ISO 15589-2:2004

Petroleum and natural gas industries - Cathodic protection of pipeline transportation systems - Part 2: Offshore pipelines

ISO 15589-2:2004 specifies requirements and gives recommendations for the pre-installation surveys, design, materials, equipment, fabrication, installation, commissioning, operation, inspection and maintenance of cathodic protection systems for offshore pipelines for the petroleum and natural gas industries as defined in ISO 13623. ISO 15589-2:2004 is applicable to carbon and stainless steel pipelines in offshore service. ISO 15589-2:2004 is applicable to retrofits, modifications and repairs made to existing pipeline systems. ISO 15589-2:2004 is applicable to all types of seawater and seabed environments encountered in submerged conditions and on risers up to mean water level. Note that special conditions sometimes exist where cathodic protection is ineffective or only partially effective. Such conditions can include elevated temperatures, disbonded coatings, thermal insulating coatings, shielding, bacterial attack, and unusual contaminants in the electrolyte.

Industries du pétrole et du gaz naturel — Protection cathodique des systèmes de transport par conduites — Partie 2: Conduites en mer

General Information

• Status: Withdrawn
• Publication Date: 04-May-2004
• Withdrawal Date: 04-May-2004
• ICS: 75.200 - Petroleum products and natural gas handling equipment
• Technical Committee: ISO/TC 67/SC 2 - Pipeline transportation systems
• Drafting Committee: ISO/TC 67/SC 2 - Pipeline transportation systems
• Current Stage: 9599 - Withdrawal of International Standard
• Start Date: 04-Dec-2012
• Completion Date: 13-Dec-2025

Relations

• Consolidates: ISO/R 981:1969 - Title missing - Legacy paper document
• Effective Date: 28-Feb-2023
• Revised: ISO 15589-2:2012 - Petroleum, petrochemical and natural gas industries - Cathodic protection of pipeline transportation systems - Part 2: Offshore pipelines
• Effective Date: 20-Jun-2008

Standards Content (Sample)

INTERNATIONAL ISO
STANDARD 15589-2
First edition
2004-05-01
Petroleum and natural gas industries —
Cathodic protection of pipeline
transportation systems —
Part 2:
Offshore pipelines
Industries du pétrole et du gaz naturel — Protection cathodique des
systèmes de transport par conduites —
Partie 2: Conduites en mer
Reference number
©
ISO 2004
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ii © ISO 2004 – All rights reserved

Contents Page
Foreword. v
Introduction . vi
1 Scope. 1
2 Normative references . 1
3 Terms and definitions. 2
4 Symbols and abbreviated terms. 3
5 CP system requirements. 3
5.1 General. 3
5.2 Selection of CP systems . 4
6 Design parameters. 6
6.1 General. 6
6.2 Protection potentials . 7
6.3 Design life . 9
6.4 Design current densities . 9
6.5 Coating breakdown factors. 11
7 Galvanic anodes. 12
7.1 Design of system . 12
7.2 Selection of anode material . 13
7.3 Electrochemical properties. 13
7.4 Anode shape and utilization factor . 13
7.5 Special mechanical and electrical considerations . 13
8 Anode manufacturing . 14
8.1 Pre-production test . 14
8.2 Coating. 15
8.3 Anode core materials. 15
8.4 Aluminium anode materials . 15
8.5 Zinc anode materials . 16
9 Galvanic anode quality control. 16
9.1 General. 16
9.2 Steel anode cores . 16
9.3 Chemical analysis of anode alloy. 17
9.4 Anode mass. 17
9.5 Anode dimensions and straightness . 17
9.6 Anode core dimensions and position. 18
9.7 Anode surface irregularities . 18
9.8 Cracks . 18
9.9 Internal defects, destructive testing . 19
9.10 Electrochemical quality control testing. 20
10 Galvanic anode installation. 21
11 Impressed-current CP systems . 22
11.1 Current sources and control. 22
11.2 Impressed-current anode materials . 22
11.3 System design. 22
11.4 Manufacturing and installation considerations . 23
11.5 Mechanical and electrical considerations.23

12 Documentation .24
12.1 Design, manufacturing and installation documentation.24
12.2 Commissioning procedures.25
12.3 Operating and maintenance manual .25
13 Operation, monitoring and maintenance of CP systems .26
13.1 General .26
13.2 Monitoring plans.26
13.3 Repair .26
Annex A (normative) Galvanic anode CP design procedures .27
Annex B (normative) Performance testing of galvanic anode materials .35
Annex C (normative) Monitoring of CP systems for offshore pipelines .37
Annex D (informative) Laboratory testing of galvanic anodes for quality control.43
Annex E (informative) Interference .45
Annex F (informative) Pipeline design for CP.48
Bibliography.54

iv © ISO 2004 – All rights reserved

Foreword
ISO (the International Organization for Standardization) is a worldwide federation of national standards bodies
(ISO member bodies). The work of preparing International Standards is normally carried out through ISO
technical committees. Each member body interested in a subject for which a technical committee has been
established has the right to be represented on that committee. International organizations, governmental and
non-governmental, in liaison with ISO, also take part in the work. ISO collaborates closely with the
International Electrotechnical Commission (IEC) on all matters of electrotechnical standardization.
International Standards are drafted in accordance with the rules given in the ISO/IEC Directives, Part 2.
The main task of technical committees is to prepare International Standards. Draft International Standards
adopted by the technical committees are circulated to the member bodies for voting. Publication as an
International Standard requires approval by at least 75 % of the member bodies casting a vote.
Attention is drawn to the possibility that some of the elements of this document may be the subject of patent
rights. ISO shall not be held responsible for identifying any or all such patent rights.
ISO 15589-2 was prepared by Technical Committee ISO/TC 67, Materials, equipment and offshore structures
for petroleum, petrochemical and natural gas industries, Subcommittee SC 2, Pipeline transportation systems.
ISO 15589 consists of the following parts, under the general title Petroleum and natural gas industries —
Cathodic protection of pipeline transportation systems:
— Part 1: On-land pipelines
— Part 2: Offshore pipelines
Introduction
Pipeline cathodic protection is achieved by the supply of sufficient direct current to the external pipe surface,
so that the steel-to-electrolyte potential is lowered to values at which external corrosion is reduced to an
insignificant rate.
Cathodic protection is normally used in combination with a suitable protective coating system to protect the
external surfaces of steel pipelines from corrosion.
External corrosion control in general is covered by ISO 13623.
Users of this part of ISO 15589 should be aware that further or differing requirements may be needed for
individual applications. This part of ISO 15589 is not intended to inhibit alternative equipment or engineering
solutions to be used for the individual application. This may be particularly applicable where there is innovative
or developing technology. Where an alternative is offered, any variations from this part of ISO 15589 should
be identified.
Deviations from this part of ISO 15589 may be warranted in specific situations, provided it is demonstrated
that the objectives expressed in this part of ISO 15589 have been achieved.

vi © ISO 2004 – All rights reserved

INTERNATIONAL STANDARD ISO 15589-2:2004(E)

Petroleum and natural gas industries — Cathodic protection of
pipeline transportation systems —
Part 2:
Offshore pipelines
1 Scope
This part of ISO 15589 specifies requirements and gives recommendations for the pre-installation surveys,
design, materials, equipment, fabrication, installation, commissioning, operation, inspection and maintenance
of cathodic protection systems for offshore pipelines for the petroleum and natural gas industries as defined in
ISO 13623.
This part of ISO 15589 is applicable to carbon and stainless steel pipelines in offshore service.
This part of ISO 15589 is applicable to retrofits, modifications and repairs made to existing pipeline systems.
This part of ISO 15589 is applicable to all types of seawater and seabed environments encountered in
submerged conditions and on risers up to mean water level.
NOTE Special conditions sometimes exist where cathodic protection is ineffective or only partially effective. Such
conditions can include elevated temperatures, disbonded coatings, thermal insulating coatings, shielding, bacterial attack,
and unusual contaminants in the electrolyte.
2 Normative references
The following referenced documents are indispensable for the application of this document. For dated
references, only the edition cited applies. For undated references, the latest edition of the referenced
document (including any amendments) applies.
ISO 1461, Hot dip galvanized coatings on fabricated iron and steel articles — Specifications and test methods
ISO 8044, Corrosion of metals and alloys — Basic terms and definitions
ISO 8501-1, Preparation of steel substrates before application of paints and related products — Visual
assessment of surface cleanliness — Part 1: Rust grades and preparation grades of uncoated steel
substrates and of steel substrates after overall removal of previous coatings
ISO 10474:1991, Steel and steel products — Inspection documents
ISO 13623, Petroleum and natural gas industries — Pipeline transportation systems
ISO 15589-1, Petroleum and natural gas industries — Cathodic protection of pipeline transportation systems —
Part 1: On-land pipelines
1)
ASTM D 1141 , Standard practice for the preparation of substitute ocean water

1) American Society for Testing and Materials, 100 Barr Harbour Drive, West Conshohocken, PA 19428-2959, USA.
2)
AWS D1.1/D1.1M , Structural Welding Code — Steel
3)
EN 287-1 , Approval testing of welders — Fusion welding — Part 1: Steels
EN 288-1, Specification and qualification of welding procedures for metallic materials — Part 1: General rules
for fusion welding
3 Terms and definitions
For the purposes of this document, the terms and definitions given in ISO 8044 and the following apply.
3.1
anode potential
anode-to-electrolyte potential
3.2
closed-circuit anode potential
anode potential while electrically linked to the pipeline to be protected
3.3
coating breakdown factor
f
c
ratio of current density required to polarize a coated steel surface as compared to a bare steel surface
3.4
cold shut
horizontal surface discontinuity caused by solidification of the meniscus of the partially cast anodes as a result
of interrupted flow of the casting stream
3.5
electric field gradient
change in electrical potential per unit distance through a conductive medium, arising from the flow of electric
current
3.6
electrochemical capacity
ε
total amount of electricity that is produced when a fixed mass (usually 1 kg) of anode material is consumed
electrochemically
NOTE It is expressed in ampere hours.
3.7
final current density
estimated current density at the end of the lifetime of the pipeline
3.8
IR drop
voltage, due to any current, developed between two points in the metallic path or in the lateral gradient in an
electrolyte such as seawater or seabed, measured between a reference electrode and the metal of the pipe, in
accordance with Ohm’s Law
cf. electric field gradient (3.5)

2) The American Welding Society, 550 NW Le Jeune Road, Miami, FL 33126, USA.
3) The European Committee for Standardization, Management Centre, Rue de Stassart, B-1050, Brussels, Belgium.
2 © ISO 2004 – All rights reserved

3.9
mean current density
estimated average cathodic current density for the entire lifetime of the pipeline
NOTE It is expressed in amperes per square metre.
3.10
protection potential
structure-to-electrolyte potential for which the metal corrosion rate is insignificant
3.11
remotely operated vehicle
ROV
underwater vehicle operated remotely from a surface vessel or installation
[ISO 14723]
3.12
riser
that part of an offshore pipeline, including any subsea spool pieces, which extends from the seabed to the
pipeline termination point on an offshore installation
[ISO 13623]
3.13
utilization factor
u
fraction of the anodic material that can be used in the cathodic protection process
4 Symbols and abbreviated terms
CE carbon equivalent
CP cathodic protection
N pitting resistance equivalent number
PRE
ROV remotely operated vehicle
SCE calomel reference electrode
σ specified minimum yield strength
SMY
5 CP system requirements
5.1 General
The main objectives and requirements of CP systems are to
 prevent external corrosion over the design life of the pipeline,
 provide sufficient current to the pipeline to be protected and distribute this current so that the selected
criteria for CP are effectively attained,
 provide a design life of the anode system commensurate with the required life of the protected pipeline, or
to provide for periodic rehabilitation of the anode system,
 provide adequate allowance for anticipated changes in current requirements with time,
 install anodes where the possibility of disturbance or damage is minimal,
 provide adequate monitoring facilities to test and evaluate the system performance.
Design, fabrication, installation, operation and maintenance of CP systems for offshore pipelines shall be
carried out by experienced and qualified personnel.
The CP system shall be designed with due regard to environmental conditions, neighbouring structures and
other activities.
Offshore pipelines that are protected by galvanic anode systems should be electrically isolated from other
pipelines and structures that are protected by impressed-current systems. Offshore pipelines shall be isolated
from other unprotected or less protected structures, which could drain current from the pipeline's CP system. If
isolation is not practical or stray current problems are suspected, electrical continuity should be ensured.
Care shall be taken to ensure that different CP systems of adjacent pipelines or structures are compatible and
that no excessive current drains from one system into an adjacent system.
The pipeline CP design shall take into account the pipeline installation method, the types of pipeline and riser
and the burial and stabilization methods proposed (see Annex F).
The CP system shall be designed for the lifetime of the installation using the calculation procedure given in
Annex A. In the design calculation, data given in Clause 6 of this part of ISO 15589 shall be used.
For areas with high water velocities and areas with erosion effects from entrained sand, silt, ice particles, etc.,
the design of the CP system needs special attention and additional design criteria shall be considered.
Installation of permanent test facilities should be considered taking into account specific parameters such as
pipeline length, water depth and underwater access related to the burial conditions.
For the cathodic protection of short lengths of submarine pipelines and their branches that are directly
connected to cathodically protected onshore pipelines, ISO 15589-1 shall be used.
5.2 Selection of CP systems
5.2.1 General
CP can be achieved using either galvanic anodes or an impressed-current system. Clause 6 covers the
design parameters to be used for both systems. An overview of these systems and items to be considered in
selecting the system to be used are covered in 5.2.2 to 5.2.5.
5.2.2 Distributed galvanic anode systems
Galvanic anodes are connected to the pipe, either individually or in groups. They are limited in current output
by the anode-to-pipe driving voltage and the electrolyte resistivity. Generally, anodes are attached directly to
the pipe as bracelets. Sleds of anodes can also be placed at regular intervals along the pipeline.
5.2.3 Galvanic anode systems installed at ends of pipeline
Shorter pipelines can be protected by anodes located at each end. Typically, this type of installation is used
on inter-platform pipelines. Anodes for the pipeline can be attached to the platform if the pipeline is electrically
connected to the platform.
5.2.4 Impressed-current anode systems
Impressed-current anodes can be of materials such as graphite, high-silicon cast iron, lead-silver alloy,
precious metals or steel. They are connected with an insulated cable, either individually or in groups, to the
positive terminal of a direct-current source, such as a rectifier or generator. The pipeline is connected to the
negative terminal of the direct-current source.
4 © ISO 2004 – All rights reserved

5.2.5 System selection considerations
Selection of the CP system shall be based on the following considerations:
 impressed-current system can protect a length of pipeline, depending on
 practical limitations on the locations for impressed-current anode and rectifier installations, e.g. at
either one or both ends of the pipeline, such as at landfalls and platforms,
 insulation resistance of the coated pipeline to the surrounding electrolyte at end of design life,
 longitudinal resistance of the pipeline;
 impressed-current systems can be more practical in high resistivity waters (e.g. large estuaries and
brackish water bays);
 lack of a source of external power can preclude the use of impressed-current systems;
 galvanic anode systems require minimal control and maintenance during the service life of the pipeline,
whereas impressed-current systems require regular control and maintenance;
 galvanic anode systems seldom cause serious interference problems on foreign neighbouring structures,
whereas impressed-current systems can have a significant effect;
 magnitude of the protective current required;
 existence of any stray currents causing significant potential fluctuations between pipeline and earth that
can preclude use of galvanic anodes;
 effects of any CP interference currents on adjacent structures that might limit the use of impressed-
current CP systems;
 limitations on the space available, due to the proximity of foreign structures, and related construction and
maintenance concerns;
 future development of the area and any anticipated future extensions to the pipeline system;
 cost of installation, operation and maintenance;
 reliability of the overall system;
 galvanic anode systems have shown reliable performance for long-term protection;
 impressed-current systems located offshore are capable of providing long-term protection but are less
tolerant to design, installation and maintenance shortcomings than galvanic anode systems. Good service
can be expected if proper attention is paid to mechanical strength, connections, cable protection
(particularly in the wave or splash zone), choice of anode type and integrity of power source. Adequate
system monitoring should be provided;
 impressed-current systems may be preferred on short pipelines which terminate at platforms that have
impressed-current systems installed;
 impressed-current systems may be preferred as a retrofit system on pipelines with galvanic anode
failures, excessive anode consumption, operation beyond original design life or excessive coating
deterioration;
 impressed-current systems may be preferred on short pipelines where an impressed-current system is
operated from shore;
 impressed-current systems can cause detrimental effects on the integrity of other pipelines and/or
structures existing in the same area unless proper measures are taken to prevent these effects.
6 Design parameters
6.1 General
The design of a pipeline CP system shall be based on
 detailed information on the pipeline to be protected, including material, length, wall thickness, outside
diameter, pipe-laying procedures, route, laying conditions on the sea bottom, temperature profile
(operating and shut in) along its whole length, type and thickness of corrosion-protective coating(s) for
pipes and fittings, presence, type and thickness of thermal insulation, mechanical protection and/or
weight coating,
 environmental conditions, such as seawater composition, temperature and resistivity, at the seabed along
the whole length of the pipeline,
 burial status (extent of backfilling after trenching or natural burial) and soil resistivity,
 the design life of the system,
 information on existing pipelines in close proximity to or crossing the new pipeline, including location,
ownership and corrosion-control practices,
 information on existing CP systems (platforms, landfalls, etc.) and electrical pipeline isolation,
 availability of electrical power, electrical isolating devices, electrical bonds,
 applicable local legislation,
 construction dates, start-up date (required for hot lines),
 pipe, fittings, J-tubes, risers, clamps and other appurtenances, and
 performance data on CP systems in the same environment.
At water depths greater than 500 m and sometimes at shallower depths, seawater characteristics (dissolved
oxygen, salinity, pH, sea currents, and fouling) can vary significantly from shallower depths and affect cathodic
polarization and calcareous deposit formation. For these situations, the required information shall be obtained
from field surveys, corrosion test data or a review of operating experience, including the following:
 protective current requirements to meet applicable criteria;
 electrical resistivity of the electrolyte, including seasonal changes if relevant;
 pipe burial depth (if buried) and identification of exposed span lengths and locations;
 water temperature at the seabed;
 oxygen concentration at the seabed;
 water flowrate at the seabed, including seasonal changes if relevant;
 seabed topography.
When reviewing operating experience, the following additional data should be considered:
 electrical continuity;
 electrical isolation;
 external coating integrity;
6 © ISO 2004 – All rights reserved

 deviation from specifications;
 maintenance and operating data.
Design procedures for the CP systems shall be in accordance with Annex A.
6.2 Protection potentials
6.2.1 Introduction
The potential criteria and other measurements and observations that indicate whether adequate CP of a
pipeline is being achieved are listed in 6.2.2. The effectiveness of CP or other external corrosion control
measures can be confirmed by direct measurement of the pipeline potential. However, visual observations of
progressive coating deterioration and/or corrosion, for example, are indicators of possible inadequate
protection. Physical measurements of a loss of pipe wall thickness, using divers, or using internal inspection
devices such as intelligent pigs, can also indicate deficiencies in the level of corrosion protection.
6.2.2 Potential criteria
To ensure adequate CP of a pipeline is being achieved, the measured potential shall be in accordance with
Table 1.
Table 1 — Recommended potential criteria
a
Material Minimum negative potential
Maximum negative potential
V
V
Carbon steel
b
Aerobic environment − 0,80 − 1,10
b
Anaerobic environment − 0,90 − 1,10
Austenitic stainless steel
c d
N W 40 − 0,30 − 1,10
PRE
c d
N < 40 − 0,50 − 1,10
PRE
d e
Duplex stainless steel − 0,50
d e
Martensitic stainless − 0,50
(13 % Cr) steel
The potentials given in Table 1 apply to saline mud and normal seawater compositions (salinity 3,2 % to
3,8 %).
The potentials are referenced to an SCE reference electrode, which are equivalent to a silver/silver
chloride reference electrode (Ag/AgCl/seawater) in 30 Ω⋅cm seawater.
a
These negative limits also ensure negligible impact of CP on pipeline coatings.
b
Where pipeline systems are fabricated from high strength steel (σ > 550 MPa), the most negative potential
SMY
that can be tolerated without causing hydrogen embrittlement shall be ascertained.
c
N = %Cr + 3,3 %(Mo+0,5W) + 16 %N.
PRE
d
For stainless steels, the minimum negative potentials apply for aerobic and anaerobic conditions.
e
Depending on strength, specific metallurgical condition and stress level encountered in service, these alloys can
be susceptible to hydrogen embrittlement and cracking. If a risk of hydrogen embrittlement exists, then potentials more
negative than −0,8 V should be avoided.

6.2.3 Thermally sprayed aluminium
For a structure with thermally sprayed aluminium which is cathodically protected at potentials more negative
than − 1,15 V, the thermally sprayed aluminium can suffer corrosion as a consequence of the build-up of alkali
at the metal/electrolyte interface. A polarized potential more negative than − 1,15 V should not be used unless
previous test results or operating experience indicate that no significant corrosion will occur.
6.2.4 Other factors
The potential of the Ag/AgCl/seawater reference electrode is dependent upon the concentration of chloride
ions in the electrolyte, and hence by the seawater resistivity. If the chloride concentration and hence the
resistivity is known to differ significantly from that of ordinary seawater (typically 3,5 % and 30 Ω⋅cm,
respectively), the protection potential criteria shall be adjusted in accordance with Figure 1.

Figure 1 — Nomogram for the correction of potential readings made with the Ag/AgCl/seawater
electrode in waters of varying salinity and resistivity against the
[5]
SCE and Cu/CuSO reference electrodes
EXAMPLE If brackish water of 100 Ω⋅cm resistivity exists at the pipeline potential measurement site, the least
negative potential for effective corrosion protection electrode will be − 0,84 V and not − 0,80 V as given in Table 1, with
reference to the Ag/AgCl/seawater reference electrode.
Alternative reference electrodes for specific conditions are given in C.4.2.
8 © ISO 2004 – All rights reserved

6.3 Design life
The design life of the pipeline CP system shall cover the period from installation to the end of pipeline
operation.
6.4 Design current densities
The design current densities depend upon the seawater temperature, oxygen content, the seawater velocity
and the ability to build up protective calcareous films on bare metal surfaces. For most applications in water
depth of less than 500 m, the design current densities are dependent only on the seawater temperature, and
the current densities for non-buried pipeline can be assessed from Figure 2.

Key
X seawater temperature, °C
Y current density, mA/m
NOTE The lower curve was published in [2]. This curve is based on test and field data from many platform and
pipeline locations world-wide, collected over a number of years. The upper curve is a conservative curve fit of the data
published in [3] and [4].
Figure 2 — Mean current density for non-buried pipeline
In Figure 2, the lower current-density curve may be used where there are no significant changes in oxygen
content from surface to seabed, no problems building up protective calcareous films, and low to moderate
seabed currents (up to 2 knots). The upper curve represents the highest current density values reported,
which are required where oxygen content, calcareous films and seabed currents have to be considered.
If no other data are known, the upper curve in Figure 2 should be used.
NOTE 1 The required current density values for a given field lie somewhere between these two extremes.
NOTE 2 In theory, three values of current density are significant: the initial, mean and final current densities, which
refer to the current density required to polarize the pipeline within a reasonable period of time (i.e. 1 to 2 months, initial),
the current density necessary to maintain the polarization (mean), and the current density necessary for an eventual
repolarization which may occur close to the end of the pipeline life (final), e.g. after a heavy storm. For a coated pipeline,
the initial current density is never the critical constraint in the design, so it is not considered further in Annex A. Pipelines
are located on the seabed and depolarization in storms has not been found to have a significant effect, so the same
current density value may be used for the mean and final current densities. If it is decided for a specific location that a
higher final current density needs to be considered in the design because of storms, a value which is 60 mA/m above the
mean value for that temperature may be used.
If the seawater temperature profile along the pipeline route is not known, the required current density shall be
based upon the minimum seabed temperature measured, which will usually be the temperature at the deepest
location along the pipeline route.
If the seawater temperature profile along the pipeline route is known, the curves in Figure 2 should be used
with the averaged pipeline section temperatures to obtain current densities for each section. It can be
necessary to subdivide the pipeline, based on the local annual average seawater conditions. If the annual
average seawater temperature varies by more than 5 °C over the pipeline length, the pipeline length should
be split up into separate sections that cover no more than 5 °C interval each. The averaged temperature
should be used for each section.
Current densities can alternatively be based on field measurements or data from facilities installed in the same
general geographical location.
Although the curves in Figure 2 cover the majority of worldwide locations, there are specific locations where
higher and lower current densities have been reported, where there are significant changes in oxygen content
with depth, and/or significant seabed currents, and/or the pipeline depth is greater than 500 m water depth
(see Table 2).
Table 2 — Design current densities for extreme conditions
Location Water depth Seawater Maintenance Comment
temperature current density
m °C mA/m
US West Coast up to 500 10 to 12 90 moderate current flow
Cook Inlet all depths 2 380 high seabed currents
Australia up to 500 12 to18 90 large seasonal temperature
variation
Norwegian Sea up to 1 500 300 cold deep conditions, probably
−1 to 4
in line with extrapolation of
Figure 2 curves.
NOTE 4 Calcareous deposits, formed on the exposed surfaces of the pipeline by the application of CP current, reduce
the current density required to maintain protective potentials and also improve current distribution. Pipeline coatings also
favour the formation of a dense calcareous deposit, because the initial current density is rather high when defects are
formed in the coating. However, the solubility of potential film-forming calcareous deposits is dependent on temperature,
and colder waters might not allow the formation of protective calcareous deposits, or could require higher initial current
density to achieve polarization.
For risers in the splash zone, current densities selected shall be 10 mA/m higher than for the equivalent riser
or pipeline below the splash zone (at the same temperature).
NOTE 5 Splash zone depths vary by location, for example in the North Sea splash zones typically extend down to
−10 m, whereas in the South China Sea the splash zone typically extends down to −1 m.
10 © ISO 2004 – All rights reserved

For pipelines fully buried in sediments or artificially covered (e.g. rock dumping), a design current density
(mean and final) of 20 mA/m shall be used, irrespective of seawater temperature or depth.
Pipelines operating with elevated temperatures (in excess of 50 °C) on the outside surface of the pipe require
an adjustment to the design current density. Increasing water temperature decreases oxygen solubility.
Increasing temperatures also accelerate the corrosion rate. The design current densities shall be increased by
1 mA/m for each degree Celsius of the metal/environment above 50 °C. Elevated temperatures can also
reduce both anode and coating performances. For external pipe surface temperatures above 80 °C, a special
assessment of current densities should be carried out.
The design current densities discussed above are also applicable for CP of all types of bare stainless steel
(austenitic, martensitic and duplex).
If subsea facilities are included on the design of the pipeline CP system, the current drain to subsea structures,
wellheads, manifolds and well casing shall be included. An allowance should be included in the total design
current density requirements to compensate for the current load imposed by the well casings below the
mudline. Values typically range from 1,5 A to 5 A per well.
6.5 Coating breakdown factors
The current demand of a coated pipeline increases with time as the coating deteriorates. Enough cathodic
protection capacity should be provided to maintain protection as the coating deteriorates. This leads to the
concept of coating breakdown factors as defined in 3.3 and used in Annex A.
The mean coating breakdown factor f is given by Equation (1):
c
f =+ff0,5∆×t (1)
( )
ci dl
The final coating breakdown factor f is given by Equation (2):
f
f =+ff∆×t (2)
( )
fi dl
where
f is the initial coating breakdown factor at start of pipeline operation;
i
∆f is the average yearly increase in the coating breakdown factor;
t is the design life, expressed in years.
dl
Typical parameters in the calculation of coating breakdown factors ( f and ∆f ) are given in Table 3. These
i
shall be applied to calculate the bare metal surface areas of the coated pipe during and at end of the design
life, respectively (see Annex A).
NOTE In Table 3, “Thermal insulation systems” are defined as those coating systems that include, in addition to a
corrosion protective coating, a layer whose specific purpose is to provide thermal insulation as opposed to corrosion
protection, whose overall system thickness is more than 3 mm and is intended to perform as a thermal insulation barrier.
The coating breakdown factors are based on coating quality being in accordance with commonly applied
industry standards. The coating breakdown factors do not include any allowance for excessive damage to
pipeline coatings during fabrication or installation or for field joints intentionally left uncoated, or third-party
damage in service (e.g. anchors, trawl gear). If such conditions are anticipated, either the affected surface
area shall be estimated and included in design calculations as bare metal surface ( f = 1) or the coating
f
breakdown factors in Table 3 shall be increased.
The design coating breakdown factors listed in Table 3 are based on field joints having a quality equivalent to
the factory-applied coatings.
Table 3 — Coating breakdown factors for corrosion and thermal insulation coatings
Factor f
Coating type ∆f
i
Asphalt/coal tar enamel + concrete 0,010 0,000 5
Fusion-bonded epoxy (FBE) + concrete 0,010 0,000 5
Fusion-bonded epoxy 0,020 0,001 0
Elastomeric materials (polychloroprene or 0,005 0,000 2
equivalent)
Multilayer (incl. FBE primer) polyethylene 0,005 0,000 2
(PE) and polypropylene (PP) anti-corrosion
Multilayer (incl. FBE primer) PE/PP anti- 0,002 0,000 1
corrosion + concrete
Thermal insulation systems (fully bonded) 0,002 0,000 1
The coating breakdown factors given refer to both pipelines exposed to seawater and
pipelines buried in the seabed.

7 Galvanic anodes
7.1 Design of system
The galvanic anode system shall be designed by locating properly shaped and sized anodes along the
pipeline such that sufficient current is delivered to the pipeline to maintain the required potentials throughout
the design life.
NOTE 1 Normally the CP system consists of bracelet anodes distributed at regular intervals along the pipeline.
Design calculations for the CP systems shall demonstrate that the anodes give current to the pipeline
necessary to meet the current density requirements. The anodes shall deliver sufficient current to meet the
mean and final design current densities.
If sled anodes are used, alternative methods for distribution and connection to the pipeline should be
considered.
The spacing between anodes shall be determined once the number of anodes has been calculated. The
anode spacing shall be close enough to maintain an adequate protection in the event of mechanical or
electrical loss of a single anode. Anode spacing exceeding 300 m shall be justified by attenuation calculations
or other mathematical modelling.
For short pipelines, anodes may be installed at each end of the pipeline, if it can be demonstrated by
mathematical calculations and modelling that CP can be achieved. Attenuation calculations (see Annex A)
shall be carried out for these installations to determine whether it is feasible to protect the mid-point of the
pipeline using anodes located at the ends.
It can be desirable to place extra anodes on the portion of the pipeline that is nearest the
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