The Use of Internal Plastic Coatings to Maximize Sub-Sea System Operations

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1 The Use of Internal Plastic Coatings to Maximize Sub-Sea System Operations Robert S. Lauer 2835 Holmes Road Houston, Texas United States of America Abstract For more than 60 years, internal plastic coatings have been used for corrosion protection, hydraulic improvement, and deposition mitigation in tubular goods and drill pipe. More corrosion resistant alloys are being used to mitigate the threat of corrosion in high profile, expensive subsea completions and pipeline applications. As this practice matures, information has slowly been uncovered that has shown several shortcomings with respect to the corrosion resistance of chrome alloy tubulars in oilfield production environments. These shortcomings have lead to a high level of losses of these assets, during service life, the reclamation process or during storage. The shift now is to search for effective ways to economically protect these corrosion resistance alloys without having to change to higher a level CRA s. A practice that is gaining momentum is the use of internal plastic coatings to protect the lower chromium concentration CRA s from the corrosive species that aid in the formation of wormhole pitting on the I.D. surface. Ancillary benefits of using internal plastic coatings on chromium alloys have also been uncovered. By reducing the effective surface roughness of the pipe, improved hydraulic efficiency can be achieved. This benefit can take the form of increased overall flow, reduced pressure losses, or the ability to reduce pipe size and still maintain expected flow. Also minimizing the surface roughness and offering a predominantly 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. Introduction Through the history of the oil and gas industry, corrosion control has taken many different forms. For years, replacement and patching seemed to be the only methods of maintaining the longevity of well and pipeline life. As time went on, chemical inhibition, internal coatings, and polymeric liners were used to mitigate corrosion and extend the overall life of the system. With the cost of completing and working over a normal offshore system steadily increasing, the cost to complete and subsequently workover a subsea well increases exponentially. These costs have led to the acceptable use of more and more expensive alloys for tubular completions in an effort to prevent the threat of working over a well due to a corrosion failure. Now these alloys are being used for corrosion control in subsea pipeline applications. In most areas, CO 2 causes the greatest corrosion concern. CO 2 corrosion can be a major cause of tubular wall loss and

2 system failure, but it is not the only corrosive species that is encountered. Other corrosive species include hydrogen sulfide (H 2 S), bacteria, oxygen, chlorides (salts), and chemicals that are added to the system such as acids and improperly administered inhibition. Martensitic stainless steels, such as basic type chromium alloys, are highly susceptible to pitting attack in oxygenated fluids, especially in the presence of chlorides. 1 In an effort to determine the true concern for pitting in these alloys, an in-depth analysis of used 13% and 22% chrome tubing that was in onshore and offshore applications was performed based on tubular inspection results. Another concern about the use of chromium alloy tubulars in subsea well completions and pipeline applications is their effect on overall system flow. Surface roughness is shown to have an adverse effect on hydraulic efficiency in most flowing systems due to the friction that is created at the surface. Reducing the surface roughness can be used to either increase flow or to reduce the pressure required to flow. This concept has been utilized in the gas and liquid transmission business for years where a thin internal polymer flow coat is applied to reduce friction at the surface therefore minimizing the pressure requirements to transport materials over long distances. 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 Corrosion 2000 paper # Internal Tubular Tube-Kote Coated Pipe Bare Carbon Steel Pipe Bare 13% Cr Pipe Average Measured Surface Roughness in microns (nominal values) 2 10 (4) (35) (45) Hazen- Williams Coefficient Table 1: Surface Roughness Values 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 ) Coatings Used to Maximize Hydraulic Efficiency, reviews how surface roughness is measured and the most appropriate factor and calculation to use for accurate measurements. 3 Altering the surface roughness and surface chemistry has also show positive results in the mitigation of organic and inorganic deposit formation. Problematic deposits can be composed of asphaltene, paraffin, scale, hydrates or combinations thereof. There is currently no sufficient laboratory or field data to indicate the effectiveness of internal plastic coatings on hydrate plugging. 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. Production/Injection Tubular Applications 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.

3 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 utilize these materials have a design life of greater than 10 years. 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 re-installation, problems are being uncovered. Non-destructive inspection of used 13% and 22% chrome tubing has revealed what corrosive effects these species are having on the parent metal. Inspection reports for used carbon steel, 13% chrome and 22% chrome tubing were compiled in a way that allows for sorting based on many reject criteria. An earlier version of this data as well as a more in-depth explanation of the inspection techniques can be found in OTC paper number 16026: The Benefits of Using Internal Plastic Coatings on Chrome Tubulars. 4 Table 2 shows the most updated version of the data. Alloy Number of Joints ID Pitting Reject Rate Carbon Steel 145, % 13% Chrome Total 69, % 13% Chrome Internally Bare 56, % 13% Chrome Internally Coated 13, % 22% Chrome Total % 22% Chrome Internally Bare % 22% Chrome Internally Coated 532 0% Table 2: Used Tubing Inspection Results What is basically being inferred from this data is that in their respective environments, these materials are subject to corrosion and inspection rejection due to the severity of corrosion based on API standards. This data also shows that regardless of the measured surface roughness of the chromium alloy as it comes out of the mill, the surface characteristics can be negatively affected by the environment. The internal coating of these alloys is becoming a more accepted practice because the surface profile can be masked with a smooth internal coating. Below is a table of historical offshore and subsea applications that have benefited from the introduction of internal plastic coatings.

4 Customer Date Coating Internally Bare Pressure /Production Rate Internally Coated Pressure /Production Rate % Improvement A 2003 Modified Epoxy 110 mmscf/d 163 mmscf/d 32% B 2003 Modified a) 5000 bfpd a) 6000 bfpd 16% Phenolic b) 7500 bfpd b) 9000 bfpd 16% C 2001 Modified 27.5 mmscf/d 34 mmscf/d 19.1% Phenolic 688 bopd 850 bopd 19% D 2002 Modified Phenolic 61.9 mmscf/d mmscf/d 13% E 1997 Epoxy Novolac 46 mmscf/d 50 mmscf/d 8% F 1997 Epoxy Novolac 74 mmscf/d 90 mmscf/d 17.6% G 2001 Modified 59 mmscf/d 78 mmscf/d 24.3% Phenolic H 1999 Modified Phenolic 46 mmscf/d 56 mmscf/d 18.6% Table 3: Hydraulic Improvement Case Histories The ability of certain internal plastic coatings to mitigate paraffin and scale deposits has been discussed previously in Paraffin Deposition and Prevention in Oil Wells by R. M. Jorda 5 and in OTC paper number 16026: The Benefits of Using Internal Plastic Coatings on Chrome Tubulars. The prevention of asphaltene precipitation has proven difficult due to wide variations in both the asphaltene molecule and the associated resin that keeps it in solution. Certain types of polymeric coating materials have shown, through laboratory evaluation, to possess the necessary surface characteristics for the mitigation of asphaltene deposition regardless of its precipitation. The application of a polymer based coating system, with a sufficient chemically inert surface, has also shown the ability to prevent the tenacious adherence of asphaltene deposits in field applications. Trying to put laboratory data behind the field success has led to the following.

5 Surface Energy (mn/m) Gold Ag Cu Fe Pure PR Asphaltene-pure PEEK Asph rich HDPE PVC LDPE TK-236 Polyamide 12 TK-70 TK-2 PS TK-99 PR Asph poor Figure 1: Surface energy and Hamaker constant for polymers and metals at 20C 6 Kynar Teflon A negative Hamaker value (A SLR ) occurs when dielectric properties of the medium (asphaltene lean phase) have a value intermediate between the dielectric properties of the substrate and the precipitated asphaltene rich phase. In this case, Hamaker constant will represent a sticking probability of asphaltene aggregates on the substrate. Figure 1 shows zero tendency asphaltene to stick on PTFE (Teflon) and PVDF and a positive tendency for the rest of materials proportional to their surface energy level A11 x J Metals 3.0 ASLR x J Polymers 0.5 Tuboscope LDPE HDPE PEEK Teflon: PTFE PVC PP PS Polyamide 12 Pure PR Kynar: PVDF PR TK-2 TK-70 TK-99 TK-236 Gold Cu Fe Ag Figure 2: Sticking tendency of asphaltene on different materials 6

6 While more than 20 years of history has proven the effectiveness of certain coating systems in the prevention of paraffin and scale deposition, success in asphaltene mitigation has been relatively recent. The above data is the beginning of a basic understanding of why certain materials indicate effectiveness. The lower or more negative the Hamaker value (surface energy) in conjunction with a lower or more negative sticking tendency, the more effective the system will be in mitigating asphaltene deposition. Flowline/Pipeline Applications Internal corrosion issues in pipelines are now becoming a recognized problem. Market analysis of pipeline failures reported between 1990 and 2005 performed by the Alberta Energy and Utilities Board indicated 12,191 operating pipeline failures. Of these, 7,035 (57.7%) was due to internal corrosion while only 1463 were due to external corrosion. 7 Even with statistics such as these, more engineering and planning time is used to implement external corrosion control versus internal corrosion control. After the fact control methods such as chemical inhibition and frequent pigging can prove ineffective over the life expectancy of the line. These now recognized issues are leading to the use of clad as well as alloy line pipe. While these can prove effective in the right environment, their expense can make some projects marginal. A more cost effective and proven method to control corrosion in these environments is the use of internal plastic coatings. The use of internal plastic coatings to control corrosion, improve hydraulics and mitigate deposit formation in flowlines and pipelines has been practiced for more that 35 years. What made this possible was the development of the Thru-Kote system. The Thru-Kote system isolates the area of coating at the end of the line pipe, which will be burned back due to the welding process, from the environment. The sleeve itself is also internally coated minimizing corrosion related issues. The total package will provide 360 coverage down the entire length of the line. A Gulf of Mexico operator was looking at either chemical inhibition or internal plastic coatings to provide corrosion control and deposit control for a subsea pipeline. Corrosion modeling indicated that they would not be able to meet the minimum design life of ten years without some level of corrosion protection. In addition to corrosion control, the application of the internal plastic coating would also provide an additional benefit; it would allow the operator to use 6 line pipe rater than the planned 8 pipeline that they would have to use if they chose only chemical inhibition. Still a third benefit from running the internal plastic coating was the minimization of pig runs due to the organic and inorganic deposit mitigating benefit of the coating. If you looked at the cost for the actual materials: the line pipe itself, the cost for the external coating, the cost for the internal coating/chemical inhibition (1 st year of operation) the overall price differential was negligible. When you factored in the additional chemical inhibition for the remainder of the design life of the line, the savings from going with the internally coated system increased to over $325,000 US. When you also add in the savings from minimizing pig runs and construction and material cost for satellite corrosion inhibitor platforms, the differential climbs into the millions. Conclusions What separates subsea applications from everything else in the industry is the enormous cost to construct, complete and repair. Most operators are willing to spend additional capitol on the front end of a project to mitigate costly repairs in the future. Even though popular in these

7 applications, analysis has shown that alloy tubulars can succumb to certain environmental species. Internal plastic coatings have a proven history of protecting tubulars from the environment and are now becoming more recognized in their ability to maximize flow and mitigate deposit formation. A minimal investment in the use of internal plastic coatings in place of or in conjunction with alloy tubulars can lead to great economic benefit. 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 J. Nelson, R. Davis, Internal Tubular Coatings Used to Maximize Hydraulic Efficiency, CORROSION/2000, paper no , (Houston, TX: NACE, 2000). 4. R. Lauer, The Benefits of Using Internal Plastic Coatings on Chrome Tubulars, OTC, paper no , (Houston, TX:OTC, 2004) 5. R. M. Jorda, Paraffin Deposition and Prevention in Oil Wells, Journal of Petroleum Technology, December G. Hirasaki, W. Chapman, J. Buckley, J. Wang, D. Gonzalez, Asphaltene Deposition Model Evaluation of Coating Materials from Tuboscope, Rice University, ALBERTA ENERGY AND UTILITIES BOARD, Report 2007-A: Pipeline Performance in Alberta, April 2007, Published by Alberta Energy and Utilities Board