Offshore Pipeline CP Retrofit Strategies
Jim Britton Deepwater Corrosion Services Inc. Houston, TX www.stoprust.com
ABSTRACT
Many miles of offshore pipelines worldwide are reaching, or have exceeded, the original design life of their cathodic protection 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 rational strategies for achieving the desired life extension of the external corrosion control systems at the minimum installed cost. Preliminary surveys, surveys, retrofit design methods, installation procedures and hardware, verification and routine post installation inspection methods will be discussed. Key Words:
Offshore Pipelines, CP Retrofits, Field Gradient Surveys, Attenuation Modeling,
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Introduction Information obtained during routine offshore pipeline CP inspections has shown that the CP design criteria used have historically historically been quite conservative. This is particularly true true of pipelines with concrete weight coatings over corrosion coatings. The main reason for 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 design life. A secondary factor appears to be a general overestimation overestimation of the current density density required to achieve protection. protection. This often results in effective life cycles of CP 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. activate. So it could be dangerous to to assume the condition of an ageing pipeline if no survey data exist. Basic 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, d ata, 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 life expectancy. In this case a retrofit retrofit will most most probably be required at some point within the next 5 years. So he would adopt the the approach of planning a minimal retrofit and at the same time gathering data to assess the Retrofit of Opportunity 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 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 retrofit location. These data can be used to eliminate the need for
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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 Anodes or Hybrid Systems. Systems. The choice between these systems 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 (a.c.) 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 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 RETROFIT PROJECT ELEMENTS
Survey There are several different survey options that vary from high [1] to low resolution and the selection of the most appropriate method will be determined by the type and accuracy of the data required.
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Table 1. 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. installation. The cost of a typical pipeline retrofit retrofit in the Gulf of Mexico will be broken down as follows: Design: Materials: Installation
2-5% 20-25% 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 safely protect the pipeline 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 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.
These and a number of other pieces of useful information are given in Table 2. This is a questionnaire provided by the writers company to owners/operators of candidate pipelines. The document is somewhat detailed but has been included in full to provide a useful tool to readers of this paper.
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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. Shows data obtained 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. Installation Planning Several key factors come into play when planning the installation installation of an offshore pipeline CP retrofit: Installation Spread Requirement – This is the offshore support equipment required to complete the job. job. The equipment required required will generally be determined by pipeline location, length, water depth and depth of burial. burial. A pipeline that runs runs from on offshore offshore facility to an onshore destination may require two completely different equipment spreads to complete the project. project. The locally available available equipment will 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) (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 similarly equipped FPV. With an average anchor deploy / recover time 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. 2. 3. 4.
Ease of safe handling offshore, correct lift points, know weight limits of installation equipment on site, etc. Provide quick installation for Diver/ROV, minimize time on bottom. Allow positive verification of performance upon installation, preferably by current output rather than potential measurement alone. Be environmentally friendly, no net snag points, toxic materials of construction etc.
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The hardware consists generally of three main elements: Anode Sled(s) Anode sleds may be galvanic or impressed current Fig. 1 shows a typical galvanic mud sled designed to operate below the the seabed. This sled has an anode weight of 1250 Net lb (568 Kg). of AlZnIn AlZnIn anodes. These sleds are generally generally deployed at a short distance distance from the pipeline (10 – 15 feet 3 to 4.5 M). Impressed current sleds will take take several forms depending on location, but will generally have to be located a little further away from the pipeline to be fully effective. effective. Sacrificial anode sleds are usually equipped with a cable-shunt type current measuring facility Fig. 2 This allows surface 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, app aratus, they can also be useful for calibration of smart pigs. Note that discreet anode sleds have a finite resistance, this can be seen in the typical attenuation predictive output shown Fig. 3. The large voltage drop at the sled sled location is caused by this resistance. resistance. This is not present when zero resistance end current sources or potentially controlled impressed current sources are used. Shorting a pipeline to a platform would represent a zero resistance resistance current source.
Interconnect Cables These are the cables that connect the anode to the pipeline, so they have to be designed to perform long term. Fortunately they are generally very corrosion resistant and being on the cathodic half of the circuit receive the benefit of full time time cathodic protection. It is sound practice to include a wire rope strain relief to eliminate the possibility of excess strain at the connection terminals. terminals. Dual redundant cables should always be provided as a minimum, cross sectional area will typically need to be in the 2/0 to 4/0 AWG range. Multi-strand locomotive style cable is preferred over stranded cond uctor constructions. Remember that the equipment is only 20% of the project cost, don’t cut corners that could compromise performance.
Attachment to Pipeline The pipeline attachment is possibly the most critical element, mechanical connections are the most cost effective, and also the speediest to install. install. A new design of attachment clamp that has been successfully used on a number of projects is shown in Fig. 4. The clamp has the benefit of installing over weight coatings, and without the need to fully excavate the pipeline, its “breakaway system” eliminates potential damage from snagging. These features alone can save save several hours of bottom bottom time per location, more more
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if the pipeline pipeline is deeply covered. The clamp has been successfully installed both both by divers and ROV. The constant torque features and material material selections ensure ensure the long term integrity of the electro-mechanical connection. Other attachment methods to be considered include friction welding, hyperbaeric or wet welding, but the circumstances would have to be unusual to justify the significant cost penalties associated with these methods. Installation The installation should proceed well if properly planned, a key element is to have a corrosion specialist available to make and interpret the various measurements taken at each location. In this way critical critical field adjustments adjustments can be made if the recorded data are not meeting or exceeding predicted levels. It is also key to have a qualified survey company on board to accurately spot the position of each retrofit site. This will be critical to long-term long-term re-survey re-survey strategy. strategy. Verification & Monitoring There are two phases of verification and monitoring; Short term and long term, in the short term it is important to verify the retrofitted retrofitted system performance. performance. This stage of monitoring comprises of the following basic measurement types: • •
Pre and post-installation pipeline potentials. Early polarization curves (sled current plotted against change in pipeline potential over a short period after grounding of the the anode sled).
These data, when evaluated on the pipeline as a whole, provide a wealth of “real” CP performance information that can be used to optimize asset life cycle inspection and mechanical integrity management costs. costs. It is these these life cycle inspection requirements requirements that make up the long term monitoring. monitoring. The data obtained during installation installation can now be put to use to plan periodic system operational verification. The large evenly distributed CP current sources are now the virtual “offshore test stations” that need simply be scanned with a low cost towed apparatus [2], to verify proper system function. This level of CP system performance verification, verification, is higher than that available on probably 90% plus of offshore pipelines. Deepwater pipelines are increasingly being protected by a few isolated sled current sources, this will eventually change the way in which offshore pipelines are monitored. It seems more than reasonable to suggest that certain aspects of this technology approach may be applicable to new pipelines in even moderate water depths. Pipeline monitoring is much harder to do on buried offshore pipelines, the larger signal strengths from the distributed sleds can be more easily detected and verified on buried pipelines, than those from small bracelets with low level field gradients.
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SUMMARY & CONCLUSIONS When considering an offshore pipeline retrofit remember the following key points to ensure the best result. 1) There are no two offshore pipelines pipelines that are the same in every aspect. Evaluate the options carefully before finalizing a retrofit strategy, understand where things can go wrong. 2) Don’t base a decision on bad or uncertain survey information. information. 3) Work with subsea subsea experts to determine most appropriate installation scenario for the pipeline. 4) Plan the retrofit retrofit to allow simple, low cost life life cycle monitoring. monitoring. 5) Work with other groups within within the company to make best use of all pipeline access opportunities, have anode sleds available to send offshore at short notice, always carry a tip contact type CP probe to get potential readings. 6) Never go offshore without a corrosion expert. I hope that this short paper has given the reader some food for thought. REFERENCES 1.
2.
NACE Corrosion 92 Paper No. 422 Britton J. N. “Continuous Surveys of Offshore Offshore Cathodic Protection Protection System Performance on Buried Pipelines in The Gulf of Mexico” “Offshore Pipeline Cathodic Protection Surveys – A Technology Update” Presented at New Orleans Orleans Section Meeting – October October 2001. Copy available from writer.
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Table 1. Survey Method
Cost
Data Types
Data Accuracy
3 Electrode ROV Deployed (Typical Equipment Spread)
Generally High (3-5K$ / Mile) (1.8 – 3K$ / Km)
Close Interval Potential & Current Density (EFG) Depth of Burial Temp. / Resistivity GPS (As Built) Visual / Sonar Imaging
Excellent Very Good Very Good Excellent Excellent Excellent
2 Electrode ROV Deployed (Typical Equipment Spread)
Fairly High 75% - 80% of 3 Electrode Cost
Close Interval Potential GPS (As Built) Visual / Sonar Imaging
Excellent Excellent Excellent
Lateral Towed Multi-Electrode Survey (Fig. 5 & 6)
Moderate 35% - 45% of 3 Electrode Cost
Point Potential Point Field Gradient GPS (As Built)
Good / V Good Good Good / Fair
Tow Fish Trailing Wire Surveys
Moderate 30% 40% of 3 Electrode Cost Depends on Number of Points
Close Interval Potential
Poor
Point Potentials Point Depth of Cover
Excellent Excellent
End Point Riser Potential
Good
Isolated Contact Measurements
End Point Riser Measurement
Low – fixed price not length dependent
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Generally Applicability Use this for pipelines that are high profile, where long life extension is required and generally on long ageing buried pipelines. Usually used on exposed pipelines or for post installation baseline surveys. N.R. for buried lines. Accuracy Improves on un-buried lines. Good for shallow water and beach approaches, also for infield lines. Not Recommended in any application Data points are few but reliable, used in conjunction with modeling or to calibrate lateral surveys. Gives same level of useful information as tow fish survey, but gives no real indication of pipeline condition.
Table 2.0 Pipeline Retrofit Questionnaire Offshore Facility Retrofit Design Sheet The information requested herein is required to allow an optimized retrofit solution. The more information that is provided then the more accurately the retrofit can be designed, where information is not available, assumptions can be made but a survey may be necessary to gather certain critical data. General Information Pipeline Location (Body of Water):
________________________________ __________________ ______________
Pipeline Diameter:
_______
Pipeline Origin (From):
_____________________________________ __________________ _________________________ ______
Pipeline Destination (To):
_____________________________________ __________________ _________________________ ______
Pipeline Service:
_____________________________________ __________________ _________________________ ______
Pipeline Type: _____________________________________ __________________ ___________________ (Conventional; Pipe-In-Pipe; Flexible; Flare Line; Line; Thermally Insulated; Bundled;) Year Installed:
________
Year to be Retired:
__________
Additional Notes: Physical Information (If Alignment Sheets are Available Please Send a Copy) Water Depth (Origin):
________
(Destination):
__________
Burial Data: ____________________________________ _________________ __________________________ _______ (Indicate whether pipeline was bottom laid or intentionally buried with depth of cover if known) Pipe Wall Thickness:
________
Pipe Material Grade:
__________
Subsea Tie-Ins / Valves: ____________________________________ _________________ __________________________ _______ (Indicate number and approximate down line distance from origin) Operating Temperature: Min:
________
Max:
___________
Riser Type (Origin): ________ (Destination): (Conventional; J-Tube; I-Tube; SCR; No Riser;)
___________
Corrosion Control Information (If Original CP Design Information is Available Please Send a Copy) Pipeline Coating Type / Thickness: Weight Coating Y/N: CP Details:
_______________________________ __________________ _____________
______ Thickness:
____________________ ____________________
Sacrificial / ICCP/ Both? __________________ _______________________________ _____________
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If ICCP Give Anode and Rectifier Details:
__________________________ __________________________ __________________________ _________________ _________ __________________________ _________________ _________
Bracelet Anode Details: Alloy:
________
Net Weight:
________
Spacing:
________
Insulator Details: Is Pipe Insulated at Origin Y/N: ________ Insulator Location Origin:
Destination Y/N:
________
_________
Destination:
_________
Survey / Inspection Data (If Inspection Reports are Available Please Forward Most Recent) Most Recent Drop Cell Survey Data: Minimum Riser Potential: Origin: ________ (Indicate least negative potential recorded)
Destination:
_________
If Insulated mV Across Insulator: Origin: ________ Destination: _________ (Indicate polarity as positive if pipe at less negative potential than pipe or negative if pipe more negative than platform) Has a Sub-Sea Survey Been Performed Y/N / Date?
____________________ _________________ ___
In-Line (Smart Pig) Inspection Y/N / Date? (If a copy report is available please submit)
____________________ _________________ ___
If Yes Please Provide the Following Information Regarding Available Data: (Check the data types and year that they were logged) Contact Potentials:
_____ _____ Continuous Potentials: _____ _____
Current Density:
_____ _____ Field Gradient (EFG):
Depth of Cover: _____ _____
Span Identification:
X-Y Locations: _____ _____ Visual Survey: Anode Depletion:
_____ _____
_____ _____ _____ _____
_____ _____
Wall Thk. Anom alies:
_____ _____
CP Survey Contractor: ___________________________________ ______________________________________ ___ Survey Type: ____________________________________ _________________ _____________________ __ (ROV; Diver; Tow-Fish, In-Line (Smart Pig)) Summary of Survey Results: Least Negative Potential:
__________
Avg. Anode Depletion %:
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______
Min / Max Depth of Cover:
_____ _____
Coating Damage Observed Y/N?:
Number Spans Found: ______
_____ Number of Locations:
______
Retrofit Requirements
Life Extension Required (Yr.)?
_______
Warranty Required Yr. _______ (Note: Extended Warranties or Leasing Require Survey Service Contract) Type of Service Required From DeepwaterBrandt: ________________________ (Turnkey Fixed Price; System Lease; Design Only; Design & Supply Material: Design Supply and Supervise). Remote Monitoring Required (Available with any System)? Submitted By:
Telephone:
Name:
_______
____________________________________ _________________ ____________________ _ Company:
_____________________________________
Date:
_____________________________________
__________________ e-mail: ___________________ _____________________ __
Table 3. Loc. No. 1 2 3 4 5 6 7 8 9 10 11 12 13 14
P re 0.880 0.933 0.941 0.990 0.937 0.914 0.931 0.938 0.931 0.955 0.990 0.968 0.968 0.970
P o st 1.016 1.027 1.011 1.026 1.006 0.987 0.995 1.000 0.999 0.998 1.026 0.990 0.990 0.997
S h i ft 0.136 0.094 0.070 0.036 0.069 0.073 0.064 0.062 0.068 0.043 0.036 0.022 0.022 0.027
Curre n t 4.050 N -R 3.340 2.350 0.420 3.830 3.050 2.840 2.410 1.210 1.980 0.710 1.000 1.700
Pre and Post are potentials measured on pipe before and an d 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.
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Figure 1. Typical Offshore Retrofit Sled – For Mud Burial
Figure 2. Wire Shunt Stab Point on Sled for Current Measurement
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Figure 3. Potential Attenuation Prediction Potential Attenuation Pipeline Segment Protected By Galvanic Sleds 1.10
w s l C g A / g A s v V ) ( l a i t n e t o P
1.05 1.00
12 3/4" Dia. 0.500" w/t Pipeline. 3% Coating Damage 2 mA/sqft Current Density
0.95 0.90 0.85 0.80 0.75 0.70 -500
500
1500
2500
3500
4500
Distance From Sled (Feet)
Figure 4. Quick-Fit Pipeline Pipeline Attachment Clamp
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5500
6500
7500
8500
Figure 5. Towed Lateral Survey Survey System (Snake) (Snake)
A-Frame or Stinger Stinger Ramp
Surface Buoys
Tugger Winch EFG Array
GPS
Data
Survey Boat C.I.W & Remote Pipe
Survey Snake
Figure 6. Lateral EFG EFG Survey Setup
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