Offshore Pipeline Cathodic Protection Retrofit Strategies
by Jim Britton (2002)
NOTE: This paper was originally written in 2002. Mr. Britton has since written an updated version to address the changes in corrosion control technology for anode replacement that has taken place in the interim. This paper remains in the library for anyone interested in the historical progress of this technology, and namely Deepwater's role in it.
Many miles of offshore pipelines worldwide are reaching, or have exceeded, the original design life of their cathodic protection systems. Many of these pipelines will be required to function for another 10, 15 or even 20 years. This paper will describe some rational strategies for achieving the desired life extension of the external corrosion control systems at the minimum installed cost. Preliminary surveys, retrofit design methods, installation procedures and hardware, verification and routine post installation inspection methods will be discussed.
Information obtained during routine offshore pipeline CP inspections has shown that the CP design criteria used have historically been quite conservative. This is particularly true of pipelines with concrete weight coatings over corrosion coatings. The main reason for this conservatism appears to be in the assumed degradation of the pipeline coating system both initially and over time. The coatings have generally outperformed the design criteria meaning that the anodes have been able to maintain adequate CP levels for much longer than the original design life. A secondary factor appears to be a general overestimation of the current density required to achieve protection. This often results in effective life cycles of cathodic protection systems designed for 20 or 25 years reaching 35 or 40 years.
This is the rule, there are however exceptions. Problems have been found on pipelines that become electrically shorted to platforms, pipelines without weight coatings that have had anodes detached during the pipe lay process and pipelines fitted with aluminum anodes of poor quality that have failed to activate. So it could be dangerous to assume the condition of an ageing pipeline if no survey data exist.
Basic Anode Retrofit Strategies
There are three basic strategies that a pipeline owner may adopt, there are a number of theme variations, but in general they are:
The Conventional Approach - Conduct a detailed survey, analyze the data, plan and schedule the retrofit as needed, execute the retrofit, conduct periodic surveys to verify continued operation of the retrofitted system.
The Practical Approach - With this approach the owner would reason that the pipeline is already beyond it's original design life, the pipeline needs to remain in service for an extended period of time way beyond even the most conservative estimates of the original CP system’s life expectancy. In this case a retrofit will most probably be required at some point within the next 5 years. So he would adopt the approach of planning a minimal retrofit and at the same time gathering data to assess the condition of the pipeline cathodic protection after the retrofit has been completed.
Retrofit of Opportunity - It will become apparent that the majority of the cost of an offshore pipeline retrofit is installation, i.e. the cost of the diving vessel and Subsea services, it makes sense to consider planning retrofits in conjunction with other Subsea activity on the pipeline. These opportunities present themselves when, for example, a Subsea tie-in to an existing pipeline is made. Other similar opportunities exist during routine route inspection, subsea repairs or reburials, or even when a suitable spread is mobilized to the general area to complete other subsea projects. It is a simple matter to ensure that the necessary equipment is available to complete a spot retrofit.
Adopting this strategy, and following an installation procedure that includes monitoring of the anode sled output current as well as “as found” and “as left” pipeline potentials will provide invaluable information on the overall condition of the pipeline CP system in the general area of the retrofit location. These data can be used to eliminate the need for an expensive, detailed pipeline survey while still allowing a safe retrofit system to be engineered for the rest of the pipeline.
Types of Retrofit
As with any CP system, three basic options are available, impressed current (ICCP), sacrificial aluminum nodes or hybrid systems. The choice between these systems will be determined largely based on the following broad criteria. Isolation status of the pipeline – If the pipeline is electrically isolated at one or both ends, the application of ICCP will generally be more practical. Practicality of applying ICCP – There are several sub-criteria that will determine the viability of using impressed current as a possible fix, they are:
• Availability of suitable power (AC) supply
• Cost of access and maintenance
• Potential for stray current interference
The length of the pipeline – ICCP can only be deployed at the ends of an offshore pipeline if it starts or terminates at platform or on dry land. The distance that can be protected from an end current source will be limited by the linear resistance of the pipeline and the current required to protect it (coating condition). Generally speaking, ICCP offers no real advantage over sacrificial anodes when considering attenuation.
For short lines (generally less than 5 miles (8 Km.) in length), that run between two platforms or otherwise provide access to a cathodic protection source at either end, the answer may be simply to electrically connect (short) the pipeline to those CP sources at either end. Using attenuation models verified with one time mid point contact potential measurement will usually be sufficient to provide adequate retrofit capacity, at a very attractive price.
Long lines (greater than 10 miles (16 Km.) in length) will invariably require multiple anode sled installations along the pipeline route, the criteria governing the location and frequency of these sleds are discussed later.
Key Elements for Retrofit Projects
Pipeline Survey - There are several different survey options that vary from high  to low resolution and the selection of the most appropriate method will be determined by the type and accuracy of the data required. Table 1 (below) Compares the merits of the various pre-retrofit survey method options. Obviously the more that is known of the pipeline condition, the more optimization can be put into the retrofit design, this will generally result in a much lower cost installation.
|Survey Method||Cost||Data Types||Data Accuracy||Generally Applicability|
|3 Electrode ROV
(3-5K$ / Mile)
(1.8 – 3K$ /
|Close Interval Potential
& Current Density (EFG)
Depth of Burial
Temp. / Resistivity
GPS (As Built)
Visual / Sonar Imaging
|Use this for
pipelines that are
high profile, where
long life extension
is required and
generally on long
|2 Electrode ROV
75% - 80% of 3
|Close Interval Potential
GPS (As Built)
Visual / Sonar Imaging
|Usually used on
or for post
N.R. for buried
Survey (Shown Addendum #1)
35% - 45% of 3
Point Field Gradient
GPS (As Built)
|Good / V Good
Good / Fair
on un-buried lines.
Good for shallow
water and beach
for infield lines.
|Tow Fish Trailing
|Moderate 30% -
40% of 3
|Close Interval Potential||Poor||Not Recommended
in any application
Point Depth of Cover
|Data points are few
but reliable, used in
modeling or to
|End Point Riser
|Low – fixed
price not length
|End Point Riser Potential||Good||Gives same level of
as tow fish survey,
but gives no real
The cost of a typical pipeline retrofit in the Gulf of Mexico will be broken down as follows:
• Design: 2-5%
• Materials: 20-25%
• Installation 75-80%
Thus it follows that optimization of the installation should receive the most attention. This can be achieved by knowing the following things about the pipeline:
• CP System & Coating Condition – This determines the number of sled sites required.
• Depth of Cover – On a buried line this is critical to minimize or eliminate excavations.
• Pipeline Location (XY) – Time wasted locating the pipeline is expensive.
The key is to safely protect the pipeline with the minimum number of locations. Top level survey intelligence can be an enormous help in this endeavor, but the economics should be closely evaluated before reaching a decision to survey.
Design - When setting about designing a retrofit for an offshore pipeline, there are a number of key elements that drive the design approach. I am not going to go into great length about design criteria such as current density requirements etc. these are well appreciated by corrosion engineers in the field. But the following points of knowledge control the design:
• Coating Condition
• Pipe Wall Thickness
• Existing Anode Condition
• General Potential Levels on Pipeline
• Isolated or Shorted at End Points
• Extent of Burial
• Operating Temperature
• Water Depth
• Location of Other Pipelines / Tie-Ins etc.
Each of the pods was designed to supplement the current required for two wellhead / riser assemblies for 10 years design life. An ROV support vessel successfully deployed the pods, and the tie backs made with the ROV. A post-installation survey showed that potentials had been shifted negatively on all risers, indicating that the TSA was no longer the primary source of CP.
In our field experience it is possible to space anode retrofit sleds as far as 10-12000 feet and achieve adequate cathodic protection overlap Table 3 (below). Shows data obtained while retrofitting an offshore pipeline in the Gulf of Mexico, the installation sites 1 – 14 are approximately 12000 feet apart and were installed in number order over a seven day time period. The numbers clearly show overlap to each successive site. This on a pipeline reaching the end of its original CP design life but still maintaining cathodic protection levels in the potential range of (-) 0.880 V vs. Ag/AgCl sw. or more negative.
|Pre and Post are potentials measured on pipe before and after attachment of retrofit sled.
Shift is simply the change in potential.
Current is the sled current output in amps shortly after connection.
All potentials are (-) Volts vs. Ag/AgCl sw. Reference.
Installation Planning - Several key factors come into play when planning the installation of an offshore pipeline cathodic protection retrofit:
Installation Spread Requirement – This is the offshore support equipment required to complete the job. The equipment required will generally be determined by pipeline location, length, water depth and depth of burial. A pipeline that runs from on offshore facility to an onshore destination may require two completely different equipment spreads to complete the project. The locally available equipment will also drive the decision in many areas of the world.
In the Gulf of Mexico, North Sea and other major offshore areas there is a usually a wide range of equipment for hire. So if we decide to use a Remotely Operated Vehicle (ROV) spread only, do we need a Dynamically Positioned (DP) support vessel or a Four Point Anchor Vessel (FPV). DP can command a day rate double that of an equivalently sized and otherwise similarly equipped FPV. With an average anchor deploy / recover time of around 6-8 hours per location the DP can complete well over twice as many installations as the FPV under certain conditions, but the bottom time required at each location has to be relatively short with respect to anchor handling time .. these among several other considerations make for a complex analysis. The wrong call could cost somebody hundreds of thousands of dollars on even a modest sized retrofit program.
Hardware Requirements - When designing pipeline retrofit hardware, there are some key requirements over and above providing the correct design from a CP standpoint (which goes somewhat without saying). The equipment must provide the following, and will not look the same for every project:
1. Ease of safe handling offshore, correct lift points, know weight limits of installation equipment on site, etc.
2. Provide quick installation for Diver/ROV, minimize time on bottom.
3. Allow positive verification of performance upon installation, preferably by current output rather than potential measurement alone.
4. Be environmentally friendly, no net snag points, toxic materials of construction etc.
The hardware consists generally of three main elements:
1. Anode Sled(s) - Anode sleds may be galvanic or impressed current. Figure. 1 shows a typical galvanic mud sled designed to operate below the seabed. This sled has an anode weight of 1250 Net lb (568 Kg). of Al-Zn-In anodes. These sleds are generally deployed at a short distance from the pipeline (10 – 15 feet 3 to 4.5 m). Impressed current sleds will take several forms depending on location, but will generally have to be located a little further away from the pipeline to be fully effective.
Sacrificial anode sleds are usually equipped with a cable-shunt type current measuring facility (Figure. 2). This allows surface or subsea readout of anode sled current output. It is a good idea to provide some magnetic or sonar reflectors that will enable ease of relocation with low cost towed survey apparatus, they can also be useful for calibration of smart pigs.