NEW DNV RECOMMENDED PRACTICES FOR GALVANIC ANODE MARINE CATHODIC PROTECTION

Tomas Sydberger DNV

N-1365 Høvik NORWAY

Matthew J. Doherty

DNV 67-72 Regent Quay

Aberdeen AB11 5AR UK

Kari Lønvik DNV

N-1365 Høvik NORWAY

John Skinner

16340 Park Ten Place Houston

TX 77084 USA

ABSTRACT Standards and other guidance documents covering design and installation of offshore cathodic protection (CP) systems have been available for over two decades. However, during this period, increased service experience has lead to a refinement in the requirements specified in the relevant codes and standards. New coating systems, some designed for substrate temperatures of 120 oC, and new operating environments (e.g. deepwater) have also acted as input to the evolution of these documents, to ensure that guidance remains relevant to modern-day subsea developments, pipelines and structures. For subsea pipelines in particular, this has reduced the conservatism inherent in CP design which affords two main advantages. Firstly, the cost of the CP system may be significantly reduced when fewer anodes have to be installed. Secondly, for certain linepipe materials the risk of cracking failure modes associated with hydrogen absorption induced by cathodic protection can be reduced, especially if CP can be provided from anodes located on adjacent structures. The development of DNV recommended practices for cathodic protection is described in detail, with reference to significant changes made for certain design parameters and the reasons behind such amendments. Comparison is also made with other CP codes, both in terms of the general methodology and by direct numerical comparison, using some illustrative examples. Keywords: marine corrosion control, cathodic protection, galvanic anodes, pipelines, standards

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INTRODUCTION

Cathodic protection (CP) by the use of sacrificial galvanic anodes continues to be used worldwide, as a reliable and cost-effective method of protecting subsea metallic components from the deleterious effects of corrosion. Some consideration is required in specifying the quantity, design and materials of construction of the galvanic anodes, in order to ensure the ‘protection object’ receives adequate CP current throughout its design life. This has driven the development of a number of standards and recommended practices, giving both general guidance and specific methodologies for design of marine CP systems and for the manufacturing and installation of galvanic anodes. This paper charts the development of a selection of these documents and uses illustrative examples to compare the anode requirement using some different CP design codes, including DNV RP-F103 and ISO 15589-2 for subsea pipelines and DNV RP-B401 for other marine structures.

EVOLUTION OF DNV RP-B401

DNV RP-B401 “Cathodic Protection Design” (first version - 1986) DNV RP-B401 “Cathodic Protection Design” /1/ was first issued by Det Norske Veritas (DNV) in 1986 with the objective of providing “general guidelines for the design, fabrication, installation and monitoring of cathodic protection systems for offshore structures and pipelines”. Prior to this, the only offshore design code which addressed these objectives was the NACE RP-01-76 “Control of Corrosion on Steel, Fixed Offshore Platforms Associated with Petroleum Production” /2/, first issued in 1976, in which galvanic anode cathodic protection was treated rather superficially. As in the NACE code, the first issue of RP-B401 did not describe the CP calculation procedures in any detail; CP design parameters related to the performance of galvanic anode parameters were defined as typical ranges, and ‘design current densities’ determining the CP current demand of bare steel surfaces were only provided for a limited number of geographical regions. For the North Sea, however, the new RP provided specific design current densities for areas south of 57oN and for 57oN – 62oN, respectively. Contrary to the NACE document, recommendations were also given regarding the effect of coatings on CP design, referring to “thin film coatings” (≤1 mm total thickness), “thick film coatings” (>1 mm total thickness) and “coated pipeline systems”. Hence, “coating breakdown criteria” (in %) were recommended for thin film coatings and “minimum design current densities for coated pipelines sufficient for up to 30 years” were specified. Moreover, requirements were defined for the quality control of galvanic anode manufacture, including a procedure for verification of the electrochemical performance of anode material during production. DNV RP-B401 “Cathodic Protection Design” (first revision - 1993) In 1992, a project to revise the 1986 issue of RP-B401 was initiated with participation of five major operators on the Norwegian continental shelf and the Norwegian Petroleum Directorate. A primary objective was to provide a detailed procedure for calculations of galvanic anode CP design, including calculations of 1) current demands to affect and to maintain cathodic protection, 2) the net anode mass required and 3) the requirement to minimum anode current capacity determining the number and size of anodes to be installed. Moreover, detailed requirements for the documentation of CP design were defined. Since the first version of RP B401 was issued in 1986, there has been a growing interest for developments in geographical areas not covered by those previously defined for selection of design current densities. To cover new areas for offshore development, it was agreed to define default design current densities for four ‘climatic regions’ (referred to as ‘arctic’, ‘temperate’, ‘sub-tropical’

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and ‘tropical’) based on the yearly mean temperature of surface waters. A 10-20% extra allowance was included to account for the effect of waves and currents in the upper 30 meters; i.e. design current densities were defined for 2 ‘depth zones’ only. At that time, there were no detailed concepts for production in waters in excess of 300 meters and it was assumed that design current densities at a depth of 30 meters would be sufficiently conservative also at this depth. It was further agreed to define the CP current reducing effects of coatings, including pipeline coatings, by a ‘coating breakdown factor’, fc, defined as:

fc = a + b · tf (1)

Hence, the coating breakdown rate was assumed to be constant so that the accumulated breakdown increased linearly with time during the CP design life (tf). This was a significant deviation from the initial version of the RP, in which the coating breakdown rate was anticipated to increase with time, leading to a logarithmic increase in the accumulated breakdown and approaching 100% at a design life of 40 years. It was further decided to define the constants a and b in eqn. (1) for four different ‘coating categories’ of paint coating. A similar approach with coating breakdown factors related to the CP design life was adopted for pipeline coatings. In the 1993 issue, reference was made to the combination of asphalt and concrete, to ‘3-layer systems’ (based on fusion bonded epoxy (FBE) in combination with either polyethylene (PE) or polypropylene (PP), and to polychloroprene based systems. However, the new coating systems were not differentiated from the older asphalt + concrete system when recommending the constants a and b for calculation of coating breakdown factors, as practical experience was still considered insufficient. Regarding the CP design parameters relating to anode performance, it was agreed to replace the specified ranges in the 1986 issue by single default values representing the minimum performance and to be used by the CP design contractor unless otherwise advised by or agreed with the purchaser. This was primarily to avoid the situation whereby an EPC contractor could use the ranges to minimise the capacity of the CP system to be provided, when the RP had been referred to in a contractual document. Also for the purpose of using the RP as a contract document, the new revision was formulated to clearly define the responsibilities of the purchaser on one hand and contractors performing either CP design, anode manufacture or anode installation on the other. Finally, a procedure for documentation of long-term properties of anode materials by laboratory testing was included as an appendix. For galvanic anode manufacture, reference was made to NACE RP 0492 /3/ and NACE RP 0387 /4/, which were issued after the first issue of RP-B401 in 1986. For CP design, DNV RP-B401 (1993) was primarily intended to describe the execution and documentation of the design work in detail. Hence, it was acknowledged in the introductory text that the selection of CP design parameters in general, and coating breakdown factors in particular, was a controversial issue among corrosion engineers. Owners of offshore structures and pipelines were therefore encouraged to use any CP design parameters they were confident with, based on any practical experience of their own. The two non-Norwegian oil and gas companies participating in the work applied the new revision accordingly as their company specification with amendments and deviations. Late in 1994, the three Norwegian companies issued a CP code designated NORSOK M-503 “Cathodic Protection Design” /5/. In this document, reference was made to the RP-B401 for calculations and documentation of CP design and for short and long term testing of galvanic anode materials. However, many of the CP design parameters were amended or modified in /5/. North Sea specific design current densities were defined for three regions (i.e. 62oN – 68oN in addition to the two defined in the first issue of RP-B401). For coating breakdown factors, a single category of ‘thin-

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film coatings’ was re-introduced whilst three categories of pipeline coating were specified, designated: ’asphalt + concrete’, ’rubber’ and ‘polypropylene’. However, the coating breakdown factors recommended for the three pipeline coating systems did not differ much (less than a factor of 2). The concept of an exponential increase of the coating breakdown rate with time (from the first issue of RP-B401) was also re-introduced for both pipeline and “thin layer” coatings using tabular coating breakdown factors rather than the ‘a’ and ‘b’ constants as in Eqn. (1) above. For a pipeline coating system based on asphalt enamel and concrete, the coating breakdown factors were somewhat lower than the corresponding values calculated from RP-B401. However, this difference vanished almost completely when all tabulated factors were increased by a factor of 1.65 in the 1997 revision of the NORSOK code. DNV RP-B401 is widely accepted as a preferred CP design code in the North Sea, the Persian Gulf, South-East Asia and in waters offshore Australia, Brazil, Western Africa and also, to some extent, offshore the USA.

DEVELOPMENT OF NEW DNV RP’s FOR MARINE CP

DNV RP-F103 “Cathodic Protection of Submarine Pipelines by Galvanic Anodes” (October 2003) Until the beginning of the 1990’s, most submarine pipelines installed were relatively large–diameter, long-distance lines for export of oil and gas from processing installations on fixed offshore installations, either steel jackets or concrete gravity based, to shore. The pipeline coatings were invariably based on a corrosion coating of asphalt or coal tar, with a concrete coating layer for the purposes of mechanical protection and/or anti-buoyancy. The first generation of submarine pipeline coatings had either poor reinforcement of the two layers or no reinforcement at all. Mechanical impacts could then potentially lead to extensive spalling of the coatings, resulting in exposure of the bare steel. Coating of field joints was normally performed without specific requirements to quality control of the application. It was even argued that any CP current-reducing effects of a field joint coating should be ignored as pipelines were sometimes installed without any such coating. In addition, an arbitrary degree of damage to the factory coating during transportation and installation was accounted for. These conditions were reflected by the coating breakdown factors defined in the first two issues of DNV RP-B401 and in NORSOK M-503. For example, the recommended coating breakdown factor at the end of a 30-year design life was up to approximately 0.10, i.e. 10% of the coated area was considered as bare steel. Further arguments for this conservatism were that the design life of such lines was often extended and that some CP current drain to other pipeline components should be included. On these lines, CP was provided by bracelet anodes clamped on top of the anti-corrosion coating prior to the application of concrete coating. Electrical continuity was achieved by lead wires with a brazed connection; no welding to the linepipe was required. After concrete application, the anodes were securely fastened so that they did not by any means interfere with the offshore pipeline installation. In relation to the total installation costs, those associated with CP were rather marginal (/11/). It could therefore be argued that an excessive CP installation was a kind of ‘insurance’ for the pipeline system and that it would in any case not be harmful to the integrity of the pipeline. Since about 1990, new offshore development concepts, primarily those based on subsea installations for production and for injection of water or gas for pressure control, have lead to the use of relatively short and small-to-medium diameter pipelines without concrete coating. Moreover, many of the production lines use thermally insulating coatings based on polypropylene (PP), polyurethane (PU)

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or some rubber compound. Associated injection lines have typically been installed with a fusion bonded epoxy (FBE) coating; in the North Sea mostly with PP jacket on top and with an intermediate layer of modified PP as an adhesive. For these coating systems, anodes had to be attached offshore and on top of the factory coating. To prevent slippage during installation, the bracelet anodes were commonly secured by welding of anode tabs to some doubler plate arrangement. CP design based on the 1993 issue of RP-B401 (and ref. /5/) lead to excessive welding of bracelet anodes during offshore installation, especially for flowlines with thermal insulation. As an example, a 16 km 8” flowline installed in 2001 with CP designed according to the NORSOK code /5/, for a design life of 15 years, had an installed net anode mass of Al-based anodes close to 18,000 kg, equivalent to over 1 kg aluminium per meter. Despite the comprehensive CP system, the pipeline was coated by an advanced multilayer FBE/PP system with a total thickness of about 50 mm and had field joint coating (FJC) of a similar design. Besides the very high costs for offshore installation of the anodes, there were growing concerns that such excessive anode installation could jeopardize the integrity of the pipeline, considering mechanical loads during installation and operation, in combination with possible material defects associated with the welding of anodes to the pipeline. An initiative to prepare a new DNV Recommended Practice (RP) dedicated to submarine pipeline CP commenced in mid 2002. Early in 2003, two Norwegian operators experienced several leakages at anode doubler plates welded to 13Cr (martensitic stainless steel) linepipe, located at field joints. The damage was soon attributed to hydrogen induced stress cracking (HISC) which had initiated at field joint coating (FJC) defects (coating disbondment), exacerbated by hydrogen generated by CP. In 2004, a third company operating the 16 km 8” flowline referred to above also experienced leakage at a field joint with identical design of anode fastening and FJC. In addition, two operators on the UK sector have experienced similar cracking damage on pipelines in type 22Cr (‘duplex’ ferritic-austenitic stainless steel) linepipe. Based on the considerations above, the emphasis for a new RP was on transmission lines and flowlines for routing of production or injection fluid over shorter distances, typically installed by reeling. Irrespective of the linepipe materials’ susceptibility to HISC, a preferred solution is to install anodes on adjacent structures such as subsea production templates, riser bases or platform substructures. Hence, additional welding on the pipe wall can be fully avoided and anodes installed on such structures have a lower cost of manufacture and installation. Additionally, the CP capacity, in terms of both current output and current charge, is higher and their condition easier to inspect than for pipeline bracelet anodes, which would normally become partly or fully buried in seabed sediments. Finally, if any future retrofitting is required, it is more practical for such anodes than for bracelet anodes. For linepipe materials susceptible to HISC, there is the additional major benefit that welding operations and damage to the linepipe coating by anode fastening can be completely avoided. Moreover, the quality of FJC is easier to control when there is no interference by any anode fastening devices located to the field joints. To achieve these objectives and to allow flowlines of considerable length (e.g. up to ≈ 30 km) to be protected by anodes at adjacent structures, it was obviously necessary to remove any undefined conservatism from the CP design assumptions. Hence, the CP design life should be equivalent to the expected useful lifetime of the pipeline and current drain to other structures should be avoided, e.g. by installing self sufficient CP systems on such structures. It was further considered necessary to presume that measures would be taken to avoid excessive mechanical damage to the coating during operation; e.g. by burial/coverage in areas with third party activities. In addition, it would be necessary to implement strict requirements to the pipeline coating systems, including the factory applied linepipe coating, field joint coatings and any field repair systems for the linepipe coating. Such requirements were to address both the coating design and the quality associated with the production of such coatings.

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In order to justify protection of pipelines by anodes located at adjacent structures, it was also necessary to include a methodology to calculate the range of CP along the pipeline length. The approach was included in DNV RP-F103 as a method of demonstrating that the voltage drop in the pipe wall was sufficiently low to ensure that the pipeline potential remained below (i.e. more negative than) the design protection potential limit, thus ensuring effective CP. A recommended practice for linepipe coatings: DNV RP-F106 (2000): “Factory Applied External Coatings for Corrosion Control” /6/ had previously been developed, sponsored by the two Norwegian oil and gas companies. This code gives detailed requirements to the design and to the quality control of coating application for the most commonly applied linepipe coating systems on submarine pipelines. However, to minimise CP current demand for flowlines as referred to above, and furthermore, to minimise the risk of HISC damage to pipelines in susceptible linepipe materials, it was considered necessary to develop a code for FJC as well. As for /6/, the new code was to cover design and quality requirements for the actual FJC systems. Field repairs of linepipe coating were also included in the scope. In October 2003, DNV RP-F102: “Pipeline Field Joint Coating and Field Repair of Linepipe External Coating” /7/, DNV RP F103: “Cathodic Protection of Submarine Pipelines by Galvanic Anodes” /8/ and a revised version of /6/ were issued. This work was also sponsored by the two Norwegian oil and gas companies. DNV RP-F103: compatibility and comparison with ISO 15589-2 Prior to the development of DNV RP-F103, a Committee Draft (CD) version of ISO 15589-2: “Petroleum and Natural Gas Industries - Cathodic Protection of Pipeline Transportation Systems – Part 2: Offshore Pipelines” /9/ had been issued for comments. Shortly before publication, a Final Draft International Standard (FDIS) version also appeared and the new standard was issued in 2004. As for RP-B401 /1/, the scope of the draft ISO document covered CP design, anode manufacture and anode installation. The ISO document had fully adopted the CP design procedure from DNV RP-B401, the procedures for laboratory testing of galvanic anode materials for quality control and for documentation of long-term performance. The sections on anode manufacture and anode installation incorporated all major requirements in NACE RP0387 /3/ and NACE RP0492 /4/. Instead of preparing a self-contained code, it was decided to base the new DNV RP on the ISO standard. Hence, for the following items, reference is made in RP-F103 to specific sections in ISO 15589-2:

- general requirements for conceptual CP design, including considerations for the selection of galvanic anode material or impressed current (IC) systems

- use of impressed current for CP of land falls - general requirements and guidelines to CP design calculations - selection of CP design parameters related to anode material and anode size/shape - design parameters related to the performance of galvanic anodes, including a default

maximum bracelet anode distance (i.e. 300 m) - general requirements to anode manufacture, including electrochemical testing for quality

control - general requirements to anode installation.

Significant amendments and deviations to ISO 15589-2 are compiled in ANNEX A, referring to 1) CP design, 2) anode manufacture and 3) anode installation.

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Comparison of CP design calculations using DNV RP-F103 (2003), ISO 15589-2 (2004) and DNV RP-B401 (1993 issue) To demonstrate the results of pipeline CP design using DNV RP-F103 (2003) compared to the old 1993 issue of DNV RP-B401 and to ISO 15589-2 (2004), CP calculations have been performed for four typical cases of submarine pipelines: Case 1: A 42” OD pipeline in CMn-steel for transmission of processed gas (shore to shore) installed by offshore welding of 12 m asphalt enamel plus concrete coated linepipe sections. Field joint coating is based on a PE heat shrink sleeve and a PU infill. The CP design premises (Tables 1 and 2) fully comply with those used for a pipeline recently installed in the North Sea. Case 2: A 20” OD pipeline in CMn-steel for transmission of processed oil to shore from an offshore platform installed in shallow waters in a tropical region (e.g. the Persian Gulf) installed by offshore welding of 12 m sections. The linepipe coating is an FBE coating with concrete coating and FJC as for Case 1 above. Case 3: A 14” OD pipeline in CMn-steel for transmission of treated seawater from a platform to a subsea manifold unit in temperate waters (e.g. in the North Sea) installed by reeling of 1000 m sections fabricated onshore. The linepipe coating is a 3-layer FBE/PP system. Two sub-cases related to FJC design apply: 3.1: a PP heat shrink sleeve (HSS) with mastic adhesive 3.2: a 3-layer FBE/PP system. Case 4: An 8” OD pipeline in martensitic stainless steel (type 13Cr) for routing of produced fluid from a subsea wellhead to a platform or to a FPSO riser base, installed by reeling of 1000 m sections fabricated onshore. The environmental conditions are as for moderate depths in the North Sea or at high depths in sub-tropical or tropical areas (e.g. off Brazil or Angola). The linepipe coating is a multi-layer FBE/PP system. Two sub-cases related to FJC design apply: 4.1: a PP heat shrink sleeve (HSS) with mastic adhesive plus strapped PU shells 4.2: a 3-layer FBE/PP system with PP applied by injection moulding to the same thickness as for the linepipe coating. CP design premises related to linepipe, internal fluid, external environment and design life for the 4 cases are compiled in Tables 1 and 2 whilst factory coating and FJC data affecting CP design are defined in Table 3.

TABLE 1 PIPELINE DESIGN PARAMETERS AFFECTING CP

Case OD Length (km)

Pipe wall thickness (mm)

Pipe material

Design life (yrs)

1 42” 300 32 CMn 50 2 20” 50 22 CMn 30 3 14” 20 16 CMn 30 4 8” 20 12 13Cr 20

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TABLE 2 PIPELINE DESIGN PARAMETERS AFFECTING CP (continued from Table 1)

Case Fluid Burial conditions

Fluid temperature (oC)

Ambient temperature (oC)

1 export gas unburied 7 7 2 export oil unburied 40 25 3 treated water buried 10 10 4 well fluid buried 70 7

TABLE 3 FACTORY COATING AND FJC PARAMETERS AFFECTING CP DESIGN

Case Factory coating

System1

) (F106)

FJC System

System1) (F102)

Total thickness

(mm)

Cut-back length (mm)

1 Asphalt enamel + concrete

CDS 5 HSS + infill

CDS 1A 70 300

2 FBE + concrete

CDS 2 HSS + infill

CDS 1A 50 250

3.1 3-Layer FBE/PP

CDS 3 HSS CDS 1A 4 200

3.2 3-Layer FBE/PP

CDS 3 3-layer FBE/PP

CDS 3D 4 200

4.1 Multi-Layer FBE/PP

CDS 5 HSS + PU half shell

CDS 1A 100 250

4.2 Multi-Layer FBE/PP

CDS 5 3-layer FBE/PP

CDS 3D 100 250

1) Coating system designations in DNV RP-F106 and DNV RP-F102

Based on information from an anode manufacturer, the minimum dimensions of bracelet anodes and the associated tentative minimum net anode mass (mmin) have been estimated, taking into account common casting practice for such anodes. These data are compiled in Table 4.

TABLE 4 ANODE PARAMETERS AFFECTING CP DESIGN

Case Anode material

Minimum anodethickness (mm)

Minimum anode length (mm)

Minimum net anode mass (kg)

1 AlZnIn 70 500 325 2 AlZnIn 50 350 72 3 AlZnIn 50 200 30 4 AlZnIn 50 250 43

The results from CP design calculations in Tables 5 and 6 have utilised the design current densities and anode performance data as specified in DNV RP-F103, ISO 15589-2 and in the 1993 revision of

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DNV RP-B401, respectively. The design current densities according to RP-F103 are based on the internal fluid temperature whilst those from the ISO code are determined from the ambient seawater temperature, in accordance with the two codes. For Case 4, the temperature correction factor from the ISO code is based on the conservative assumption that the outer pipe temperature is equal to that of the internal fluid. The calculations according to RP-F103 use the same anode utilisation factors and electrochemical efficiencies as in the ISO code. However, a design factor of 0.80 has been applied in accordance with 5.4.3 of the RP. The design current densities for seawater exposure (Case 1 and 2) used for calculations according to the ISO standard were taken from the lower curve in Fig. 2 as this represents the minimum requirement as for the design current densities as given in the DNV RP’s. Using the design premises and parameters above, the minimum required total net bracelet anode mass per 10 km of pipeline (here designated ‘Mo

min’) have been calculated as specified in DNV RP-

F103, ISO 15589-2 and in the 1993 revision of DNV RP-B401, respectively. For the buried pipelines of Cases 3 and 4, Mo

min is calculated for the two sub-cases that CP is provided by either bracelet anodes (assumed conservatively to be heated to the same temperature as the fluid and with an utilisation factor of 0.80) or stand-off type anodes installed on an adjacent structure (utilisation factor 0.90 and ambient seawater temperature).

TABLE 5 CALCULATED NET ANODE MASS BASED ON BRACELET TYPE ANODES

Minimum net anode mass required (Mo

min) as bracelet anodes (kg per 10 km)

Net anode mass installed (Mmin) as bracelet anodes of min. size and a distance of 300 m (kg per 10 km)

Case

DNV RP-F103

ISO 15589-2

RP B401 (1993)

DNV RP-F103

ISO 15589-2

RP B401 (1993)

Case 1 10 400 10 700 66 000 12 000 12 000 66 000 Case 2 1 550 1 250 9 830 2 500 2 500 9 830 Case 3.1 352 294 1 800 1 000 1 000 1 800 Case 3.2 82 294 1 800 1 000 1 000 1 800 Case 4.1 610 268 7 000 1 500 1 500 7 000 Case 4.2 65 268 7 000 1 500 1 500 7 000

TABLE 6 CALCULATED PROTECTION LENGTH AND MINIMUM NET ANODE MASS

Protection length (km)

Minimum net anode mass required (Mo

min) as stand-off anodes (kg per 10 km)

Minimum net anode mass installed (Mmin) as 100 kg stand-off anodes (kg per 10 km)

Case

DNV RP-F103

ISO 15589-2

DNV RP-F103

ISO 15589-2

DNV RP-F103

ISO 15589-2

Case 3.1 8.6 10.0 (250) 210 (300) 300 Case 3.2 21.2 10.0 58 210 100 300 Case 4.1 3.6 5.0 (135) (60) (200) (100) Case 4.2 12.0 5.0 15 (60) 100 (100)

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If CP is based on bracelet anodes and with a minimum anode distance of 300 m (recommended as a default value in both ISO 15589-2 and DNV RP-F103), the minimum installed net anode mass (Mmin) may exceed Mo

min, as Mmin is determined by the minimum net weight (mmin) of the individual anodes for the actual bracelet anode (Table 4). For CP by bracelet anodes, Mo

min and Mmin for the four pipeline cases are calculated in Table 5. Using RP-F103 and the ISO standard, Mmin and Mo

min were found to be virtually identical for Case 1 whilst Mmin exceeded Momin by a factor of

close to 2 for Case 2. However, for Case 3 and 4, this factor was as high as 3 to 20. On the other hand, when calculations were performed according to the 1993 revision of RP-B401, the required net anode mass (Mo

min) calculated is higher than the installed net mass (Mmin) if anodes with the minimum net anode mass (mmin) were to be installed with a minimum distance of 150 m (as recommended in the 1993 revision of RP-B401). Hence, in order to meet the required net anode mass, the anode size must be increased and/or the minimum distance reduced. In Table 4, Mmin then becomes equal to Mo

min. For Case 3 and Case 4, Mmin has also been calculated assuming that CP is to be provided by stand-off anodes with an assumed anode net mass of 100 kg. These results are compiled in Table 6. The parentheses indicate that the protective length of such anodes (i.e. independent of the installed mass) as calculated below is less than 10 km. As seen in Table 5, the minimum required net anode mass (Mo

min) for the asphalt + concrete coated export pipelines (Case 1 and 2) calculated from the new RP-F103 and the ISO standard is only 10-20% of that calculated from the 1993 version of RP-B401. For the transmission and flowlines with FBE/PP coating (Case 3 and 4), the difference is even larger; the net anode mass required by the two new codes being only 1-10% of that using RP-B401. For Cases 3 and 4, it would be preferable to install the required anode mass on an adjacent structure; the protective length (L) of such anodes has been calculated in Table 6 from eqn. 12 in RP-F103. According to the new RP, a length of the order of 5-20 km then can be protected. However, the actual protective range is much dependent of the FJC design, hence, the results indicate that the full length of the 20 km pipeline according to Case 3 and 4 can be protected by anodes on structures on both ends of the pipeline only if FJC systems with a design and quality control according to the sub-cases 3.2 and 4.2 are applied. Calculations utilising the equation above were also performed using the coating breakdown factors, design current densities and design protective potentials in the ISO standard, in combination with the default values for linepipe specific electrical resistivity in 5.6.10 of RP-F103. The latter calculations gave a protective length of about 5-10 km; however, it is not clear if the heat shrink sleeves of Case 3.1 and 4.1 can be considered to meet the requirement in the ISO standard for “a quality equivalent to the factory-applied coatings” (see Annex A, Item D.1.2), which is a pre-requisite for the recommended coating breakdown factors referring to the type of factory coating only. The use of coating breakdown factors from the ISO document for this purpose is discussed below. DNV RP-B401 “Cathodic Protection Design” (January 2005 revision) The following items in the 1993 revision have been deleted from the scope of the 2005 revision: - CP design, anode manufacture and anode installation related to submarine pipelines. - General considerations for the design and fabrication of impressed current CP systems. - General considerations for the inspection and monitoring of CP. Significant amendments and changes/deviations to the 1993 revision are compiled in ANNEX B, referring to 1) CP design, 2) anode manufacture and 3) anode installation.

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In the 2005 revision and as in /6-8/, guidelines and information to users have been included as ‘Guidance Notes’, most of which are based on queries from users of the document. Comparison of CP design calculations using the new 2005 revision and the old 1993 revision of DNV RP-B401 CP design calculations have been performed to compare the results of CP design carried out according to the new and the old revisions of RP-B401. Hence, the net anode mass of AlZnIn anodes for CP has been calculated for a jacket structure of 100 m2 steel area located at a depth of 100 m in a temperate and in a tropical region, respectively. For simplicity, this calculation has been carried out disregarding the higher current density for the uppermost 30 m. The calculations have been performed for bare steel and for coated steel (‘Coating Category II’). Further calculations have been performed for a subsea template located at a depth >300 m in a temperate and in a tropical region as above but with ‘Coating Category III’ for its coated surfaces. Calculations were subsequently performed to verify that the final current output capacity of the anodes met the final current demands in each case. These calculations were based on stand-off type anodes with typical dimensions for a net anode mass of about 100 kg and 300 kg for the template and jacket respectively, applying a default specific seawater resistivity of 0.30 ohm·m.

TABLE 7 CALCULATED MINIMUM NET ANODE MASS FOR BARE STEEL AND COATED

SURFACES Minimum net anode mass

required (kg/100m2) Item Depth Coating

category1) Climatic region

RP B-401 (1993)

RP B-401 (2005)

Steel jacket 100 m (bare steel) Temperate 1 170 1 170 Steel jacket 100 m (bare steel) Tropical 876 876 Steel jacket 100 m II Temperate 409 321 Steel jacket 100 m II Tropical 307 241 Subsea template >300 m (bare steel) Temperate 1 170 1 610 Subsea template >300 m (bare steel) Tropical 876 1 310 Subsea template >300 m III Temperate 234 225 Subsea template >300 m III Tropical 175 184

1) As defined in DNV RP-B401 As seen in Table 7, the current demand of bare steel in shallow waters (up to 100 m) is the same in the 1993 and the 2005 revisions. However, at depths exceeding 300 m, the current demand calculated from the new revision is markedly higher. This is due to that the design current densities have been increased to account for the effect of depth on the expected current-reducing performance of calcareous deposits and in tropical regions also oxygen contents exceeding those in more shallow water depths /12/. However, the practical consequences of this is marginal since C-steel items related to subsea production installations are mostly coated and the lower coating breakdown factors in the new revision compensate for the higher design current densities in both temperate and tropical regions (see Table 7).

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DISCUSSION

CP of larger diameter export pipelines with concrete weight coating (DNV RP-F103) Compared to the 1993 revision of DNV RP-B401, the reduction in the minimum required net anode mass (Mo

min) when using DNV RP-F103 or the ISO standard is substantial, as illustrated in Table 5 above. The long term experience of coatings based on asphalt or coal tar enamel plus concrete is quite extensive and the new coating breakdown factors reflect the practical experience of major operators of offshore pipelines participating in the development of the ISO standard. Although the coating breakdown factors in DNV RP-F103 refer to specific linepipe and FJC systems as defined in DNV RP-F106 and DNV RP-F102, respectively, the requirements for design and quality control of the actual coating systems in these RP’s generally comply with “commonly applied industry standards” as referred to in the ISO document. The coating breakdown factors for linepipe and FJC coating in RP-F103 have been defined to match those for the actual “corrosion and thermal insulation coatings” (i.e. factory coating plus FJC) as referred to in the ISO standard. The linepipe and FJC coating systems used for asphalt + concrete coated export pipelines are considered as quite robust and with moderate requirements to quality control (i.e. when compared to those based on FBE as the innermost layer). However, it is emphasised that the calculated net anode mass according to RP-F103 should be considered an absolute minimum requirement, since it does not include any form of contingency for e.g. lifetime extension, third party coating damage or current drain to other pipeline components. To account for any such factors, the use of a design factor (see Annex A, Item A.1.1) should be duly considered. CP of medium and small diameter transmission lines and flowlines (DNV RP-F103) Comparison of the required net anode mass (Mo

min), calculated using the old RP-B401 and the new pipeline CP design code as made in Table 5, is not actually relevant because the coating breakdown factors recommended in the old RP did not reflect the properties of the coating systems currently in use. However, although the minimum required net anode mass for the new codes is only a small fraction of that required by the old one, the use of ’traditional’ bracelet anodes with a maximum spacing of 300 m corresponds to an installed net anode mass (Mmin) being only moderately lower than specified using the old code. As emphasised above, a main purpose of DNV RP-F103 is to allow for flowlines and transmission line of a length up to 30 km approximately to be protected by anodes located on adjacent structures and being freely exposed to seawater. The protective range of such anodes is then limited by the voltage drop generated by the CP current returning to the anodes through the pipe wall. Hence, the anode capacity installed on such structures does not affect the protective length as long as the structure itself is adequately protected. Also the ISO standard allows for this CP concept but does not contain the equations and design parameters that are necessary to affect such calculations (see Annex A, Item A.1.4). To maximise the protective range and to ensure that pipelines can be reliably protected by anodes on adjacent structures, the current demand of the pipeline must be assessed as accurately as possible. This current demand is primarily determined by the design of the coating systems applied and quality control in their application. With respect to coating design, the coating breakdown factors in the ISO standard (Table 3) refer to either generic types of coating systems (e.g. “fusion bonded epoxy”) or merely the coating’s function (“thermal insulation systems”). As to quality control of coating application, the ISO standard assumes “coating quality being in accordance with commonly applied industry standards”. For coating systems based on FBE as the innermost layer in particular,

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insufficient control of surface preparation and heating before coating application has frequently caused severe deficiencies of pipeline coatings with resulting disbonding and blistering /12/. The coating breakdown factors recommended in DNV RP-F103, are based on detailed requirements for both coating design and quality control, as defined in DNV RP-F106 and DNV RP-F102 for linepipe and FJC, respectively. A primary requirement in the RP’s is that coating application shall be preceded by a project specific qualification of the coating application procedure, including destructive testing of adhesion to the pipe material and to overlapping parent coating, as well as resistance to coating disbondment by chemical or physical effects. Coating application is then to be performed in accordance with the qualified procedure, including compliance with process parameters essential for the quality of the coating. A further assumption implicit in the definition of coating breakdown factors in the ISO standard is “field joints having a quality equivalent to the factory-applied coatings”. Although reference is only made to the FJC ‘quality’, it is possibly the intention that also the design of the FJC shall be ‘equivalent’ to that of the parent coating. However, it is then unclear how pipelines with FJC of a design apparently inferior to that of the linepipe coating (i.e. as for Case 3.1 and 4.1 above) shall be treated. In addition to the specific design and quality control requirements, DNV RP-F103 takes into account the dimensions of the factory coating cut-back, use of any infill and the frequency of FJC along the pipeline. Even if stringent requirements to the quality control of FJC application are also specified, it is recognised that FJC’s invariably represent a discontinuity of the pipeline coatings and with conditions for application that are less well controlled than continuous application of linepipe coating in a plant. Hence, for the same generic type of coating systems, the values of ‘a’ and ‘b’ used to calculate the coating breakdown factors (fc) of FJC are typically a factor of 3-10 higher than for those to be used for linepipe coating of the same type. CP of other marine structures (DNV RP-B401) The maintenance design current densities given in DNV RP-B401 /1/ are generally higher than those for coated pipelines in DNV-RP F103 /8/. As explained in the Guidance Note to paragraph 5.2.4, the CP current demand of multilayer coating systems (with coating breakdown factors defined in ANNEX 1 of /8/) is related to the leakage of current at pores and narrow cracks or crevices in the coating, primarily associated with field joints. Hence, the cathodic current is assumed in /8/ to be related primarily to hydrogen formation, whilst oxygen reduction is considered to play only a minor role. In the ISO standard /9/, however, oxygen reduction is apparently considered as the primary cathodic reaction as design current densities for pipelines are assumed to be markedly affected by seabed currents. Another consequence of this is that the required current density is assumed to decrease markedly in the ambient seawater temperature range 5 oC to 30 oC. If the cathodic current density is assumed to be related primarily to hydrogen evolution, an increase in current density is rather expected. According to /9/ (Table 2), “cold deep conditions” would require a maintenance design current density as high as 0.300 A/m2, referring to the Norwegian Sea with water depths up to 1,500 m and seawater temperatures in the range -1 to 4 oC. This would require an initial design current density about twice as high (0.600 A/m2). However, to the knowledge of the authors, the need for such high design current densities has not been documented. Hence, when testing in the North Sea /13/ was performed with CP loggers with an initial design current density of 0.220 A/m2 at locations with a depth of 600 m and 1300 m, polarisation occurred readily at the sea bottom where the ambient temperature was close to -1 oC. (The above initial design current density corresponds to a

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maintenance current density of about 100 A/m2 after polarisation to a protection potential more negative than – 0.90 V(Ag/AgCl/seawater)) However, for identical CP loggers installed at the same locations but at a depth of 100 m and 200 m and with an ambient seawater temperature of 6 to 8 oC, polarisation was more sluggish. This performance was related to the higher sea currents at the lower depth /13/.

SUMMARY AND CONCLUSIONS

Subsea development at large depths and with environmental conditions affecting CP design which markedly differ from those in surface waters have prompted the needs for amendments to the previously issued CP design codes. This applies in particular to design current densities applicable to surfaces of bare steel and painted steel with coating defects exposing bare steel, being related to convective mass transfer of dissolved oxygen and the formation of calcareous deposits retarding this process. For pipelines with thick layers of coating, however, the cathodic reaction is rather related to hydrogen formation and the effect of the internal fluid temperature is more significant than the ambient seawater temperature affecting oxygen solubility. For subsea pipelines, it is primarily the installation of flowlines and transmission lines for routing of produced fluid or injection fluid from/to subsea installations that have lead to needs for amendments of the existing CP codes. Hence, new coating systems have been developed for the purpose of thermal insulation and/or compatibility with reeling operations for pipeline installation. Some of the systems applied offer superior isolation to the environment and hence, with a potential for very low CP current demands. On the other hand, some of the systems are inherently liable to coating disbondment due to insufficient quality control of the application process or improper design/application of field joint coatings. During the last years, contemporary CP design codes have led to excessive installation of bracelet anodes that may jeopardize the integrity of the pipeline during installation and operation. As an example, an 8” North Sea flowline installed in 2001 with a design life of 15 years and with CP design according to the NORSOK M-503 code had an installed net Al-based anode mass of more than 1,000 kg per km. The anodes are typically attached by welding to pre-installed doubler plates on the pipelines during offshore un-reeling and welding defects as well as hydrogen induced stress cracking (HISC) induced by CP under disbonded coating have lead to fractures of linepipe materials susceptible to HISC by cathodic protection. Even for materials not susceptible to HISC, excessive amounts of anodes welded to the pipeline may jeopardise the integrity of the pipeline during installation and operation. For pipeline CP design, the ‘coating breakdown factor’ is the primary design parameter determining the required minimum CP capacity. The coating breakdown factors recommended in the CP design code DNV RP-F103 (2003) are based on detailed requirements for coating design and quality control of the application, as defined in DNV RP-F106 and DNV RP-F102 for linepipe and FJC, respectively. In ISO 15589-2 (2004), however, coating breakdown factors are recommended for pipeline coatings based on the generic type or function of the coating, referring to the “quality” of the linepipe and the field joint coating being according to “commonly applied industry standards” and “equivalent to the factory-applied coatings”, respectively. The DNV RP, on the other hand, recognises that FJC’s invariably represent a discontinuity of the pipeline coatings and with conditions for application that are less well controlled than continuous application of linepipe coating in a plant. Hence, RP-F103 recommends coating breakdown factors that are a factor 3-10 higher than

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those for the linepipe coating of the same design and takes into account the length and frequency of field joint coatings, in addition to their specific design. For medium and large diameter export pipelines with traditional coatings based on asphalt or coal tar enamel in combination with concrete, the minimum required net anode mass calculated from the new DNV and ISO standards for pipeline CP design is markedly lower according to the 1993 revision of DNV RP-B401. On the other hand, when bracelet anodes of a typical size in relation to pipe diameter and concrete coating thickness are installed and with a maximum distance of 300 m as specified in both codes, the minimum installed net anode mass will in most cases exceed the minimum required net anode mass, thus providing some additional contingency. The concept of installing ‘anode joints’ at regular intervals along pipelines of this type is technically adequate and there are no major economic advantages of minimizing the installed capacity. Pipeline owners are therefore advised to aim for a robust CP design with an installed capacity well exceeding the minimum requirement calculated from any of the two codes. Hence, it is emphasised in DNV RP-F103 that contrary to the old revision of DNV RP-B401, any major coating defects associated with the manufacturing process, transportation and handling of coated pipes, pipeline installation or 3rd party damage during operation is not included, nor is any contingency for lifetime extension or current drain from other structures. To ensure additional conservatism in CP design, the use of design factor (>1) is recommended rather than modification of individual CP design parameters. The coating breakdown factors in DNV RP-F103 associated with coatings for small and medium diameter flowlines and transmission lines have been defined with the primary purpose of calculating the protective length of stand-off or flush mounted anodes installed on an adjacent structure for protection of the pipeline, or that of bracelet anodes (or other anode configurations) installed along the pipeline at a distance widely exceeding the maximum default value of 300 m. As discussed in the paper, the concept of installing anodes on adjacent structures offers some main advantages, particularly for pipelines in materials susceptible to HISC. Equations for calculations of the protective range of such anode configurations are derived in the RP. Hence, with stringent requirements to the design and quality control of field joint coatings in addition to the factory applied coating, lines with a length up to about 30 km can readily be protected by installing one or a few extra anodes on the adjacent structures, or by utilizing an existing excess CP capacity. Also the ISO standard (7.1) encourages CP of “short pipelines” by anodes located “at each end of the pipeline”. The coating breakdown factors in ISO 15589-2 are, however, not considered useful for this purpose. On the other hand, this is not the intention since any assessment of the protective length shall utilise “attenuation calculations” according to Annex A of the standard, with the ‘pipe-to-electrolyte insulation resistance’ as the most critical parameter and which “should be selected based on practical experience”. The DNV codes for corrosion control have been formulated with two major objectives. Firstly, they may be used as a guideline for owners of offshore installations or their contractors’ in preparation of specifications covering the scope of the RP’s. Their second primary function is for use as an attachment to an inquiry or purchase order. For the latter purpose, the codes contain detailed requirements and guidelines for project specific information to be provided by the purchaser, and for the specification of any amendments and deviations. The documents are available free of any charge on the DNV home page, and are amended twice per year based on feedback from users.

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REFERENCES

/1/ DNV RP-B401 “Cathodic Protection Design” (January 2005) /2/ NACE RP-01-76 “Control of Corrosion of Steel, Fixed Offshore Platforms Associated with Petroleum Production” (2004) /3/ NACE RP 0492 “Metallurgical and Inspection Requirements for Offshore Pipeline Bracelet Anodes” /4/ NACE RP 0387 “Metallurgical and Inspection Requirements for Cast Sacrificial Anodes for Offshore Applications” /5/ NORSOK M-503 “Cathodic Protection Design” (1997) /6/ DNV RP-F106 (2000): “Factory Applied External Coatings for Corrosion Control” (October 2003) /7/ DNV RP-F102: “Pipeline Field Joint Coating and Field Repair of Linepipe External Coating” (October 2003) /8/ DNV RP-F103: “Cathodic Protection of Submarine Pipelines by Galvanic Anodes” (October 2003) /9/ ISO 15589-2: “Petroleum and Natural Gas Industries- Cathodic Protection of Pipeline Transportation Systems – Part 2: Offshore Pipelines” (2004) /10/ Sydberger, T., Edwards, J.D. and Tiller, I.B.: “Conservatism in Cathodic Protection Design”, Materials Performance, February 1997, p. 27 /11/ NACE Internal Publication 7L192 (1992): “Cathodic Protection Design Considerations for Deep Water Structures” /12/ Norman, D. and Argent, C: “Fitness for Purpose Issues Relating to FBE and Three Layer PE/PP Coatings”, CORROSION’2006 (NACE), paper no HOLD /13/ MARINTEK report 78.1085.01 (01.04.1998): “Norwegian Deepwater Programme: Cathodic Protection Testing at Vøringplatået”

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ANNEX A

AMENDMENTS AND CHANGES/DEVIATIONS TO ISO 15589-2 MADE IN DNV RP-F103 (The references within parentheses refer to RP-F103)

A.1. Amendments to CP Design A.1.1 Use of a ‘design factor’ to introduce any additional (specific or general) conservatism in CP design (1.2.1). A.1.2 Default values for coating breakdown factors for pipeline components protected by “ordinary” marine paint coating systems and constituting a surface area maximum 2% of the total surface area and minimum requirements to such coatings (5.2.8). A1.3 Use of a design factor (0.8) for anode electrochemical efficiency data (i.e. as specified in the ISO standard) to be applied when no reliable documentation of the performance of anodes from candidate suppliers is available at the CP design stage, and/or the anode current density of operating anodes cannot be confirmed to exceed 1 A/m2 (5.4.3). A.1.4 Derivation of simple formulas for the calculation of the protective range of anodes located on adjacent structures, and for bracelet anodes installed at a distance exceeding the recommended value of 300 m (5.6.3- 5.6.9). The derivation of the formulas is explained and all parameters to be used are defined in the code. The ISO standard (Annex A), on the other hand, recommends a set of more complicated ‘attenuation formulas’ containing the ‘pipe-to-electrolyte resistance’ as the most critical variable, “to be selected based on practical experience”. A.1.5 Default values for specific electrical resistivity of linepipe materials (5.6.10). The ISO standard refers to literature. A.1.6 Extended requirements to the documentation of completed CP detailed design (5.7). In addition, some guidelines regarding the selection of CP design parameters and the execution of design calculations are made in Sec. 5 of the RP. A2. Amendments to Anode Manufacture A.2.1 Requirements (mandatory or optional to purchaser) for documentation of quality control procedures, including manufacturing procedure specification, pre-production qualification testing, inspection and testing plan and daily log ( 6.2-6.4). A.2.2 Requirements (mandatory) for verification, handling and storage of materials for anode manufacture (6.5). A.2.3 Requirements (mandatory or optional to purchaser) regarding chemical analyses of produced anodes. (6.6.1). A.2.4 Requirements (mandatory or optional to purchaser) for documentation and marking (6.7). A.2.5 Requirements (mandatory or optional to purchaser) for handling, storage and shipping of anodes (6.8). A3. Amendments to Anode Installation A.3.1 Requirements (mandatory or optional to purchaser) for the documentation of quality control procedures, including installation procedure specification, pre-production qualification testing, inspection and testing plan and daily log (7.2-7.4). A.3.2 Requirements (mandatory) for verification, handling and storage of materials for anode installation (7.5). A.3.3 Requirements (mandatory) for bolting for anode fastening (7.1.3), qualification of brazing procedures (7.3.2) and damage to linepipe coating (7.6.3).

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A.3.4 Requirements (mandatory) regarding inspection and testing (7.7). A.3.5 Requirements (mandatory and optional to purchaser) regarding documentation (7.8). D1. Deviations to CP Design For the following items, some significant deviations (in combination with amendments) to ISO 15589-2 have been made in DNV RP-F103: D.1.1 The ISO standard (figure 2) gives design current densities for seawater exposure as a function of seawater temperature (0oC to 30oC) in the form of an ‘upper’ and a ‘lower’ curve. For pipelines with temperatures exceeding 50oC but maximum 80oC “on the outside surface of the pipe”, an increase in design current density by 1 mA/m2 for each oC is recommended. For temperatures exceeding 80 oC, “a special assessment of current densities should be carried out”. RP-F103 (Table 5-1), on the other hand, gives recommended default values for the minimum design current density only, based on the internal fluid temperature and for the ranges ‘≤50oC’, ‘>50oC to 80oC’, ‘>80oC to 120oC’ and ‘>120oC’. At a fluid temperature of >5oC to 50oC, the recommended default minimum value of 0.050 A/m2 in the RP corresponds to the range 0.070 A/m2 to 0.030 A/m2 using the ‘lower’ curve in Fig. 2 of the ISO standard. For fluid temperatures of >50oC to 80 oC, and based on the conservative assumption that the external pipe surface temperature is equal to the fluid temperature, the recommended default minimum value of 0.080 A/m2 in the RP corresponds to 0.030 A/m2 to 0.100 A/m2 in the ISO standard and for seawater temperatures in the range >5oC to 30oC. For buried pipelines, both documents recommend a design current density of 0.020 A/m2 independent of seawater temperature and fluid/pipe temperature up to 50oC. For fluid temperatures of >50oC to 80oC, the recommended default minimum value in the RP is 0.025 A/m2. Based on the conservative assumption that the external pipe temperature is equal to the fluid temperature, the design current density advised in the ISO standard (lower curve) is 0.020 A/m2 to 0.050 A/m2. D.1.2 RP-F103 (ANNEX 1) recommends coating breakdown factors for coating systems (factory applied and field applied) of a specific design and maximum operating temperature. Reference is then made to DNV RP-F106 and DNV RP F102 for factory applied coatings and to field joint coatings/factory coating field repairs, respectively. These documents also give detailed requirements to the quality control of the coating application. D.1.3 The recommended design protective potential for martensitic stainless steel type 13Cr in the DNV RP (5.6.11) is -0.60 V(Ag/AgCl/seawater). The design value recommended in the ISO standard (Table 1) is -0.50 V. (The reason for this deviation is that field testing of 13Cr linepipe material in marine sediments gave an anodic current when the specimen was polarised to -0.50V (Ag/AgCl/seawater). D2 Deviations to Anode Manufacture There are no deviations to the ISO standard. D3 Deviations to Anode Installation D.3.1 Whilst the ISO standard recommends both clamping and welding of anodes to linepipe with SMYS up to 550 MPa, the RP (7.1.2) advises against the use of welding for all CRA linepipe (typically with SMYS 450 to 550 MPa).

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ANNEX B

AMENDMENTS AND CHANGES/DEVIATIONS TO THE 1993 REVISION MADE IN THE 2005 REVISION OF DNV RP B-401

(The references within parentheses refer to the 2005 revision of RP-B401)

A.1. Amendments to CP Design For the following items, some significant amendments have been made in the 2005 revision: A.1.1 More comprehensive advice on the CP compatibility of metallic materials with respect to hydrogen induced stress cracking (HISC) and measures to avoid HISC (5.5.3- 5.5.11). A.1.2 Warning regarding evolution of hydrogen gas by galvanic anode CP in closed compartments (5.5.12). A.1.3 For steel structures, two further Depth Zones: ‘>100 m to 300 m’ and ‘>300 m’ have been added for the definition of design current densities (6.3.6 referring to Tables 10-1 and 10-2 in Annex A). A.1.4 For CP of steel reinforcement in concrete structures, one further depth zone: ‘>100 m’ has been added for the definition of design current densities (6.3.12 referring to Table 10-3 in Annex A). It is further specified that for external CP of concrete shafts that are normally empty, the design current densities in Table 10-3 shall be multiplied with a factor of 1.5. A.1.5 Information to Contractor and specification of optional requirements to CP design by Purchaser has been added (7.1.2). A.1.6 Advice against the use of anodes with large differences in size. A.1.7 Extended Guideline Notes for selection of CP parameters in Sec. 6 and CP calculations in Sec. 7. C.1. Changes (Deviations) to CP Design For the following items, some significant changes have been made in the 2005 revision: C.1.1 As a consequence of A.1.3 above, some changes have been made for the initial/final design current densities recommended for the Depth Zones: ‘0 m to 30 m’ and ‘>30 m to 100 m’ (6.3.6 referring to Table 10-1 in Annex A). These changes are, however, within ±10% of those in the 1993 issue. C.1.2 As a consequence of A.1.4 above, some of the design current densities recommended for the Depth Zones: ‘0 m to 30 m’ and ‘>30 m to 100 m’(6.3.12 referring to Table 10-3 in Annex A) have been reduced. C.1.3 The number of Coating Categories has been reduced from 4 to 3 and the definitions of the individual categories have been changed. C.1.4 As a result of C.1.3 above, the ‘a’ and ‘’b’ values for calculations of coating breakdown factors have been reduced. A.2. Amendments to Anode Manufacture For the following items, some significant amendments have been made in the 2005 revision: A.2.1 Information to Contractor and specification of optional requirements to anode manufacture by Purchaser has been added (8.1.2). A.2.2 Requirements for a ‘Manufacturing Procedure Specification’ (mandatory) have been extended/detailed (8.2). A.2.3 Requirements regarding ‘Pre-Production Qualification Testing’ (mandatory for purchase orders of 15 000 kg net alloy mass or more, optional for smaller orders) have been extended/detailed (8.3).

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A.2.4 Requirements for quality control during production (mandatory and optional) have been extended/detailed (8.4-8.6). This applies especially to traceability and handling of materials (8.5), chemical analyses (8.6.1), visual inspection of anodes for cracks and other surface irregularities (8.6.3), destructive testing/inspection of anodes (8.6.5), sampling, testing procedure and acceptance criteria for electrochemical testing (8.6.6-8.6.7 and Annex B). Contrary to the 1993 revision, 3% NaCl solution is not allowed for testing; the testing solution shall be either natural seawater or synthetic seawater according to ASTM D1141. A.2.5 Requirements regarding documentation and marking (mandatory and optional) have been extended/detailed (8.7). A.3. Amendments to Anode Installation For the following items, some significant amendments have been made in the 2005 revision: A.2.1 Information to Contractor and specification of optional requirements to anode installation by Purchaser has been added (9.1.3). A.2.2 Requirements for an ‘Installation Procedure Specification’ (mandatory) have been extended/detailed (9.2). A.2.3 Requirements regarding the qualification of anode installation (mandatory if welding is applied) have been extended/detailed (9.3). A.2.4 Requirements for quality control during production (mandatory and optional) have been extended/detailed (9.4-9.6). A.2.5 Requirements regarding documentation (mandatory and optional) have been extended/detailed (9.7). C.4/A.4 Changes and Amendments to the Procedure for Performance Testing of Sacrificial Anode Materials (Annex C in the 2005 revision) For the following items, some significant changes and amendments have been made in the 2005 revision: C.4.1 Requirements for sampling and size of specimens for testing have been altered (12.2.1-12.2.3). C.4.2 The recommended minimum size of the cathode has been altered from 20 to 30 times the initially exposed anode surface (12.3.5). A.4.1 Requirements regarding documentation have been extended/detailed (12.4).

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