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Pipeline External Corrosion Protection
CHAPTER 8
Pipeline External Corrosion Protection 8.1
Introduction
Offshore steel pipelines are normally designed for a life ranging from 10 years to 40 years. To enable the pipeline to last for the design life, the pipeline needs to be protected from corrosion both internally and externally. Internal corrosion is related to fluid that is carried by the pipeline, and this topic is not covered here. This chapter describes the method by which the external corrosion of offshore pipelines may be minimized. A strong adhesive external coating over the whole length of the pipeline will tend to prevent corrosion. However, there is always the possibility of coating damage during handling of the coated pipe either during shipping or during installation. Cathodic protection is provided by sacrificial anodes to prevent the damaged areas from corroding.
8.2
External Pipe Coatings
This first external pipe coating layer is used to protect the pipe against corrosion. A singlelayer coating is used when the installed pipeline is always in a static, laterally stable condition lying on soils such as clay or sand. Additional layers of coating are used for additional protection, for weight to help the pipeline remain laterally stable on the seabed, or for providing insulation. A multi-layer coating is generally used in cases where the external environment tends to easily wear out the external coating (e.g., pipeline lying on top of rocky soil, calcareous material, etc.). Insulation is provided to maintain a higher temperature of the flowing internal fluid compared to the ambient. Depending on the external environment and on the location or use of the pipeline, a single-layer coating or a multi-layer coating is required. The properties that are considered desirable for deepwater pipeline coatings are: 9 9 9 9 9
Resistance to seawater absorption Resistance to chemicals in seawater Resistance to cathodic disbondment Adhesion to the pipe surface Flexibility 99
100
Offshore Pipelines
9 Impact and abrasion resistance 9 Resistance to weathering 9 Compatibility with cathodic protection A single-layer coating may not be able to provide all of these properties under all operating conditions of pipeline. In such cases multi-layered coatings are used. As the coating must adhere to steel pipe, the surface finish process of line pipe manufacturing must be carefully examined. This is required because in some instances unacceptable surface finish of the line pipe can lead to loss of adhesion of the coating. The next step is to apply the coating in the coating plant following the manufacturer's recommended method of application.
8.2.1
Single-Layer Coating
The most common choice for single-layer coating for deepwater pipelines is Fusion Bonded Epoxy (FBE). Properties and coating requirements are shown in Table 8.1. For deepwater pipelines where there is no other requirement on the external coating, FBE is most frequently used. Most deepwater oil and gas transmission lines use FBE as they are extremely cost effective. This coating can be used in conjunction with concrete weight coating. The other coatings that can be used with concrete coating are coal tar enamel and coal tar epoxy and they are used with lower product temperatures. Both of these coatings are bituminous coatings reinforced with fiberglass. However, most bituminous coatings are not desirable due to environmental laws and decreasing efficiency (sagging, cracking, permeation, and chemical deterioration). The FBE field joint coating is carried out using the same coating material as millapplied coating. Further advantages include: 9 9 9 9
Easy to repair Easy for coating application High adhesion to steel Good for pipeline operating temperatures In the US and UK, FBE coating is preferred for offshore pipelines.
8.2.2
Multi-Layer Coatings
Table 8.2 lists the most common choices that are available for multi-layer coating for deepwater pipelines.
TABLE8.1 Single-Layer Pipe Coatings Coating Type Fusion Bonded Epoxy
Max. Temperature ( ~ 90
Average Coating Thickness(mils) 14 to 18
Some Manufacturers Dupont, 3M, Lilly, BASE Jotun
Pipeline External Corrosion Protection
101
TABLE 8.2 Multi-Layer Pipe Coatings
Coating Type
Max. Temperature (~
Dual-layer FBE, Duval 3-layer polyethylene (PE) 3-layer polypropylene (PP) Polychloropene
90 110 140 90
Two Main US Coating Applicators for Offshore Pipelines BrederoShaw; Bayou Pipe Coaters BrederoShaw; Bayou Pipe Coaters BrederoShaw; Bayou Pipe Coaters BrederoShaw; Bayou Pipe Coaters
Dual-Layer FBE. Dual-layer FBE coatings are used when additional protection is required for the outer layer such as high temperature, abrasion resistance, etc. For deepwater trunklines the high temperature of the internal fluid dissipates rapidly reaching ambient within a few miles. Therefore, the need for such coatings is limited for SCRs at the touchdown area where abrasion is high and an additional coating with high abrasion resistance is used. The Duval system consists of an FBE base coat (20 mils) bonded to a polypropylene coating (20 mils). The polypropylene layer provides mechanical protection. Three-Layer. Three-layer PP coating consists of an epoxy or FBE, a thermoplastic adhesive coating and a polypropylene top coat. The polyethylene (PE) and polypropylene (PP) coatings are extruded coatings. These coatings are used for additional protection against corrosion and are commonly used for dynamic systems like steel catenary risers and where the temperature of the internal fluid is high. These pipe coatings are frequently used in pipelines that are installed by the reeling method. The field joint coating for the threelayer systems is more difficult to apply and takes a longer time. However, in Europe, PE and PP coatings are preferred because of their high dielectric strength, water tightness, thickness, and very low CP current requirement. Concrete Weight Coating. Concrete weight coating is used when stability of the pipeline on the seabed is an issue. The two common densities of concrete that are used are 140 Ibs/cu. ft and 190 lbs/cu, ft. Higher density is obtained by adding iron ore to the concrete mix. Recently, higher density iron ore has been used to obtain concrete density ranging from 275 to 300 lbs/cu, ft for the Ormen Lange pipeline in the North Sea.
8.2.3
Standards Organizations with Specifications Related to Pipe Coatings
The main organizations in the US are: 9 9 9 9 9
American Society of Testing Methods (ASTM) Steel Structures Painting Council (SSPC) National Association of Corrosion Engineers (NACE) National Bureau of Standards (NBS) International Organization for Standardization (ISO)
In Europe, the more common ones are: 9 9 9 9
Det Norske Veritas (DnV) Deutsches Institut fur Nurmung (DIN) British Standards (BS) International Organization for Standardization (ISO)
102
Offshore Pipelines
8.3
Cathodic Protection
Cathodic protection is a method by which corrosion of the parent metal is prevented. The two main methods of cathodic protection are galvanic anodes and impressed current systems. For offshore pipelines, the galvanic anode system is generally used. Corrosion is an electrochemical reaction that involves the loss of metal. This is due to the fact that the steel pipeline surface consists of randomly distributed cathodic and anodic areas, and seawater is the electrolyte that completes the galvanic cell. This causes electrons to flow from one point to the other, resulting in corrosion. By connecting a metal of higher potential to the steel pipeline, it is possible to create an electrochemical cell in which the metal with lower potential becomes a cathode and is protected. Pipeline coatings are the first barriers of defense against corrosion. However, after coating the pipe the process of transportation and installation of the pipelines results in some damage to the coating. Cathodic protection uses another metal that will lose electrons in preference to steel. The main metals used as sacrificial anodes are alloys of aluminum and zinc. By attaching anodes of these metals to the steel pipeline, the steel area where the coating is damaged is protected from corrosion. Zinc anodes are not normally used in deepwater pipelines because they are less efficient and therefore require a larger mass for protecting the pipeline. However, zinc anodes can be cast onto the pipe joint and therefore no cables need to be used for electrical connection to the steel. Zinc has been used in projects where the pipeline needed to be towed along the seabed and cast-on zinc anodes were less liable to be knocked off in the process of installation. Zinc anodes do not perform well for hot buried pipelines and are subject to intergranular attack at temperatures above 50~ There is also a tendency for zinc anodes to passivate at temperatures above 70~ Aluminum anodes, on the other hand, perform much better. They are better suited for hot buried pipelines. Generally, for deepwater pipelines, aluminum alloy anodes that are attached to the pipeline are bracelet anodes. These anodes are normally attached to the pipe joint at the coating yard for S-lay and J-lay installation methods. Electrical contact to the pipeline is made by thermite welding or brazing the cable from the anode. In the case of installation of pipeline by the reeling method, the anodes are installed on the lay vessel during unreeling and straightening. In this case, bracelet anodes are attached to the pipe by bolting and attaching the cable by thermit/cadweld to the pipeline. The design of cathodic protection systems must consider the potential detrimental effects of the CP system such as hydrogen embrittlement of steel and local stresses that may lead to hydrogen induced stress cracking (HISC).
8.3.1 Cathodic Protection Design In order to conduct a CP design for a deepwater pipeline, the parameters that need to be known are: 9 9 9 9
Service/design life (years) Coating breakdown (%) Current density for protection (mA/sq.m) buried or unburied Seawater resistivity (ohm-cm)
Pipeline External Corrosion Protection 103 9 9 9 9 9 9 9 9
Soil resistivity (ohm-cm) Pipeline protective potential (normally, - 9 0 0 mV w.r.t Ag/AgCI) Anode output (amp-hr/kg) Anode potential (mV w.r.t. Ag/AgC1) Anode utilization factor (%) Seawater temperature Pipeline temperature Depth of pipeline sinkage/burial
The design life of the pipeline is based on whether it is trunkline or an infield line. The life of a trunkline can be as long as 40 years while that of an infield line is normally 20 years. The coating breakdown factor depends on the type of coating. There is very little historical data available on coating breakdown. DnV (RP-F103) and NACE (RP-01-76) have recommended values based on the type of pipeline coating. Three values of coating breakdown are typically given--initial, mean, and final. The current density, resistivity, and temperature depends on the geographical location where the pipeline is located. In deepwater pipelines, the approximate seawater temperature range is from 1.7~ to 7.5~ DnV and NACE give values for current densities and resistivities for offshore geographical locations. For bare steel buried in sediments, a design current density of 0.020A/m 2 is recommended by DnV. The type of anode used determines its electrochemical properties. The Galvalum III | anode, for example, has an anode output of approximately 2250 amp-hr/kg in seawater temperature less than 25~ and its potential is approximately - 1 0 5 0 mV. Manufacturers of anodes provide these properties for design. The anode utilization factor depends on the shape and application of the anode. Bracelet anodes are typically assumed to be 80% utilized at the end of their life, while stand-off anodes are 90% utilized. For pipeline temperatures above 25~ the design current densities increase. For each degree above 25~ the current density is increased by 0.001A/m 2.
8.3.1.1 CP Design Methodology The design methodology summarized here follows that given in DnV RP B401. Designs must satisfy two requirements: 9 The total net anode mass must be sufficient to meet the total current demand over the design life. 9 The final exposed anode surface area must be sufficient to meet current demand at the end of design life (the final exposed anode surface area is calculated from anode initial dimensions, net mass, and the utilization factor). First, one computes the current demand, (It), for initial, mean, and final stages of the design life. The current demand to protect each pipeline is calculated by multiplying the total external area (Ac) with the relevant design current density (i~) and coating breakdown factor (j~): I~ -- i ~ i ~
(8.1)
104
Offshore Pipelines
The current demands for initial polarization, Ici, and for re-polarization at the end of the design life, Icf, are normally to be calculated together with the mean current demand Icm required to maintain cathodic protection throughout the design period. It is not necessary to calculate the current demand required for initial polarization, Ici, because, initially, the pipeline corrosion coatings greatly reduce the current demand and time required for initial polarization. The coating breakdown factors for various coatings, initial, mean, and final, are given in DnVand NACE publications. For example, in the Gulf of Mexico, for FBE coating with a design life of 20 years, the initial, mean, and final coating breakdown factors normally used are 1%, 3%, and 5%, respectively. The total net anode mass Mt required to maintain cathodic protection of a pipeline throughout the design life td (years) is given by: M~ =
8760Icmtd
(8.2)
ufee where
Icm = mean current demand 8e = the electrochemical efficiency (A-h/kg) uf = the anode utilization factor. The required current output (initial/final) and current capacity for a specific number of anodes determines the required anode dimensions and net weight. The following requirements must be met by the cathodic system design: naCa >- 8760Icmtd
na]a (initial~final) >- Ic (initial~final) where na = number of anodes
Ca = anode current capacity (A-h) ira = anode current output (A). The anode current capacity (Ca) is given by: Ca = maSeUf
(8.3)
where, ma is the net mass per anode. The anode current output (Ia) is calculated from Ohm's law:
Ia - - E ~ 1 7 6 Ra where E ~ = design closed circuit potential of the anode E ~ = design protective potential Ra = anode resistance
(8.4)
Pipeline External Corrosion Protection 105 The design protective potential (Ec~ for carbon steel is -0.80 V (rel. Ag/AgC1/ seawater) when in aerated seawater and -0.90 V (rel. Ag/AgCl/seawater) when in anaerobic environments including typical marine sediments. Recommended practice states that the E ~ = - 0 . 8 V should be used for all design calculations because the initial and final design current densities are referred to this protective potential. The closed circuit anode potential (E~ for an M-based anode is taken to be - 1.1 V for the pipeline at ambient temperature and -1.085 V for the pipeline at elevated temperatures. The anode resistance (R~) formula for a bracelet anode is given by:
Ra
-
0.315. p
(8.5)
,/Ze where
Pe -- environmental resistivity Ae -- exposed anode surface area. The required number of anodes, n, can be obtained by: ~a -- ~c~
(8.6)
/aS where,
Icji = total final current demand for the pipeline Iaf = individual anode current output. Some iterations may be required to meet the requirements of both the total net anode mass, Mr, and the total final anode current output (nalaf). Generally, maximum spacing of the anodes recommended is 300 m. However, methods to calculate attenuation of protective potential with distance can be used to determine the mass and spacing of anodes. Attenuation computations are specifically useful for determining anodes for cathodic protection of Steel Catenary Risers (SCR). In SCRs, rather than placing anodes on the suspended dynamic portion, several anodes may be placed on static pipeline sections past the touchdown point. This method is also useful for short (up to 3 miles) bottom-towed pipelines with sleds at each end. Instead of placing discrete bracelet anodes along the pipeline, all total mass of anodes required for the pipeline can be placed on the end sleds. Placing them on the end sleds prevent the accidental impact and loss of bracelet anodes from the pipeline being towed along the seabed. Attenuation calculations show that if current is drained from two points on a pipeline, the change in potential of the pipe may be calculated using the following equations:
E x - EBcosh[(E'a'rRl/kpza)l/2(x-
dp/2)]
(8.7) (8.8)
106
Offshore
Pipelines
ira -- (2EB/R,) [(2rrrRl/kpza)l/2sinh(dp/2(2rrRl/kpza)l/2)] k
.]
(8.9)
where
Ex = change in potential at point x EA = change in potential at drain point r = pipe radius EB = change in potential at the midpoint between the two drain points R1 = linear resistance of the pipeline IA = total current pick up dp -- distance between drain points x = distance from drain point kp = polarization slope Za = actual bare area per linear length of pipeline Additional constraints are: 9 The current, IA, must be equal to the current that can be delivered by the lumped anode array. 9 EA must equal the anode potential less the IR drop, using the anode array resistance. 9 The anode weight must exceed the weight necessary to protect the section of the pipeline for the specified design life. Using the above equations and constraints, a greater spacing of the required mass/array of anodes may be computed.
References Aalund, L. R., "Polypropylene System Scores High as Pipeline Anti-corrosion Coating," Oil & Gas Journal (1992). Alexander, M., "High-Temperature Performance of Three-Layer Epoxy/Polyethylene Coatings," MP (1992). DnV-RP-F103 "Cathodic Protection of Submarine Pipelines by Galvanic Anodes." Gore, C. T. and Mekha, B. B., "Common Sense Requirements for Steel Catenary Risers (SCRs)," OTC Paper 14153 (2OO2). Houghton, C.J., Ashworth, V. "The Performance of Commercially Available Zinc and Aluminum Anodes in Seabed Mud at Elevated Temperatures," Corrosion Conference (1981). Kavanagh, W. K., Harte, G., Farnsworth, K. R., Griffin, E G., Hsu T. M., Jefferies, A., "Matterhorn Steel Catenary Risers: Critical Issues and Lessons Learned for Reel-Layed SCRs to a TLP," OTC Paper 14154 (2002). LaFontaine, J., Smith, D., Deason, G., Adams G., "Bombax Pipeline Project: Anti-Corrosion and Concrete weight Coating of Large Diameter Subsea Pipelines," OTC Paper (2002). NACE RP 0176 "Corrosion Control of Steel Fixed Offshore Structures Associated with Petroleum Production." Smith, S. N. "Analysis of Cathodic Protection on an Underprotected Offshore Pipeline," MP (April 1993). Varughese, K., "Mechanical Properties Critical to Pipeline Project Economics," Oil & Gas Journal (Sept. 9, 1996).
Pipeline External Corrosion Protection 8.1
Introduction
Offshore steel pipelines are normally designed for a life ranging from 10 years to 40 years. To enable the pipeline to last for the design life, the pipeline needs to be protected from corrosion both internally and externally. Internal corrosion is related to fluid that is carried by the pipeline, and this topic is not covered here. This chapter describes the method by which the external corrosion of offshore pipelines may be minimized. A strong adhesive external coating over the whole length of the pipeline will tend to prevent corrosion. However, there is always the possibility of coating damage during handling of the coated pipe either during shipping or during installation. Cathodic protection is provided by sacrificial anodes to prevent the damaged areas from corroding.
8.2
External Pipe Coatings
This first external pipe coating layer is used to protect the pipe against corrosion. A singlelayer coating is used when the installed pipeline is always in a static, laterally stable condition lying on soils such as clay or sand. Additional layers of coating are used for additional protection, for weight to help the pipeline remain laterally stable on the seabed, or for providing insulation. A multi-layer coating is generally used in cases where the external environment tends to easily wear out the external coating (e.g., pipeline lying on top of rocky soil, calcareous material, etc.). Insulation is provided to maintain a higher temperature of the flowing internal fluid compared to the ambient. Depending on the external environment and on the location or use of the pipeline, a single-layer coating or a multi-layer coating is required. The properties that are considered desirable for deepwater pipeline coatings are: 9 9 9 9 9
Resistance to seawater absorption Resistance to chemicals in seawater Resistance to cathodic disbondment Adhesion to the pipe surface Flexibility 99
100
Offshore Pipelines
9 Impact and abrasion resistance 9 Resistance to weathering 9 Compatibility with cathodic protection A single-layer coating may not be able to provide all of these properties under all operating conditions of pipeline. In such cases multi-layered coatings are used. As the coating must adhere to steel pipe, the surface finish process of line pipe manufacturing must be carefully examined. This is required because in some instances unacceptable surface finish of the line pipe can lead to loss of adhesion of the coating. The next step is to apply the coating in the coating plant following the manufacturer's recommended method of application.
8.2.1
Single-Layer Coating
The most common choice for single-layer coating for deepwater pipelines is Fusion Bonded Epoxy (FBE). Properties and coating requirements are shown in Table 8.1. For deepwater pipelines where there is no other requirement on the external coating, FBE is most frequently used. Most deepwater oil and gas transmission lines use FBE as they are extremely cost effective. This coating can be used in conjunction with concrete weight coating. The other coatings that can be used with concrete coating are coal tar enamel and coal tar epoxy and they are used with lower product temperatures. Both of these coatings are bituminous coatings reinforced with fiberglass. However, most bituminous coatings are not desirable due to environmental laws and decreasing efficiency (sagging, cracking, permeation, and chemical deterioration). The FBE field joint coating is carried out using the same coating material as millapplied coating. Further advantages include: 9 9 9 9
Easy to repair Easy for coating application High adhesion to steel Good for pipeline operating temperatures In the US and UK, FBE coating is preferred for offshore pipelines.
8.2.2
Multi-Layer Coatings
Table 8.2 lists the most common choices that are available for multi-layer coating for deepwater pipelines.
TABLE8.1 Single-Layer Pipe Coatings Coating Type Fusion Bonded Epoxy
Max. Temperature ( ~ 90
Average Coating Thickness(mils) 14 to 18
Some Manufacturers Dupont, 3M, Lilly, BASE Jotun
Pipeline External Corrosion Protection
101
TABLE 8.2 Multi-Layer Pipe Coatings
Coating Type
Max. Temperature (~
Dual-layer FBE, Duval 3-layer polyethylene (PE) 3-layer polypropylene (PP) Polychloropene
90 110 140 90
Two Main US Coating Applicators for Offshore Pipelines BrederoShaw; Bayou Pipe Coaters BrederoShaw; Bayou Pipe Coaters BrederoShaw; Bayou Pipe Coaters BrederoShaw; Bayou Pipe Coaters
Dual-Layer FBE. Dual-layer FBE coatings are used when additional protection is required for the outer layer such as high temperature, abrasion resistance, etc. For deepwater trunklines the high temperature of the internal fluid dissipates rapidly reaching ambient within a few miles. Therefore, the need for such coatings is limited for SCRs at the touchdown area where abrasion is high and an additional coating with high abrasion resistance is used. The Duval system consists of an FBE base coat (20 mils) bonded to a polypropylene coating (20 mils). The polypropylene layer provides mechanical protection. Three-Layer. Three-layer PP coating consists of an epoxy or FBE, a thermoplastic adhesive coating and a polypropylene top coat. The polyethylene (PE) and polypropylene (PP) coatings are extruded coatings. These coatings are used for additional protection against corrosion and are commonly used for dynamic systems like steel catenary risers and where the temperature of the internal fluid is high. These pipe coatings are frequently used in pipelines that are installed by the reeling method. The field joint coating for the threelayer systems is more difficult to apply and takes a longer time. However, in Europe, PE and PP coatings are preferred because of their high dielectric strength, water tightness, thickness, and very low CP current requirement. Concrete Weight Coating. Concrete weight coating is used when stability of the pipeline on the seabed is an issue. The two common densities of concrete that are used are 140 Ibs/cu. ft and 190 lbs/cu, ft. Higher density is obtained by adding iron ore to the concrete mix. Recently, higher density iron ore has been used to obtain concrete density ranging from 275 to 300 lbs/cu, ft for the Ormen Lange pipeline in the North Sea.
8.2.3
Standards Organizations with Specifications Related to Pipe Coatings
The main organizations in the US are: 9 9 9 9 9
American Society of Testing Methods (ASTM) Steel Structures Painting Council (SSPC) National Association of Corrosion Engineers (NACE) National Bureau of Standards (NBS) International Organization for Standardization (ISO)
In Europe, the more common ones are: 9 9 9 9
Det Norske Veritas (DnV) Deutsches Institut fur Nurmung (DIN) British Standards (BS) International Organization for Standardization (ISO)
102
Offshore Pipelines
8.3
Cathodic Protection
Cathodic protection is a method by which corrosion of the parent metal is prevented. The two main methods of cathodic protection are galvanic anodes and impressed current systems. For offshore pipelines, the galvanic anode system is generally used. Corrosion is an electrochemical reaction that involves the loss of metal. This is due to the fact that the steel pipeline surface consists of randomly distributed cathodic and anodic areas, and seawater is the electrolyte that completes the galvanic cell. This causes electrons to flow from one point to the other, resulting in corrosion. By connecting a metal of higher potential to the steel pipeline, it is possible to create an electrochemical cell in which the metal with lower potential becomes a cathode and is protected. Pipeline coatings are the first barriers of defense against corrosion. However, after coating the pipe the process of transportation and installation of the pipelines results in some damage to the coating. Cathodic protection uses another metal that will lose electrons in preference to steel. The main metals used as sacrificial anodes are alloys of aluminum and zinc. By attaching anodes of these metals to the steel pipeline, the steel area where the coating is damaged is protected from corrosion. Zinc anodes are not normally used in deepwater pipelines because they are less efficient and therefore require a larger mass for protecting the pipeline. However, zinc anodes can be cast onto the pipe joint and therefore no cables need to be used for electrical connection to the steel. Zinc has been used in projects where the pipeline needed to be towed along the seabed and cast-on zinc anodes were less liable to be knocked off in the process of installation. Zinc anodes do not perform well for hot buried pipelines and are subject to intergranular attack at temperatures above 50~ There is also a tendency for zinc anodes to passivate at temperatures above 70~ Aluminum anodes, on the other hand, perform much better. They are better suited for hot buried pipelines. Generally, for deepwater pipelines, aluminum alloy anodes that are attached to the pipeline are bracelet anodes. These anodes are normally attached to the pipe joint at the coating yard for S-lay and J-lay installation methods. Electrical contact to the pipeline is made by thermite welding or brazing the cable from the anode. In the case of installation of pipeline by the reeling method, the anodes are installed on the lay vessel during unreeling and straightening. In this case, bracelet anodes are attached to the pipe by bolting and attaching the cable by thermit/cadweld to the pipeline. The design of cathodic protection systems must consider the potential detrimental effects of the CP system such as hydrogen embrittlement of steel and local stresses that may lead to hydrogen induced stress cracking (HISC).
8.3.1 Cathodic Protection Design In order to conduct a CP design for a deepwater pipeline, the parameters that need to be known are: 9 9 9 9
Service/design life (years) Coating breakdown (%) Current density for protection (mA/sq.m) buried or unburied Seawater resistivity (ohm-cm)
Pipeline External Corrosion Protection 103 9 9 9 9 9 9 9 9
Soil resistivity (ohm-cm) Pipeline protective potential (normally, - 9 0 0 mV w.r.t Ag/AgCI) Anode output (amp-hr/kg) Anode potential (mV w.r.t. Ag/AgC1) Anode utilization factor (%) Seawater temperature Pipeline temperature Depth of pipeline sinkage/burial
The design life of the pipeline is based on whether it is trunkline or an infield line. The life of a trunkline can be as long as 40 years while that of an infield line is normally 20 years. The coating breakdown factor depends on the type of coating. There is very little historical data available on coating breakdown. DnV (RP-F103) and NACE (RP-01-76) have recommended values based on the type of pipeline coating. Three values of coating breakdown are typically given--initial, mean, and final. The current density, resistivity, and temperature depends on the geographical location where the pipeline is located. In deepwater pipelines, the approximate seawater temperature range is from 1.7~ to 7.5~ DnV and NACE give values for current densities and resistivities for offshore geographical locations. For bare steel buried in sediments, a design current density of 0.020A/m 2 is recommended by DnV. The type of anode used determines its electrochemical properties. The Galvalum III | anode, for example, has an anode output of approximately 2250 amp-hr/kg in seawater temperature less than 25~ and its potential is approximately - 1 0 5 0 mV. Manufacturers of anodes provide these properties for design. The anode utilization factor depends on the shape and application of the anode. Bracelet anodes are typically assumed to be 80% utilized at the end of their life, while stand-off anodes are 90% utilized. For pipeline temperatures above 25~ the design current densities increase. For each degree above 25~ the current density is increased by 0.001A/m 2.
8.3.1.1 CP Design Methodology The design methodology summarized here follows that given in DnV RP B401. Designs must satisfy two requirements: 9 The total net anode mass must be sufficient to meet the total current demand over the design life. 9 The final exposed anode surface area must be sufficient to meet current demand at the end of design life (the final exposed anode surface area is calculated from anode initial dimensions, net mass, and the utilization factor). First, one computes the current demand, (It), for initial, mean, and final stages of the design life. The current demand to protect each pipeline is calculated by multiplying the total external area (Ac) with the relevant design current density (i~) and coating breakdown factor (j~): I~ -- i ~ i ~
(8.1)
104
Offshore Pipelines
The current demands for initial polarization, Ici, and for re-polarization at the end of the design life, Icf, are normally to be calculated together with the mean current demand Icm required to maintain cathodic protection throughout the design period. It is not necessary to calculate the current demand required for initial polarization, Ici, because, initially, the pipeline corrosion coatings greatly reduce the current demand and time required for initial polarization. The coating breakdown factors for various coatings, initial, mean, and final, are given in DnVand NACE publications. For example, in the Gulf of Mexico, for FBE coating with a design life of 20 years, the initial, mean, and final coating breakdown factors normally used are 1%, 3%, and 5%, respectively. The total net anode mass Mt required to maintain cathodic protection of a pipeline throughout the design life td (years) is given by: M~ =
8760Icmtd
(8.2)
ufee where
Icm = mean current demand 8e = the electrochemical efficiency (A-h/kg) uf = the anode utilization factor. The required current output (initial/final) and current capacity for a specific number of anodes determines the required anode dimensions and net weight. The following requirements must be met by the cathodic system design: naCa >- 8760Icmtd
na]a (initial~final) >- Ic (initial~final) where na = number of anodes
Ca = anode current capacity (A-h) ira = anode current output (A). The anode current capacity (Ca) is given by: Ca = maSeUf
(8.3)
where, ma is the net mass per anode. The anode current output (Ia) is calculated from Ohm's law:
Ia - - E ~ 1 7 6 Ra where E ~ = design closed circuit potential of the anode E ~ = design protective potential Ra = anode resistance
(8.4)
Pipeline External Corrosion Protection 105 The design protective potential (Ec~ for carbon steel is -0.80 V (rel. Ag/AgC1/ seawater) when in aerated seawater and -0.90 V (rel. Ag/AgCl/seawater) when in anaerobic environments including typical marine sediments. Recommended practice states that the E ~ = - 0 . 8 V should be used for all design calculations because the initial and final design current densities are referred to this protective potential. The closed circuit anode potential (E~ for an M-based anode is taken to be - 1.1 V for the pipeline at ambient temperature and -1.085 V for the pipeline at elevated temperatures. The anode resistance (R~) formula for a bracelet anode is given by:
Ra
-
0.315. p
(8.5)
,/Ze where
Pe -- environmental resistivity Ae -- exposed anode surface area. The required number of anodes, n, can be obtained by: ~a -- ~c~
(8.6)
/aS where,
Icji = total final current demand for the pipeline Iaf = individual anode current output. Some iterations may be required to meet the requirements of both the total net anode mass, Mr, and the total final anode current output (nalaf). Generally, maximum spacing of the anodes recommended is 300 m. However, methods to calculate attenuation of protective potential with distance can be used to determine the mass and spacing of anodes. Attenuation computations are specifically useful for determining anodes for cathodic protection of Steel Catenary Risers (SCR). In SCRs, rather than placing anodes on the suspended dynamic portion, several anodes may be placed on static pipeline sections past the touchdown point. This method is also useful for short (up to 3 miles) bottom-towed pipelines with sleds at each end. Instead of placing discrete bracelet anodes along the pipeline, all total mass of anodes required for the pipeline can be placed on the end sleds. Placing them on the end sleds prevent the accidental impact and loss of bracelet anodes from the pipeline being towed along the seabed. Attenuation calculations show that if current is drained from two points on a pipeline, the change in potential of the pipe may be calculated using the following equations:
E x - EBcosh[(E'a'rRl/kpza)l/2(x-
dp/2)]
(8.7) (8.8)
106
Offshore
Pipelines
ira -- (2EB/R,) [(2rrrRl/kpza)l/2sinh(dp/2(2rrRl/kpza)l/2)] k
.]
(8.9)
where
Ex = change in potential at point x EA = change in potential at drain point r = pipe radius EB = change in potential at the midpoint between the two drain points R1 = linear resistance of the pipeline IA = total current pick up dp -- distance between drain points x = distance from drain point kp = polarization slope Za = actual bare area per linear length of pipeline Additional constraints are: 9 The current, IA, must be equal to the current that can be delivered by the lumped anode array. 9 EA must equal the anode potential less the IR drop, using the anode array resistance. 9 The anode weight must exceed the weight necessary to protect the section of the pipeline for the specified design life. Using the above equations and constraints, a greater spacing of the required mass/array of anodes may be computed.
References Aalund, L. R., "Polypropylene System Scores High as Pipeline Anti-corrosion Coating," Oil & Gas Journal (1992). Alexander, M., "High-Temperature Performance of Three-Layer Epoxy/Polyethylene Coatings," MP (1992). DnV-RP-F103 "Cathodic Protection of Submarine Pipelines by Galvanic Anodes." Gore, C. T. and Mekha, B. B., "Common Sense Requirements for Steel Catenary Risers (SCRs)," OTC Paper 14153 (2OO2). Houghton, C.J., Ashworth, V. "The Performance of Commercially Available Zinc and Aluminum Anodes in Seabed Mud at Elevated Temperatures," Corrosion Conference (1981). Kavanagh, W. K., Harte, G., Farnsworth, K. R., Griffin, E G., Hsu T. M., Jefferies, A., "Matterhorn Steel Catenary Risers: Critical Issues and Lessons Learned for Reel-Layed SCRs to a TLP," OTC Paper 14154 (2002). LaFontaine, J., Smith, D., Deason, G., Adams G., "Bombax Pipeline Project: Anti-Corrosion and Concrete weight Coating of Large Diameter Subsea Pipelines," OTC Paper (2002). NACE RP 0176 "Corrosion Control of Steel Fixed Offshore Structures Associated with Petroleum Production." Smith, S. N. "Analysis of Cathodic Protection on an Underprotected Offshore Pipeline," MP (April 1993). Varughese, K., "Mechanical Properties Critical to Pipeline Project Economics," Oil & Gas Journal (Sept. 9, 1996).