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. This paper was selected for presentation by an OTC Program Committee following review of information contained in an abstract submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the Offshore Technology Conference and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the Offshore Technology Conference or its officers. Electronic reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the Offshore Technology Conference is prohibited. Permission to 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 where and by whom the paper was presented. 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