THE USE OF INTERNAL PLASTIC COATINGS
TO MAXIMIZE CHROME TUBULAR INVESTMENTS
Robert S. Lauer
Tuboscope, A Varco Company
2835 Holmes Road
Houston, TX 77051
Fax: 713-799-5212
Email: [email protected]
ABSTRACT
Chromium alloy tubulars are fast becoming the predominant choice for corrosion protection in oil and
gas production around the world. As this practice matures, field experiences have shown several
shortcomings in some of the chromium alloy tubulars with respect to their corrosion resistance in
oilfield production environments. These shortcomings have lead to an unacceptable level of asset loss
both during service in the field and during the reclamation process that follows. The shift now is to
search for effective ways to economically protect the lower concentration chromium alloys without
having to resort to changing to higher level corrosion resistant alloys (CRAs). One practice that is
gaining momentum is the use of internal plastic coatings to protect the lower concentration chromium
CRAs from the corrosive species that aid in the formation of “wormhole pitting” on the I.D. surface.
Ancillary benefits from using internal plastic coatings on chromium alloys have also been uncovered.
Coatings can reduce the effective surface roughness of the tubing, thereby improving hydraulic
efficiency. This benefit can take the form of increased overall flow, reduced overall operating
pressures, or the ability to reduce pipe size and still maintain expected flow. Also, minimizing the
surface roughness and offering a more chemically inert surface can provide for the mitigation of
organic and inorganic deposits. These benefits can maximize tubular investments as well as positively
impact flow assurance.
Keywords: Corrosion, corrosion resistant alloys, 13Cr, internal plastic coating, flow assurance,
asphaltene, paraffin, scale
1. INTRODUCTION
Corrosion and effective corrosion control can mean the difference between a successful and an
expensive oil and or gas well. For years people have tried to find the most effective method to control
corrosion without making the well un-economic. These methods include the use of chemical
inhibition, composite materials, organic and inorganic coatings, and corrosion resistant alloys.
Each method has its own positives and negatives, but CRAs are becoming the leading method of
corrosion protection in the industry today. An additional benefit gained from the use of these alloys is
their increased erosional velocity relative to that of basic carbon steel materials. The term “corrosion
resistant alloys” encompasses many different materials, each of which can offer protection from many
different corrosive species. Most of the CRAs are manufactured by alloying differing levels of
elements, such as chromium, molybdenum, or nickel, with iron. By adjusting the concentrations of the
alloying elements, a mill can produce a steel product that, for a particular oilfield environment,
possesses enhanced corrosion protection over basic carbon steel.
CRAs have become the product of choice for dealing with CO 2 corrosion. Several CRAs have become
the alloys of choice for dealing with CO 2 corrosion; namely: 13 to 22% chromium alloys. The most
prevalent of these alloys used today is 13% chrome. These materials offer superior corrosion
resistance when dealing with CO 2 corrosion, but that is typically not the only form of corrosion that is
encountered in the oil and gas industry. 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 tubing that was used in on and offshore application along the Gulf of
Mexico. Results of this analysis are included in this paper.
Given the environments, and overall well expenses, that these alloys are typically used in, it becomes
of great importance to optimize the hydraulic efficiency of the system, as well as to optimize flow
assurance. Internal plastic coatings can help with this optimization through their ability to adjust
surface roughness and therefore surface friction in conjunction with their ability to alter surface
chemistry and subsequent deposition points.
2. CORROSION RESISTANCE
13 to 22% chromium alloys have entered the oil and gas industry, as the CRAs to cure downhole
corrosion problems and prevent subsequent costly workovers. As these alloys have been exposed to
varying environments, it has been realized that these chromium alloys, while offering resistance to
CO 2 corrosion, have weaknesses to other corrosive species. The problems most commonly
encountered are with oxygen, chlorides, and improperly inhibited acids. These problems have lead to
the loss of entire CRA strings after pulling and inspection. In an effort to curb problems with oxygen
and chloride corrosion, especially in a salt spray environment such as on the deck of an offshore rig,
many physical as well as chemical treatments have been brought to the market. These treatments can
be expensive, time consuming, as well as environmentally unfriendly, and if not performed in a timely
fashion, can be ineffective.
Inspection of used 13% chrome tubing has revealed the extent that these species have corroded the
parent metal yielding an API inspection reject, as well as a rough surface that retards hydraulic
efficiency. Inspection methods include electromagnetic inspections, ultrasonic inspections, and visual
inspections. 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).
Compiling the data found in inspection reports into a format that groups different reject criteria, allows
one to further understand the full impact of certain corrosive species on chromium alloys. For the
purpose of this discussion, we will focus on pitting on the internal surface of the pipe. We will also
further refine it to include pitting to the extent that the joint was rejected by API standards (12.5% wall
loss from API minimum body wall). Table 1 outlines the most important results of this compiled data
for carbon steel tubing, 22% chrome tubing, and 13% chrome tubing. What is evident from the data is
that both 13% and 22% chrome alloys are subject to corrosion under certain environmental conditions.
Even though all three types have relatively similar ID pitting reject ratios, one must remember that, for
the most part, each of these materials is used in progressively more severe environments.
Internal plastic coatings have been used for nearly 60 years for corrosion protection of carbon steel.
For the past eight years attention has been given to a secondary benefit of internal plastic coatings,
namely the improvement of hydraulic efficiency through carbon steel as well as chromium alloy
tubing. Table 2 outlines the comparison between the reject rates (i.e. corrosion protection) between
bare and coated chrome alloy tubulars. What becomes apparent from this data is that chromium alloy
joints that were originally coated for hydraulic improvement received a secondary benefit from the
coating, namely corrosion protection. The data confirms that there is a definite asset maximization
benefit realized by the use of internal plastic coatings on chromium-based alloys.
3. HYDRAULIC EFFICIENCY
Internal plastic coatings have long been known to have positive impact on the hydraulic efficiency of
most flowing systems. 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 The reduction in friction is due to the reduced surface roughness inherent
to most internal plastic coatings.
Table 3 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 at a nominal 55 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. The use of finer grits may produce a
smoother surface but may also not meet the API requirement of total removal of the mill scale. It
should also be factored in that the corrosivity of the bare 13Cr system often leads to a rougher surface
once in service.
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 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 25%. 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 on
software analysis and laboratory testing alone.
Case History #1
A Gulf of Mexico well was re-completed to achieve higher gas rates and minimize erosion of the steel
tubing. The operator decided to increase the tubing size from 2 7/8” to 4” 13% chrome tubing in an
effort to accomplish the desired goals. Gas production was measured at 23 mmscf/d before replacing
the 2 7/8” tubing. A Perform model had predicted a rate of approximately 46 mmscf/d with an FTP of
2250 psia would be the optimal rate achievable with bare 13% chrome tubing. In May of 1997, after
installing the 4” tubing internally coated with a modified phenolic, the well started producing 50
mmscf/d. The 8 percent increase in production is attributed to the reduced friction loss due to
internally coating the tubing.
Case History #2
A major offshore operator in the Gulf of Mexico was researching alternatives to enhance the
production of a future subsea completion. The tubing used was 5 ½” 23#, 13% chrome, which when
blasted to API specification, had a surface roughness of approximately 50 microns (1.97 x 10-3 in.).
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 improve the
production of this well was to use internal plastic coating to minimize the frictional effects at the
surface of the pipe. Making sure first that the coating would survive the well environment, it was
decided to use a novolac powder coating due to its low surface roughness. The surface roughness of
this particular coating is approximately 2 microns (7.86 x 10-5 in.). A computer hydraulic simulation
was performed 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, the use of bare chrome would allow
approximately 110 mmscf/day of gas to be produced. The use of internal plastic coating would allow
approximately 145 mmscf/day of gas to be produced, a 24% increase in production.
The well was completed with the coated 5 ½” 13% chrome tubing and brought on production. After
the well cleaned up, the well was producing higher than expected gas rates. At last contact, the
engineers felt that they were going to “open it up”, and begin producing approximately 180 mmscf/day
of gas. Fear of potential erosion of vital downhole equipment has prevented this type of increase, and
to date, the maximum comfortable rate has been 147 mmscf/d. Using the original 35 mmscf/day
increase in flow along with a conservative $4/mscf gas rate, the coated tubing was 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.
4. FLOW ASSURANCE
Flow assurance has become a very important topic as the cost to develop, produce and transport
product has become more expensive. As companies have drilled into remote locations where fixing a
plugging problem is difficult and uneconomical, ensuring that a system is designed to mitigate the
potential for organic and inorganic deposits is imperative. Currently, the most problematic deposits are
composed of asphaltene, paraffin, scale and hydrates. Given the unique way in which hydrates form
and plug a system, the use of internal plastic coating have little to no deposition mitigation effect. For
asphaltene, paraffin and scale deposition, internal plastic coating works in slightly different ways. For
years, it was thought that the reason internal plastic coatings have positive effects on the mitigation of
deposits was due to having a smooth surface. Laboratory analysis and field applications have indicated
that this is not always the case.
Asphaltene Deposition
The mitigation of asphaltene deposits has proven to be very difficult. An asphaltene molecule is
stabilized in solution by a resin system. Destabilization of that resin system causes the precipitation
and eventual coagulation and deposition of the asphaltene. An asphaltene deposit cannot be thermally
solublized and due to the complexity of the asphaltene/resin make-up, chemical dispersion is difficult.
What has been learned through laboratory and field applications is that with asphaltene deposition, a
smooth surface is not the most important factor in keeping the deposit from forming and adhering.
Given that asphaltene molecules are very polar in nature, having an internal tubing surface that is
chemically inert and void of major, polar binding sites is very important in deposition mitigation.
Adjusting of the surface chemistry with the use of internal plastic coating, could allow asphaltene
molecules, even if removed from their resin system, to pass through the system without accumulating
and depositing on the pipe surface. Positive field applications have further reinforced the laboratory
testing on the effects of internal plastic coating on the deposition of asphaltenes.
Case History #3
During well design and determination of the bubble point of the reservoir fluids, it was determined that
this Gulf of Mexico well would operate in a 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 main form of protection while using
the internal plastic coating as secondary. When the well was brought on production, the asphaltene
inhibitor injection point was plugged with completion fluid and could not be used, leaving internal
plastic coating as the only mode of protection. After 18 months, the reservoir was depleted, and the
tubing pulled. Mitigation of the asphaltenes by the internal plastic coating appeared to be very
effective due to the fact that there were no visible signs of deposition on the coated surfaces and the
fact that the asphaltene inhibitor was not utilized due to plugging of the injection system.
Paraffin Deposition
The use of internal plastic coatings for paraffin mitigation has yielded success due mainly to the
reduced surface roughness (lack of an area conducive to mechanical binding) possessed by coatings.
Many entities have tried to prove the benefit of internal plastic coating in the mitigation of paraffin
deposition by taking an all or none approach. What the oil and gas industry has realized is that
typically there is no 100% effective tool that works in 100% of the situations 100% of the time. Even
though there are field experiences that have shown how internal plastic coatings have completely
stopped the deposition of paraffin, there are also those that show that the use of internal plastic
coatings have extended the time between invasive treatments or reduced the amount of chemical
inhibition required to treat. Care must also be take in choosing the type of chemistry that makes up the
given coating or liner as some systems will have a porous top layer which will allow paraffin to set up
an anchor point for additional paraffin to stick to itself forming a larger deposit. 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 experienced difficulties due to the deposition of
paraffin. 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.
In addition to this direct economic benefit, the operator also received a volumetric flow increase due to
the reduced surface roughness of the internal plastic coating. Prior to coating the tubing for this well,
the system produced on average 2.38 mmscf/day. After the coating was introduced into the system,
the flow of gas increased 14.4% to 2.72 mmscf/day. At a conservative rate of $2/mscf, the increased
production from the use on internal plastic coating improved the operator’s annual revenues by
approximately $250,000 per year. This economic benefit allowed the operator to pay for the
application of the internal plastic coating in less than 25 days.
Scale Deposition
Scale is an inorganic deposit that begins to precipitate as the concentration of the inorganic species
increase over their solubility point. Scale deposition is primarily mechanical in nature, looking for a
rough surface to adhere to. Internal plastic coatings offer a surface roughness much less than that of
carbon steel and chromium alloys. As with other deposit treatments, coating success 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 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) that the pipe requires
special treatment prior to further handling.
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. 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.
5. CONCLUSIONS
The use of chromium alloy tubulars to mitigate corrosion has become the treatment choice in oil and
gas production wells. What needs to be remembered is that chromium alloy tubulars work very well in
the mitigation of CO 2 corrosion, but are susceptible to other types of corrosion. A compilation of
inspection results of used bare and coated chromium alloy tubulars has shown that, just as in the past
with carbon steel tubulars, internal plastic coating will protect chromium based corrosion resistant
alloys from the corrosive species that they are susceptible to.
Internal plastic coatings have also proven through actual field histories that under proper system
constraints, reducing surface roughness will cause an increase in hydraulic efficiency. That increase in
hydraulic efficiency can manifest itself as either an overall increase in volumes produced, injected or
transported, or in the ability to reduce the diameter size of the pipe in question.
Along with the corrosion and hydraulic benefits of internal plastic coatings on chromium alloys, flow
assurance has become an exciting benefit. Altering the surface characteristics has already been proven
to be effective in reducing surface friction, and now allows for the mitigation of the deposition of
organic and inorganic deposits. The result of a surface with minimal residual chemistry and a smooth
finish leaves no chemical or mechanical binding sites. The reduction or alleviation of these binding
sites can either greatly reduce or completely stop the threat of deposition type plugging.
Chromium alloy tubulars are an asset to their given system. There is a proven economic advantage in
being able to protect those assets from corrosion and deposition. There is also definite economic
advantage in using the chromium alloy tubing to protect against the corrosive species that it was
designed for, and still maximize the flow characteristics of a system. Internal plastic coatings allow for
asset maximization as well as system optimization.
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 Plastic-coated 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).
Table 1 - Inspection Results Database
Tubing Type
Carbon Steel
22% Chrome
13% Chrome
Total Joints
Inspected
18,393
4324
54,477
Number of Joints
Rejected for ID Pitting
2057
616
7253
Reject Rate
11.2%
14.3%
13.3%
Table 2 - Coated (IPC) vs. Bare Inspection Results
Tubing Type
22% Chrome (Bare)
22% Chrome (IPC)
13% Chrome (Bare)
13% Chrome (IPC)
Total Joints
Inspected
3,792
532
44,105
10,372
Number of Joints
Rejected for ID Pitting
616
0
7150
103
Reject Rate
16.2%
0.0%
16.2%
1.0%
Table 3 - Relative Surface Roughness Values
Average Measured
Surface Roughness
in microns
(nominal values)
Hazen-Williams
Coefficient
Tube-Kote® Coated
Pipe
2 – 10
(4)
150
Bare Carbon Steel
Pipe
30 – 40
(35)
100
Bare 13% Cr
Pipe
50 – 60
(55)
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)
1.97 x 10-3 to
2.36 x 10-3
(2.16 x 10-3)
Figure 1- Pitted Chrome Tubing