense of these alloys has led to the
practice of trying to use some of the lower concentration
alloys for this protection.
The chromium alloys have become the product of choice for
dealing with CO 2 corrosion. The most prevalent of these
alloys used today is 13% chrome, while higher concentrations
from 15 to 25% chrome can be used in more severe
environments. Corrosion from CO 2 , while of major concern,
is not the only species that can be corrosive in these
environments. Corrosion from elevated levels of oxygen and
chlorides, as well as excessive exposure to certain acids can be
detrimental to these chromium alloys. Martensitic stainless
steels, such as 13 Cr, are highly susceptible to pitting attack in
oxygenated fluids, especially in the presence of chlorides.1 It
is the realization of the potential shortcomings of these
materials that has led to an in-depth analysis of used tubing
that was in onshore and offshore applications along the Gulf
of Mexico. The results of this analysis have posed some
interesting questions about how to effectively protect against
corrosion while maximizing the corrosion protection asset.
Other issues that have arisen from the use of these chrome
alloy materials is their effect on overall system flow, as well
as their effectiveness against deposition for flow assurance
concerns. Due to the rough nature of the steel surface after
manufacturing, an adverse condition is present with respect to
flow efficiency as well as deposit adherence. In an effort to
alleviate this problem, several avenues have been attempted to
alter the surface profile and surface chemistry.
Hydraulic Efficiency
The rough nature of a given surface is shown to have an
adverse effect on hydraulic efficiency in most flowing systems
due to the friction that is created. It has long been felt that
reducing the surface roughness and therefore reducing the
frictional interaction at the surface could increase flow
efficiency in a pipe system. Two methods of achieving this
surface have been proposed, mechanical smoothing of the
steel surface through fine grit blasting, milling or polishing, or
2
through the use of an internal plastic coatings. In 1967 D.R.
McLelland wrote: “A study of the frictional flow
characteristics of gas in plastic-coated tubing indicates an
approximate 25-percent increase in transmissibility resulting
from the low frictional characteristics of new plastic-coated
tubing, as compared to conventional plain tubing.” 2 Similar
increases have also been seen by mechanically smoothing the
steel surface. These mechanically altered surfaces have also
show that their life of increased flow is short due to the effect
that the system environment (fluids, gases, solids, and
flow/erosion) has on that surface. These same forces have
been shown to not adversely effect the flow enhancements
achieved through the use of internal plastic coatings.
Table 1 shows the combined data of many field measured
roughness values for a random sampling of various tubular
materials. There are several points worth mentioning when
looking over this table. First, the surface roughness of bare
13% Cr pipe is a nominal 45 microns. API specification (5CT
7th Edition) specifies that all mill scale shall be removed from
API 13Cr tubulars.3 The most common method for descaling
chrome tubulars is abrasive blasting. As stated previously, the
use of various mechanical means may produce a smoother
surface but may also not meet the API requirement of total
removal of the mill scale. The second point relates to the
Hazen Williams Coefficient for bare 13% Cr pipe of 80.
Since this is also referred to as the Hazen Williams “C” factor
some confusion exists between this value and the API RP14E
“C” factor for 13% Cr pipe (150 – 200) which relates to
erosional velocity. Care should be taken to keep the two
factors separate.
Comparing the nominal surface roughness numbers generated
from actual sample measurements shows that the use of
internal plastic coating can reduce the surface roughness by
about an order of magnitude (a factor of 10) relative to bare
pipe. Corrosion 2000 paper # 00173 “Internal Tubular
Coatings Used to Maximize Hydraulic Efficiency”, reviews
how surface roughness is measured and the most appropriate
factor and calculation to use for accurate measurements.4
The use of internal plastic coating on carbon as well as
chromium alloys (up to 22% chrome) has become an efficient
and cost effective method of increasing overall hydraulic
characteristics. The reduction in friction at the pipe surface
can increase the volume of flow or allow the use of a smaller
tubing size, effectively reducing material, construction and
handling costs. Volumetric flow rate increases can vary
between 0 to 35%. To fully understand the true impact of the
use of internal plastic coating on chromium alloy tubing, it is
important to include actual field histories instead of relying
solely on software analysis and laboratory testing.
Case History #1
A major worldwide operator was recompleting gas wells in an
onshore field with 13% Cr tubing to help deal with a CO 2
corrosion problem. As this practice progressed, the operator
began to experience production drops of approximately 20%.
During a brainstorming session, it was decided that normal
production rates could be regained by either redrilling the
OTC 16026
wells to allow for the running of larger diameter tubing or by
reducing the surface roughness of the normal pipe size being
put into service. Given the huge expense of redrilling and
recompleting each well, it was decided to focus on reducing
the surface roughness of the tubing surface. Two methods
were uncovered that would reduce the surface roughness to
adequate levels, surface polishing and internal plastic coating.
After extensive laboratory testing indicated that the internal
plastic coating would survive the environment, several test
wells were run using either the polished tubing or the
internally plastic coated tubing. The tubing that was polished
experienced increased production rates, but after two months,
rates sank back to what was being experienced with the bare
13% chrome tubing. The wells internally coated experienced
rate increases ranging from 15% to 35%. After one year in
service, there had been no drop in the production rate in the
wells that were internally coated. Implementation of the
practice of using internally coated 13% Cr tubing during
replacement has allowed this operator to regain lost
production from the switch to 13% Cr tubing. On average the
increased production from the use of the internal plastic
coating paid for the coating investment in less than 2 days.
Case History #2
A major offshore operator in the Gulf of Mexico was
researching alternatives to enhance the production rates of a
future subsea completion. The tubing used in this application
was 5 ½” 23#, 13% chrome. The bottom hole environment for
this well had a temperature of approximately 175°F with a
maximum pressure of approximately 7700 psi. It was decided
that the most cost efficient way to maximize the production of
this well was to use internal plastic coating to minimize the
frictional effects at the surface of the pipe. A novolac powder
coating was decided upon because of its ability to handle the
environment as well as its low surface roughness. A customer
performed computer hydraulic simulation was used to
determine what incremental improvement could be realized by
the use of internal plastic coating in this well. Given all of the
other well parameters, approximately 110 mmscf/day of gas
would be produced through bare chrome. The use of internal
plastic coating would allow approximately 145 mmscf/day of
gas to be produced, a 24% increase in production.
After the system cleaned up, the well was producing
approximately 147 mmscf/d through the coated tubing. Using
the original 35 mmscf/day increase in flow along with a
conservative $4/mscf gas rate, the increased flow through the
coated tubing yielding an additional $140,000 per day in gas
sales revenue. It took less than 12 hours to cover the cost of
internally coating this tubing.
Flow Assurance
As the dynamics of existing well parameters change, and the
cost of overall operation increases, the need for having a failsafe flow assurance program becomes more important. In
addition, as companies have drilled into remote locations
where fixing flow problems are difficult and uneconomical,
designing an effective multi-tiered protection system is key.
These problematic deposits can be composed of asphaltene,
paraffin, scale, hydrates or combinations thereof. It must be
OTC 16026
mentioned that hydrates form in somewhat of a plug rather
than a deposit on a surface. There is currently not sufficient
laboratory or field data to indicate the effectiveness of internal
plastic coatings on hydrate plugging. For asphaltene, paraffin
and scale deposition, internal plastic coating is effective in
different ways of mitigating deposition. For years, it was
assumed that the only reason internal plastic coatings had a
positive effect on the mitigation of deposits was due to having
a smooth surface, which minimizes mechanical adherence.
Laboratory analysis and field applications have indicated that
while this is true in some cases, it is not always the case.
Asphaltene Deposition
The mitigation of asphaltene deposits has proven difficult due
to wide variations in both the asphaltene molecule and the
associated resin that keeps it in solution. Destabilization of
that resin system causes the precipitation, coagulation and
eventual deposition of the asphaltene. This asphaltene/resin
destabilization typically occurs as the flocculation pressure
migrates down the wellbore.5 An asphaltene deposit cannot be
thermally solublized and due to the complexity of the
asphaltene/resin make-up, chemical dispersion is often
difficult. What has been learned through laboratory and field
applications is that with asphaltene deposition having a
smooth surface is not the most important factor in keeping the
deposit from forming and adhering. An experiment performed
placing positive and negative electrodes into an asphaltenic
fluid, where an electrical potential of 220 volts was applied,
resulted in the deposition of asphaltene on the positive
electrode indicating the negative charge of the asphaltene
molecule.6 Given this charged nature, having an internal
tubing surface that is void of these necessary charged binding
sites is very important in deposition mitigation. Certain types
of internal plastic coatings have shown through laboratory
evaluation to possess the necessary surface characteristics for
the mitigation of asphaltene deposition. Adjusting the surface
chemistry with the use of internal plastic coatings, could allow
asphaltene molecules, even if removed from their resin
system, to pass through the system without accumulating and
depositing on the pipe surface. Field applications have further
reinforced the results from the laboratory evaluations on the
effects of internal plastic coating on the deposition of
asphaltenes.
Case History #3
A Gulf of Mexico well was expected to operate in a pressure
range that would be conducive to the precipitation of
asphaltenes. Preliminary testing indicated that the use of a
high performance liquid phenolic coating would benefit this
system by retarding the deposition of asphaltenes through
surface chemistry alteration. Because the practice of using
internal plastic coatings for asphaltene mitigation was in its
infancy, the customer decided to use an asphaltene inhibitor as
the primary form of protection while using the internal plastic
coating as secondary. When the well was brought on
production, the asphaltene inhibitor injection point was
inadvertently plugged during the completion process and
could not be used, leaving internal plastic coating as the only
mode of protection. After 18 months, the zone was depleted,
3
and the tubing pulled. Inspection of the coating surface
showed that the precipitated asphaltene did not adhere to the
surface.
A second well in the same field underwent the same treatment
regime, but for this instance, the chemical injection point was
still viable and was therefore utilized. After the zone was
completed, the tubing was pulled, and an inspection of the
surface indicated that there was a paper-thin line
approximately ¾” wide traveling for several thousand feet
down one side of the tubing. Over all, the coating met the
design criteria of the system by not allowing an asphaltene
plug to take place. The only difference between the two
systems is that one was chemically inhibited, while the other
was inhibitor free.
Paraffin Deposition
Paraffin precipitation occurs when changes in conditions alter
the solubility of the paraffin molecule. The most common
cause of this change in solubility is a drop in temperature
below the wax appearance temperature for that particular
molecular distribution.6 The use of internal plastic coatings for
paraffin mitigation has been in practice for over twenty years.
The reason for this success has been due mainly to the reduced
surface roughness (lack of an area conducive to mechanical
binding) possessed by certain coating systems. Many testing
entities have tried to prove the effects of internal plastic
coating in the mitigation of paraffin deposition by taking an all
or none approach. What is understood with most other types
of applications in this industry is that typically there is no tool
that works in 100% of the situations at 100% efficiency.
Through twenty years of field history with the use of internal
plastic coatings for paraffin mitigation there have been
applications where the threat of deposition has been
completely removed, as well as applications where the use of
internal coatings has delayed the need for ancillary treatment.
Care must also be taken in choosing the type of chemistry that
makes up the given coating or liner. Some systems have been
shown to have a porous top layer, which will allow paraffin to
set up an anchor point allowing additional paraffin to stick to
itself forming a larger deposit regardless of the coating’s other
surface characteristics. Reduction of the effective surface
profile will at the very least minimize the ability of paraffin to
mechanically adhere to the pipe surface.
Case History #4
During production, a Gulf of Mexico well had been
experiencing difficulties due to the deposition of paraffin,
even though inhibition was being performed. With bare pipe
in the well and the addition of chemical treatment, the operator
was cutting for paraffin once per week. The well was pulled,
and the customer went back in with a powder applied novolac
internal plastic coating for deposition mitigation as well as
improved hydraulic efficiency. The introduction of the
internal plastic coating reduced the deposition of paraffin to a
level that cutting was only required once every 60 days. This
reduction in well intervention produced a savings of
approximately $45,000 per year, without even considering the
economics from the minimization of lost production due to
frequent interventions.
4
Scale Deposition
Scale is an inorganic species that will begin to precipitate as
the concentration increases over its solubility point. The
adherence of the scale deposit appears to be primarily
mechanical in nature. Bare steels, both carbon steel and
chrome alloys, no matter how smooth the surface as it enters
the well, will roughen due to erosion and corrosion as the well
ages. Internal plastic coatings have a surface roughness much
less than that of carbon steel and chromium alloys, and the
coating surface has shown it will not roughen with age. As
with the treatment for organic deposits, coating effectiveness
has been as high as 100%, while in other areas, the use of
internal plastic coating has mitigated the deposition to a level
where acid treatment, surfactant soaks and washes, and
chemical treatments have been greatly reduced. This
minimization has reduced overall treatment costs and
decreased potential lost production due to treatment
interventions. A previously unrecognized benefit being
realized is that some scales, in sufficient amounts, have a high
enough N.O.R.M. (naturally occurring radioactive material)
level that the pipe requires special treatment prior to further
handling. The use of internal plastic coatings has been shown
to help prevent the deposit of these type scales, saving on
subsequent treatments.
Case History #5
A major E&P company was having a barium sulfate and
calcium carbonate scale problem in a North Sea oil producing
well. The current treatment choice of chemical inhibition was
not providing complete deposition mitigation for the system.
In an effort to mitigate corrosion problems that were occurring
as well as mitigate scale deposition, internal plastic coating
was applied. One of the main reasons the coating was used in
this application for scale deposition is because (1) barium
sulfate scale is very difficult to keep in solution due to its very
low solubility, and (2) the severity of the hazardous chemicals
that are required to attempt to dissolve the scale deposit once it
has adhered. The implementation of the internally coated
system alleviated the threat of scale deposition and minimized
the amounts of chemical inhibitor needed to treat the bare
portions of the system.
Corrosion Resistance
The use of corrosion resistant alloys (CRA’s) has become a
more common practice for combating corrosion and reducing
the threat of in service failures as well as future costly
workovers. The chromium-based CRA’s have shown
effective resistance to corrosion from CO 2 . While these
materials have greatly reduced CO 2 corrosion problems,
issues have arisen from the presence of oxygen, chlorides or
improperly inhibited acids if they are present in sufficient
concentration. A large number of wells that these materials
are being used in have a greater than 10 year design life.
What typically happens is that even though the desired well
life is long, the tubulars are pulled periodically for various
reasons. When these used tubulars are inspected prior to reinstallation, problems are being uncovered.
Non-destructive inspection of used 13% and 22% chrome
tubing has revealed what corrosive effects these species are
OTC 16026
having on the parent metal. This corrosion can cause the
material to be downgraded as well as cause a roughening of
the surface, which can retard hydraulic efficiency. Given the
small deep nature of pitting in chrome tubing (“worm hole
pitting”), a visual inspection often provides the location
information needed to pinpoint defects for further automated
inspections (Figure 1). Typically automated inspection
techniques, such as electromagnetics and ultrasonics, will be
looking for larger defects in area and in volume than the
worm-hole type pits possess, giving rise to new methodology.
Inspection reports for used carbon steel, 22% chrome and 13%
chrome tubing were compiled in a way that allows for sorting
based on many reject criteria. For the purpose of this
discussion, we will focus on pitting of the internal surface of
the pipe. It is important to use the same reject criteria for all
materials analyzed. To accomplish this, rejects were defined
by API standards (12.5% wall loss from API minimum body
wall). Table 1 shows the results of this compilation. The
important fact that needs to be understood when looking at
this data is that even though the reject rates appear somewhat
similar, it does not mean that they will all perform the same in
a given environment. As you go from carbon steel tubing up
to 22% chrome tubing, the environments typically get much
more corrosive. What is basically being inferred from this
data is that in their respective environments, these materials
are subject to corrosion. Knowing that the ID pitting
corrosion on the chrome tubing is largely due to exposure to
excessive levels of chlorides and oxygen, many physical as
well as chemical treatments have been brought to the market
in an effort to prevent this damage. These treatments can be
expensive, time consuming, as well as environmentally
unfriendly, and if not performed in a timely fashion on the
used material, can be completely ineffective.
Internal plastic coatings were introduced into the corrosion
control market nearly 60 years ago primarily for the protection
of carbon steel materials. As time has progressed, additional
benefits from internal plastic coatings have been uncovered
(see above). The internal plastic coating of chrome tubing
began approximately 8 years ago for the increase in hydraulic
efficiency. Further sorting of the inspection results for that
same used 13% and 22% chrome tubing into bare and
internally coated material yields some interesting results
(Table 3). For the 13% chrome tubing, the bare material has a
19% reject rate due to internal pitting, while the internally
coated material has a reject rate of only 1.2%. Similar results
are seen for the 22% chrome tubing. The bare material has a
reject rate of 14.9%, while the internally coated material has a
0.0% reject rate. The data shows that even on a corrosion
resistant alloy, internal plastic coatings can offer corrosion
protection. Given the expense of these alloys, it is important
to maximize the potential for reuse.
Conclusions
Chromium alloy tubulars are becoming more widely used due
to their corrosion resistance and the minimization of lost time.
While these materials offer corrosion resistance to CO 2
corrosion, they can become corroded by other species. It is
corrosion by these species that has led to the losses of what
OTC 16026
5
can be termed a true system asset. Using internal plastic
coating for improved hydraulic efficiency not only increased
overall production revenue, but also showed that these assets
can be protected from their environment, therefore
maximizing this tubular asset. While altering the surface
roughness has shown to be an effective means of increasing
flow, it has also proven effective, along with a chemically
inert surface, in the mitigation of deposits such as asphaltene,
paraffin and scale. Internal plastic coatings still prove they
provide corrosion protection, even to corrosion resistant
allows, while offering ancillary benefits in improved
hydraulics and deposition mitigation, which yield economic
benefits to the bottom line.
Total Joints
Reject Rate for
Inspected
ID Pitting
22% Chrome (Bare)
4,178
14.9%
22% Chrome (Coated)
532
0.0%
13% Chrome (Bare)
50,977
19.0%
13% Chrome (Coated)
12,056
1.2%
Table 3: Coated (IPC) vs. Bare Inspection Results
Tubing Type
Figures
References
1.
H. H. Hashim, B. D. Craig, “Corrosion and Cracking of 13
Chromium L-80 Tubing,” CORROSION/95, paper no. 75,
(Houston, TX: NACE, 1995).
2.
D. R. McLelland, “Field Test of Friction Losses in Plasticcoated Tubing,” presented at the API Division of
Production Southern Meeting 1967
3.
API 5CT “Specification for Tubing and Casing,” Seventh
Edition April 30, 2002.
4.
J. Nelson, R. Davis, “Internal Tubular Coatings Used to
Maximize Hydraulic Efficiency,” CORROSION/2000,
paper no. 00173, (Houston, TX: NACE, 2000).
5.
L. Brown, “Flow Assurance: A π3 Discipline,” OTC/2002
paper no. 14010, (Houston, TX: OTC, 2002)
6.
Allen, T.O. Roberts, A.P.: Production Operations: Well
Completions, Workover, and Stimulation, Second Edition,
Penwell Corp.,Tulsa, (1982) Chap. 2.
Tables
Average
Measured Surface
Roughness in
microns
(nominal values)
HazenWilliams
Coefficient
Tube-Kote®
Coated Pipe
2 – 10
(4)
150
Bare Carbon
Steel Pipe
30 – 40
(35)
100
Bare 13% Cr
Pipe
30 – 60
(45)
80
Average
Measured
Surface
Roughness in
inches
(nominal values)
7.86 x 10-5 to
3.94 x 10-4
(1.57 x 10-4)
1.18 x 10-3 to
1.57 x 10-3
(1.38 x 10-3)
1.18 x 10-3 to
2.36 x 10-3
(1.77 x 10-3)
Table 1: Surface Roughness Values
Tubing Type
Carbon Steel
22% Chrome
13% Chrome
Total Joints
Inspected
128,043
4,710
63,033
Table 2: Inspection Results Database
Reject Rate for ID
Pitting
11.5%
13.2%
15.6%
Figure 1: Pitted 13% Chrome tubing