Many pipeline integrity issues are the result of external corrosion or stress corrosion cracking. Each of these failure modes relies on the interaction of exposed steel with a corrosive environment. Modern coating systems have been developed that reduce the potential for such failures. This paper will review coating selection and developments for pipeline protection. Recent failures of high integrity coatings will be discussed in terms of the risk to pipeline integrity.
Introduction
Pipeline integrity starts with an effective pipeline coating that is then augmented by cathodic protection. The first line of defense is the coating and if this is not applied correctly or the wrong coating is selected for the required service then issues related to cathodic protection design and potential for future integrity issues can be expected. As long as the coating remains bonded to the steel and isolates the environment from the metal then the risk of corrosion related failures is eliminated. If the coating is damaged or becomes disbonded then the nature of the damage and the properties of the disbonded coating are important aspects that determine whether corrosion or cracking incidents are likely to occur.
Many pipeline leaks and ruptures have been encountered on pipelines built in the 1960's through to the 1980's where coating methodologies employed over the ditch application of materials such as asphalt enamel or polyethylene tapes. As a result of such failures modern coatings should rightly be scrutinized in an attempt to understand possible failure modes and to establish probabilities that coating failure will lead to pipeline leak or in the worst case pipeline rupture. Recent reports of "failures" with high integrity coatings such as fusion bonded epoxy and 3 layer polyolefin coatings have started to appear in the literature (1-3). However it is important to understand whether such coating failure will lead to a condition where the pipeline itself is likely to fail. To date there are no reported pipeline ruptures reported on high integrity coating systems.
Managing Risk
Managing risk with respect to pipeline integrity starts during the design phase of a pipeline project. Selection of the correct pipeline materials, system design, coating selection and cathodic protection design are just a few of the issues that should be addressed. A clear project specification should be written to address the requirements of the pipe coating from application through to pipeline installation and operation. Many of the risk based methodologies for managing pipeline integrity once a pipeline is operational rely on historical data to predict future performance. This approach has been shown to be suitable where numerous failures have occurred with such coatings as asphalt enamel and polyethylene tapes. With such coatings predictive soils models have been a useful method to help prioritize high risk locations for future excavation (4). Fault tree analysis has also proven a successful approach to managing pipeline integrity (5). However to use such methods relies on a good understanding of the failure modes of a coating system and how the failed coating interacts with the corrosive environment. Using models developed with enamel and tape coatings may not be appropriate for use with modern high integrity coatings.
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Coating Selection
The vast majority of pipelines constructed today rely on fusion bonded epoxy as the primary corrosion barrier either as a standalone coating or as a component in a three layer polyolefin system. The choice of coating should be based on installation and operational requirements that can be expected for the pipeline. However, a study performed by the office of pipeline safety in the USA indicates that the primary factor used in selecting a pipeline coating is past experience with use of that coating. Whilst methods such as limit state design, use of materials situation dependent strength and fitness for purpose are being used for the design of the steel component of the pipeline, such methods have yet to be consistently used for coating design and selection.
The primary role of a pipe coating is to isolate the environment from the pipeline steel substrate. It should therefore be an effective moisture barrier, a good electrical insulator and have excellent adhesion to the pipe surface. Adhesion starts with pipe surface preparation whereby the steel should be cleaned to minimum requirements using abrasive blasting and if necessary chemical pretreatment. Important parameters in surface preparation include surface profile, peak density, residual dust levels and other forms of contamination such as oils, greases or salts. It should be remembered that just because a surface looks clean this doesn't mean that it is clean. Mono-layers of contaminants that are not visible can detrimentally impact coating adhesion.
The applied coating should resist damage associated with normal handling, storage and installation. The modes of damage that are most likely to occur are the result of forces associated with impact, abrasion or bending. If a pipe is to be stored outside for long periods then the ability of the coating to withstand UV degradation is important.
During operation it is imperative that the correct materials have been selected to meet the operating temperature requirements of the pipeline. Conventional three layer polyethylene coated pipelines can be used at temperatures up to 80 to 85°C but if higher temperatures are expected then three layer polypropylene systems would be more appropriate. Additionally the selection of the correct fusion bonded epoxy primer layer is also important. A critical parameter in the selection of an appropriate FBE for a given operating temperature is the glass transition temperature or Tg. Conventional FBE products have a Tg of around 95 to 105°C. Above the glass transition temperature of the FBE the material shows a marked reduction in mechanical properties. Therefore, if the operating temperature of the line is expected to be above 105°C to 110°C then a FBE powder specifically chosen with a high glass transition temperature should be used.
Coating Developments
A number of developments have taken place in the last few years aimed at improving the performance of high integrity coatings. FBE systems have been developed to address a number of specific pipeline issues related to mechanical damage, UV resistance, high operating temperatures and low application temperatures.
One of the weaknesses of fusion bonded epoxy has been the ability to withstand mechanical damage during handling and construction. To overcome this problem hard outer layers that are applied over conventional FBE corrosion resistant base coatings have been developed. Such dual layer systems have exhibited performance
that exceeds that of conventional FBE and in some cases can actually match that of 3 layer polyethylene (6, 7).
More recently at least one FBE supplier has developed a three layer powder FBE system that consists of an outer tough layer to resist penetration, a softer middle layer designed for shock absorption and gouge resistance, and an inner FBE layer designed specifically to enhance adhesion and corrosion protection properties (8). Such a system should provide superior performance with respect to impact damage for example in situations during backfill of the pipe or in other cases such as impinging concrete weight coatings onto the pipe.
This multi layer approach to building up FBE coating systems also allows the use of UV resilient top coats to protect the FBE in situations where prolonged storage may be required.
The potential use of high strength steels for future pipeline developments provides a challenge to the pipe coating applicator. High strength steels are known to be affected by the application temperatures of conventional FBE powders. Changes to the ultimate tensile strength and yield to tensile ratios have been reported (9) during induction heating of high strength steels at 230 to 240°C. This has resulted in certain pipeline operators setting an upper limit of 200°C for application of the corrosion protection coating system to high strength steel pipelines. New powders have been developed that can be applied at temperatures as low as 160°C as part of three layer polyethylene systems (10).
The development of 3 layer polyethylene coatings has included the application of some of the ideas highlighted above for the FBE products. In addition a move towards higher density polyethylene with improved impact resistance and towards polyethylene materials with higher environmental stress crack resistance has taken place. A recent study has reported the use of cross linked polyethylene as a thin outer layer that provides improved mechanical and cracking resistance (11).
Coating Failure Modes
The failure mode of a pipeline coating has significant impact on whether corrosion and stress corrosion cracking can develop in the underlying metal.
Early coatings based on asphalt or coal tar were subject to oxidation and a loss of low molecular weight components through water dissolution and biodegradation (12). These effects result in a permeable embrittled coating that often separates from the steel to form a thin gap. Water penetration through these coatings can result in the development of corrosive conditions under the coating and external corrosion, microbial corrosion (MIC) and stress corrosion cracking (SCC) failures have been observed. In continuously wet environments pipelines coated with such materials exhibit a slow increase in cathodic protection current demand with time.
The next generation of coatings included tapes based on polyethylene and polyvinyl chloride. PVC based products require addition of a plasticizer to obtain the physical properties of the coating. Such plasticizers are low molecular weight organic molecules such as dioctyl phthalate that can be lost from the coating through biodegradation, water dissolution and sometimes local crystallization. The loss of plasticizer produces a brittle coating and such coatings have been prone to cracking in service. Increased cathodic protection current demand, shielding of cathodic protection and ultimately localized corrosion have all been observed with PVC based tape coatings.
Polyethylene tapes are well known to fail due to development of shielding coating disbondments. The adhesive tapes used with older versions of such products can degrade through microbial action, but in addition the
adhesive strength of the products is not sufficient to withstand soil stress disbondment. The result is production of long narrow openings in the coating that can shield cathodic protection (17, 18). In addition due to tenting at long seam and spiral welds access of water to the steel pipe surface can occur. The occurrence of localized corrosion as well as SCC and MIC has been frequently observed with such products (12, 13).
Modern coating systems are based on corrosion protection using fusion bonded epoxy, either as a standalone coating or as the primer layer in a three layer coating system. Field observations have encountered defective coatings based on both of the above types of systems. However the occurrence of localized corrosion that can lead to pipeline leak or rupture appears to be very low with such systems (1-3, 14). Surface preparation techniques used in the application of modern pipe coatings rely on abrasive blast cleaning. This imparts residual compressive stress in the outer layer of the pipe steel. This has been shown to be beneficial in prevention of initiation of stress corrosion cracks (19). The application process for 3 layer polyethylene ensures that a continuous sheath of polymer is extruded around the pipe. If the polymer is applied by side extrusion the overlap between each revolution is fused to the next.
For standalone FBE coatings the type of defect that is most often encountered during field evaluations takes the form of a blister in the coating. In continuously wet soil environments water is able to migrate through the coating. Analysis of the pH of water found under FBE coatings in such conditions indicates that the pH is in the region of 10 to 14. This indicates that effective cathodic protection is reaching the steel surface. In this scenario the pH of the trapped electrolyte and the cathodic protection potential of the steel are outside the window where corrosion, MIC or SCC can occur on pipeline steel.
Recent observations have indicated that buried pipe-lines coated with three layer polyethylene systems have exhibited coating disbondment. Pipes coated at the same time but stored or operated above ground have not shown such disbondment (1). The implication here is that the buried environment results in a loss of adhesion with the steel of the FBE layer of the three layer system over time but this is still a topic of active research (14). The type of disbondment observed with factory applied three layer coatings is not the same as that observed with over the ditch applied tape coating. The long narrow shielding disbondments produced as a result of soil stress with tape coatings have not been observed with three layer factory applied coatings. This does not mean that a disbonded three layer coating could not shield cathodic protection, but the implication is that cathodic shielding is only one of the components that contribute to pipeline failure. The discussion below attempts to explain why such disbondment has not resulted in pipeline corrosion scenarios that have resulted in pipeline failure.
Corrosion Mechanisms
The reactions identified below suggest that pipeline corrosion is a multi-faceted process that is very complex. The underlying processes however, rely on the availability of water and oxygen. For aerobic corrosion to occur a readily available supply of oxygen is required. The corrosion rate of pipeline steel in the presence of stagnant water is very low.
Cathodic reactions that take place at a pipeline surface include electrolysis of water, liberation of hydrogen and oxygen reduction.
2H2O ? 2H+ + 2OH-
2H+ + 2e- ? H2
O2 + 2H2O + 4e- ? 4OH-
At the anode the basic reaction occurring is dissolution of iron:
Fe ? Fe2+ + 2e-
Under aerobic or partially aerobic conditions the production of goethite, hematite and magnetite is observed.
Fe2+ 3H2O ? Fe(OH)3 + 3H+ + e-
Fe2+ + 2H2O ? FeOOH + e-+ 3H+
2Fe3+ + 3H2O ? Fe2O3 + 6H+
3Fe + 4H2O ? Fe3O4 +8H+ + 8e-
Under anaerobic corrosion conditions iron carbonate or siderite is often observed:
CO2 + H2O ? HCO3-+ H+ ? CO32-+ 2H+
Fe2+ +CO32- ? FeCO3
In the presence of sulfate reducing bacteria the following reaction occurs resulting in the formation of various iron sulfide materials typically the non stochiometric product mackinawite:
4Fe + SO42- + 8H+ ? "FeS" + 3Fe2+ + 4H2O
Distinctive corrosion products are produced by each of the reactions identified above. These corrosion products can be used to identify the nature of the corrosion mechanism (15) and provide an indication of the level of risk. Soil conditions also give an indication of the probable corrosion process that can take place (16). The absence of significant corrosion under disbonded three layer coatings suggests that diffusion of oxygen and replacement of water is limited. Although microbial corrosion cannot be eliminated as a potential hazard under such disbonded coatings such corrosion mechanisms have yet to be identified.
The type of disbondment observed during field excavations of 3 layer polyethylene coatings does not appear to support high corrosion rates. The nature of the observed corrosion under such coatings is in the form of a thin patina of corrosion product and to date has not resulted in generation of localized pitting or SCC. As such the probability that coating disbondment will lead to a critical corrosion defect appears to remain low. As with many older coating systems the main area of concern for in service pipelines has been corrosion at field joints particularly where heat shrinkable sleeves have been used.
The risk of pipeline failure due to disbondment of modern high integrity coatings appears to be low. However continued efforts to understand the disbondment mechanisms and the consequences of such disbondment are required. The observation that disbondment of coating appears to occur with buried pipelines, but does not occur with pipe stored or operated above ground suggests that the exposure to the soil environment is important. The absorption of water appears to weaken the FBE to steel adhesion during service perhaps by lowering the Tg of the FBE thereby reducing its mechanical strength (14).
Conclusions
The risk of pipeline failure due to disbondment of FBE or 3 layer polyethylene appears to be low.
Developments in pipeline coatings are ongoing.
Whilst field observations of disbonded FBE and 3 layer polyethylene have been made significant corrosion has not been observed under disbonded high integrity coatings.
References
1. K.K. Tandon, G.V. Swamy, G.Saha, "Performance of three layer polyethylene coating on a cross country pipeline - a case study", 14th International Conference on Pipeline Protection, BHR Group, Barcelona, Spain, October 29-31, 2001
2. G. Portesan, J Taves, G. Guidetti, "Cases of massive disbondment with three layer PE pipeline coatings", Cathodic protection and associated coatings, CEFRACOR, EFC Event nr 254, Aix-en-Provence, France, June 6-7, 2002.
3. Marcel Roche, Denis Melot, G. Paugam, "Recent experiences with pipeline coating failures", 16th International Conference on Pipeline Protection, BHR Group, Paphos, Cyprus, Nov 2-4, 2005.
4. B. Delanty, J O'Beirne, Oil and Gas Journal, June 15 (1992) p39.
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8. D Grimshaw, G Twidale, M Wilmott, "Handling performance and the benefits of multiplayer FBE system", 17th International Conference on Pipeline Protection, BHR Group, 17-19 October, 2007.
9. Australian Pipeline Industry Association Private Communication.
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12. T R Jack, M J Wilmott, R L Sutherby R G Worthingham, "External Corrosion of Line Pipe a summary of research activities", Materials Performance Vol 35, No 3, pp 18-24, March 1996, NACE International.
13. 13. T R Jack, G Van Boven, M J Wilmott, and R G Worthingham "Evaluation of coating performance after exposure to biologically active soils." Materials Performance 35(3), 39-45, March 1996, NACE International.
14. D Melot, G Paugam, M Roche, "Disbondments of pipeline coatings and their consequence and corrosion risks", 17th International Conference on Pipeline Protection, BHR Group, 17-19 October, 2007.
15. 15. T R Jack, M J Wilmott, and R L Sutherby "Indicator Minerals formed during the external corrosion of line pipe" Materials Performance 34(11), 19-22, 1995
16. M.J. Wilmott and T.R Jack "Corrosion By Soils" Uhlig Corrosion Handbook 2nd Edition edited by Winston Revie John Wiley and Sons Inc 2000.
17. T.R. Jack, G Van Boven, M. J. Wilmott, R.L. Sutherby and R.G. Worthingham, "Cathodic protection potential penetration under disbonded pipeline Coating" Materials Performance 33(8), 17-21, 1994
18. D.A. Diakow, G.J.Van Boven, and M.J. Wilmott, "Polarization beneath disbonded coatings: a comparison between conventional and pulsed cathodic protection." Corrosion 97, paper 566, New Orleans 1997.
19. R.N. Parkins, "Environment Sensitive Cracking (low pH Stress Corrosion Cracking) of High Pressure Pipelines," Report to the Pipeline Research Committee of the American Gas Association, NG18 Report #191,1989.
This paper was presented by Dr.Martyn Wilmott, Director of Technology, PPSC Industrial Holdings Sdn Bhd at the 3rd Asian Pipeline Conference & Exhibition 2007.
