SPE SPE-162182
Advancements in the Abrasion Resistance of Internal Plastic Coatings
Robert S. Lauer, NOV Tuboscope
Copyright 2012, Society of Petroleum Engineers
This paper was prepared for presentation at the Abu Dhabi International Petroleum Exhibition & Conference held in Abu Dhabi, UAE, 11–14 November 2012.
This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been
reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its
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reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright.
Abstract
For more than 60 years, internal plastic coatings have been used for corrosion protection on tubing,
casing, line pipe and drill pipe. One of the historic concerns with the use of internal plastic coating is
the threat of mechanical damage and subsequent corrosion cell generation. Through the earlier years of
usage of internal plastic coatings, applicators relied solely on enhanced surface preparation and adhesion
to ensure minimal exposure of the steel substrate if damage were to occur. Even with this minimization,
the potential for corrosion was still a concern for some. Due to this, a focus on developing internal
coatings that offered higher degrees of abrasion resistance was initiated. At this time, several materials
have been developed that offer abrasion resistances up to twenty times greater than what had previously
been seen. These abrasion resistant materials allow internal coatings to be used in applications that were
previously filled with alloys and GRE liners. These applications include: production/injection wells that
rely on frequent mechanical intervention, rod pumping wells, completion string systems and
environments containing high amounts of entrained solids. This paper outlines the development of these
products including the different chemistries used and their abrasion resistance, impact, laboratory
evaluation of their abrasion resistance and initial case histories of applications where internal coatings
have historically been excluded.
Introduction
Internal coating suppliers and applicators recommend that well interventions like wireline and coiled tubing to be
performed at slow, controlled speeds to minimize their abrasive forces. While this has been successful when properly
implemented, the threat of damage was still a cause for concern when using internally coated tubing. In the development of
abrasion resistant internal plastic coatings, one must first identify what types of abrasion mechanisms are to take place.
There are three main types of abrasion that occurs at the internally coated tubular surface: wireline abrasion, flowing
solids abrasion, and large body abrasion such as with coiled tubing and rod pumping applications. Interaction between a
wireline and a coated surface tends to manifest itself in a cutting action. Film penetration can be quick leading to the steel
substrate being exposed. Exposing the steel to the well environment could lead to corrosion, but it has long been understood
that this minimal area of exposed steel would not lead to accelerated corrosion, because the surface area ratio of the anode to
cathode were very small.1 Even though the corrosion rate would effectively be reduced in this area, the fear of a corrosion
breach was still prevalent.
A second type of abrasion is from the erosive effects from flowing solids interaction with the pipe wall. Solids
contained in process flow will incorporate impact as well as general abrasive forces requiring the coating material to possess
both general abrasion resistance as well as a natural resiliency to mitigate any small scale chipping due to solid particle
impact. Outside of general abrasion resistance, the internal coatings can possess a surface finish much smoother than that of
either carbon steel or of 13% chrome. This lower surface roughness will reduce the turbulence at the surface, therefore,
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reducing small particle interaction and impact.
A third type of abrasion is large body abrasion due wear associated with coiled tubing during well intervention or
from sucker rods in a rod or beam pumping production application. The abrasive force from this interaction tends to be
spread over a much larger area and therefore the rate of penetration tends to be much slower than wireline abrasion. The
detrimental effects of this type of abrasion can further be accelerated, specifically in sucker rod pumping wells, because in
conjunction with the direct wear abrasion from the constant cycling of the rods up and down the well, there will also be
impact on the coated surface from what is called “rod slap”. “Rod slap” is the impact of the rod against the pipe wall that is
caused from either deviations in the well cause the rods to buckle, or from resistance in the pump area causing rod bucking
and therefore impact. A coating material used in this application will provide a higher level of success if it possesses both
abrasion resistance as well as impact resistance.
Measurement of Abrasion Resistance
There are several laboratory tests that are used to determine the abrasion resistance of polymeric coating systems.
While these methods tend to be very beneficial in the comparison of abrasion resistance qualities of different materials, they
tend not to correlate directly to abrasion occurring in service. Several proprietary test apparatus have been developed to try
and simulate wireline, coiled tubing, and sucker rod interaction on coating systems, but these tests tend to have very poor
reproducibility making their predictive ability somewhat suspect. For the purpose of this paper, we will focus on accepted
standard industry tests that are reproducible and allow comparison between different coating systems as well as field results.
One such test is ASTM D 4060 “Standard Test Method for Abrasion Resistance of Organic Coatings by Taber
Abaser”. In this testing protocol, a flat coated panel of known weight is rotated under CS-17 abrasive wheels, with a 1
kilogram load for between 5000 to 10,000 cycles. The coated panel is then re-weighed to determine how many grams of
coated material were abraded away every 1000 cycles. While this provides a comparable value, the fact that different coating
materials have different densities, erroneous comparisons can be made. A second allowable recording method is to measure
the thickness of coating material that is lost for every 1000 cycles, measured in mils (thousandths of an inch) or microns.
This method provides for a comparison of different coating materials and their abrasion resistance.
To provide a better understanding of how this test relates to real a world application, let’s reference SPE 77687
“Case History: Internally Coated Completion Workstring Successes”.2 In this paper, a comparison was made between two
different coating materials, an epoxy-phenolic coating that had been used in drilling and completion operations for more than
45 years and a modified epoxy-phenolic coating. The modified epoxy phenolic actually contains the same resin system as the
epoxy phenolic coating it is being compared too, but alternatively, it contains a different inorganic filler package to enhance
the abrasion resistance.
To summarize, during this completion work, there were a total of 17 frac pack completions in which frac fluid was
pumped through the internally coated pipe at velocities approaching 56 ft/sec. The modified epoxy-phenolic coating was
involved in but the first three of the completions, but was entered into the string with pipe containing the epoxy-phenolic
coating that was evaluated and considered to be still in good condition. During the 17 completions, there was more than
2,000,000 pounds of frac fluid (viscous fluid containing either sand or manufactured solids) pumped and over 136,000 ft of
wireline run through this string. As can be seen in Figure 1, the original epoxy-phenolic coating (greenish-brown in color)
was abraded down to bare metal in a high erosion zone. The modified epoxy-phenolic coating (blue-green in color) lost
approximately 12% of its total film thickness in the same area. These field results indicated that what were being reported as
positive results with the Tabor Abraser testing yielded positive results regarding the materials ability to reduce the affect of
abrasion in the field.
ASTM D 968 (Abrasion Resistance of Organic Coatings by Falling Abrasive) has also been utilized to quantify the
abrasion resistance of various oilfield coatings. In this test, silicon carbide is used to test the erosion/small body impact
resistance of the coating system. The abrasive is allowed to free fall onto the coated surface of a metal coupon which has
been secured at a 45° angle. The test looks for how many liters of abrasive it will require to completely penetrate the coating
surface and expose the steel substrate. Results are reported is liters of abrasive per mil of coating required.
Finally, while not a direct analysis of abrasion, it is important to understand the flexibility and impact resistance of
the material in an effort to determine how it will handle large body impact in the presence of abrasion (such as in rod
pumping applications). There are industry tests that look at direct impact, but they tend to focus on more pin point type
impact versus large body impact. When considering the impact related to rod pumping applications, these tests do not
generate relevant results. Instead, looking at the flexibility of the coating has shown to be a better indicator of performance in
these applications.
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As you compare these test results for different coating systems, it can be determined which will have the greatest
level of success in the various types of abrasive environments. Table 2 breaks down the parameters for each of these systems
including the applications in which they are historically used. Table 3 outlines and compares these results for historically
popular internal coating systems versus the recently developed materials that have been designed for greater abrasion
resistance.
Field Performance
Case History 1
For some time, GRE liners have become more widely used in offshore and onshore injection wells partly due to the
perception of added abrasion resistance over previously used internal coating systems. It has been asserted that these next
generation abrasion resistant coatings would actually provide better resistance to wear, but this was difficult to compare in a
laboratory given the testing utilized to measure the abrasion resistance on GRE liners and internal coatings do not correlate.
To compare the effectiveness of what was becoming more the industry standard of utilizing GRE liner in deepwater injection
wells, an internal modified epoxy phenolic coating was applied to 5 ½” casing to be installed in an injection well application
at the same time an identical casing string with a GRE liner was installed in a sister well. After 9 years of injection, a video
camera was run into each well for a visual analysis of their performance. The video indicated that the coating showed no
evidence of abrasion or impact damage from the numerous wireline runs (approximately 12). The video also indicated that
there were no evidence of corrosion cells at the connection interface of the VAM Top Connection. The video run through the
GRE liner system in the sister well with (similar work performed) indicated damage to the end flanges in the connection area
and “key holing” of the liner itself due to wireline abrasion. “Key holing” is where the wireline physically cut into the liner
leaving a gouge. The video was inconclusive as to whether any of these gouges breached the liner exposing the cement
interface.
Case History 2
For an offshore application in Southeast Asia, an operator would complete their production wells utilizing L-80
carbon steel on the bottom half of the well and 13% chrome on the upper half. The actual bottom hole temperature for these
wells averages 420°F (215.5°C) with a flowing tubing pressure of approximately 2000 psi. The CO 2 concentration ranged
from 18% to 22%. Due to the temperature, there was not sufficient liquid water to cause corrosion in the bottom section of
the well; therefore, bare L-80 carbon steel tubing was utilized. The temperature at the metallurgy transition well depth is
approximately 320°F (160°C). A phenolic novolac coating system was installed into an L-80 carbon steel tubing string to
use in place of the 13% chrome tubing in an effort to cut well costs. Two wells were selected to trial the coated tubing
strings. The wells in this particular field required numerous wireline interventions partly because the reservoir is made up of
multiple zones which would water up if allowed to produce for too long. Through well #1, there were 18 recorded wireline
runs and through well #2, there were 33 wireline runs for a combination of drifting, CBL, perforating, setting plugs, caliper
surveys, and BHP survey. The phenolic novolac coating system withstood the abrasive interaction of the wireline
interventions while still being able to protect the steel substrate from the corrosive environments.
Case History 3
Rod pumping or beam pumping wells offer a unique challenge to providing adequate corrosion protection
due to the dynamics of the system. The abrasive wear coupled with the impact that can take place from the interaction of the
sucker rods and the pipe internal surface can make many standard corrosion treatment methods ineffective. For an internal
coating to withstand both the abrasive action as well as the possible impacts, it must possess a unique blend of characteristics.
A highly deviated rod pumping well was experiencing premature tubing failures due to excessive rod wear on the
tubing through the deviations. A variety of alternative coating systems (including ceramic filled coatings, nano-coatings,
nylon coating, and penetrants) had been field trialed in this well resulting in a maximum tubing life of less than 6 months.
A modified epoxy coated tubing string was installed in November of 2009 and has been successful in dramatically
extending the life of the tubing string without the use of rod guides. To date, this coating has lasted 22 months and continues
to protect the tubular assets, reduce workover costs and allow continuous production of the well. During this time period, the
rod string has been pulled approximately 10 times to replace sections of the rod string experiencing issues with corrosion and
wear and the downhole pump was pulled twice due to wear for replacement.
Conclusion
Historically, internal tubular coatings have been considered to be susceptible to mechanical damage that could
expose the steel substrate to the corrosive nature of the production or injection fluids. Advancements have been made in both
filler materials as well as resin chemistries that have shown in laboratory tests and field trials to increase the abrasion
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resistance of these coating systems by as much as fifty times. These abrasion resistant systems have proven themselves to
perform well when subjected to mechanical intervention such as wireline and coiled tubing, to abrasive solids flow such as
fracing or the production of sand, and to abrasive wear in conjunction with impact forces typically seen in rod pumping
applications. These new coating systems can reduce well construction costs, when compared to exotic alloys, as well as
reduce production/injection downtime.
References
1.
2.
Byars, Harry G. “Positive Effect of Anode-to-Cathode Ratio in Damaged Coated Tubing” TPC Publication 5, 1999.
Pourciau, Robert D. “Case History: Internally Coated Completion Workstring Successes”, SPE 77687, SPE Annual
Technical Conference, 2002.
Tables
Coating
Taber Abraser
mg/1000 cycles
Taber Abraser mils/1000
cycles
Epoxy Phenolic
67
0.6
9
0.18
Modified Epoxy-Phenolic
TABLE 1: Source Company Generated Taber Abraser Values for Coatings Tested in SPE 77687
TABLE 2: Coating System Parameters
TABLE 3: Laboratory Results for Coating Mechanical Properties
SPE SPE-162182
Figures
FIGURE 1: Sections of Pipe Utilized in SPE 77687 Comparing Abrasion Resistance in the Same Completion Environment
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