New Advancements in the Abrasion Resistance of Internal Plastic Coatings

Transcription

1 1 New Advancements in the Abrasion Resistance of Internal Plastic Coatings Robert S. Lauer NOV Tuboscope 2835 Holmes Road Houston, Texas, USA 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. Keywords: corrosion, coating, abrasion resistant, tubular, internal 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

2 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, 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 2

3 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 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 epoxyphenolic 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. 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 3

4 4 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. Case History 1 FIELD PERFORMANCE 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.

5 5 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 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. Byars, Harry G. Positive Effect of Anode-to-Cathode Ratio in Damaged Coated Tubing TPC Publication 5, Pourciau, Robert D. Case History: Internally Coated Completion Workstring Successes, SPE 77687, SPE Annual Technical Conference, 2002.

6 6 TABLES Coating Taber Abraser mg/1000 cycles Taber Abraser mils/1000 cycles Epoxy Phenolic Modified Epoxy-Phenolic TABLE 1: Taber Abraser Values for Coatings Tested in SPE TABLE 2: Coating System Parameters TABLE 3: Laboratory Results for Coating Mechanical Properties

7 7 FIGURES FIGURE 1: SPE Coating Comparison