Cathodic Protection in Deepwater

Paper No.

629CATHODIC PROTECTION DESIGN IN DEEP WATER

BE SAFE .... NOT SORRY!

Jim BrittonDeepwater Corrosion Services Inc.

6S30 North Eldridge Pkwy.Houston, TX 77041

ABSTRACT

Deepwater offkhore structures am now quite corumom however a deep water development project still &uims significantcapital investment on the part of the operator. Corrosion failure is not acceptable. This paper presents a eonunon sense approach tocathodic protection design on deep-water projects. Some practical tips for avoiding pitfhlls are presented as well as the role of ROV’Sin maintenance and monitoring of these stmctums.

Keywords: offshore, cathodic protection deep water, ROV, cathodic protection monitoring, subsea completions, subsea wellheads.

INTRODUCTION

Development of deep water oil and gas prospeets world-wide, has resulted in the emergence of many alternative sohemes andstructures designed to produce the oil and gas cost eflkctively. Early developments used large fixed jaoket structures such as the ShellCognac and BuUwinkle platlionns, which are located in water depths of 1000 feet and 1350 feet respectively in the Gulf of Mexico.A drilling moved to even greater depths, these fied stmctures were no longer eat effkctive and new structure designs emerged suchas Tension Leg Platforms (TLP’s), Floating Production Systems (ITS’s) and SPAR designs. AU of these structures have processfacilities located on the surthce above subsea wellheads. The completion of remote subsea wells connected by flowlines and controlumbilicals to a surface production fhcility is now common. This is a cost effective method to develop smaller reservoirs. Theseremote wells are often several miles from the production facility. It is not uncommon for several subsea wells to be connected to asubsea manifold stmcture, this is in turn connected by pipelines to a production or storage facility on the surface some distance away.These wells, manifold% flowlines, jumpers and umbilicals are the main focus of this paper.

ENVIRONMENTAL CONSIDERATIONS

Understand Deep Water

There are three major fhctors impacting cathodic protection (CP) design in deep water. It is important to understand thesefactors and how they work together to drive CP designs in this environment.

Water Temmrature. Temperature decreases with increasing water depth. Temperature has a direct atTect on the water resistivity. Bydkcting the volubility of nutrient salts, lower temperature changes the composition and morphology of calcareous deposits formed atthe cathode.

Water Resistivity. The resistivity of seawater increases with increasing water depth. This directly at%cta the anode to seawaterresistance, this increase in resistance decreases current output fim anodes of fixed geometry. Water resistivity is therefore a majorf@or in sizing anodes to meet desirable weight to current ratios.

CopyrightW 999 by NACE international. Requeatsfor permission to publish this manuscript in any form, in part or in whole must be made in writing to NACEInternational, Conferences Division, P.O. Box 218340, Houston, Texas 77218-8340. The material presented and the views expressed in thispaper are solely those of the author(s) and are not necessarily endorsed by the Aasoeiation. Printed in the U.S.A.Ivo Kalcic - Invoice INV-396732-NC2T0G, downloaded on 12/21/2010 9:24:46 AM - Single-user license only, copying and networking prohibited.

Calmreous Demosits. Deposits formed on the cathode surface as a result of electrochemical reactions associated with cathodicprotection. This phenomenon is the major factor in the success of seawater cathodic protection systems, the calcareous deposit actingas a barrier coating, has the affkct of dramatically reducing current density requirements for cathodic protection. Calcamous depositsform much slower in cold water, and in general are less dense than deposits formed in warmer waters. Less dense deposits require ahigher current density to maintain required cathodic polarization.

In summary, design of deep-water cathodic protection systems requires the basic design criteria modification thus;

1. Use higher initial (polarization) and maintenance current density values than would be used in shallow warm water.2. Use higher seawater resistivity values when computing anode resistance/current output.3. Use coatings to nxluce CP current requirements.

DESIGNING CP SYSTEMS

Basic Considerations

D&a Conservatively. If “conservative” is defined as “being within sensible limits”, then we must design deep water CPsystems very conservatively. The cost associated with deep-water oil & gas projects is measured in tens, or even hundreds of millionsof dollars. Costs associated with in-situ repairs quickly escalate into millions of dollars, thus corrosion fkilures are not an optiom CPsystems for these pieces of equipment have relative costs in the tens of thousands of dollars, CP is cheap use it wisely, get it right tittime, every time.

useCoatinfzs.As previously sta~ CP design in cold water presents the following challenge% mo~ catho&c protectioncurrent is required per unit are% standard anode geometry will make less current available. When designing, it quickly becomesobvious that covering up some surfkce area with coatings makes CP designs much more workable. In additiou coatings provideadditional benefits associated with in-situ visibility and corrosion protection during onshore fabrication.

Coating Efficiency. What is the appropriate CQating breakdown fhctor to use? This question has been debated amongcorrosion engineers for decades. Published guidelines vary in their advice on this subject one prominent code would consider somecoatings completely worthless idler 20 years [1]. The same guideline later provides a common sense statement “ @erator’sexperience of a specijic paint coating system may justt~ the use of less conservative coating breakdown factors than specified in thisakument.” Clearly conservative common sense must rule, for pipelines, it is common practice to assign a coating breakdown fmtorof 5% over the design life, for coatings on seawater immersed surfaces near bottom the writer would recommend increasin g thisnumbers to 10-15% initial damage and 20-25V0 over the design life. This will result in more anodes but remember. Be safe . . ... notsorry, you know it makes sense.

Qualitv Control. It is critical that anodes work as designed. Anodes which fail to activate, or which perform withsignificantly reduced galvanic efficiency could mean that a premature anode retrofit would be required. An anode retrofit is not out ofthe question but it will usually be very expensive. Quality anode performance can be guaranteed if the following basic rules areobserved

1. Write a clearly defined specification with special emphasis on electrochemical potential and efficiency testing. Anyserious deficiencies in chemical composition will be exposed in these tests. A helpful document has recently beennmised by a NACE T7-L technical committee [2].

2. Use an anode alloy with a proven track record. The A1-in-Zn-Si anode alloys are preferable because they have a morepredictable behavior in mud environments, have less environmental con- than Mercury @g) or Tin (Sri) activatedmaterials, are more efficient and lighter than zinc anodes and have the highest available open circuit potential of all theviable options.

3. Ensure that the anode specifications require that the testing be @onned at the minimum anticipated servicetemperature.

4. Specify an anode chemistry that will work in cold water, and cold saline mud. A suggested modification of an ambienttemperature chemical composition versus one intended for cold water is presented in Table 1. This will result in fewerrejects at the testing phase, and will reduce the risk of anodes not activating when installed.

5. Ex-pect what you In-sped. Use qualified third party inspectors to assure anode qudty.

SPECIAL CONSIDERATIONS FOR SUBSEA PRODUCTION EQUIPMENT

General Considerations

The mechanical complexity of a subsea wellhead assembly, or a subsea production manifold causes a number of unusualproblems for the cathodic protection designer. The wide array of specialized materials involved in the cmstmdion can result in

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unexpected compatibility issues for example, itis important to be aware of pitfalls and design the CP systems around them. Someproblems unusual to subsea production equipment are addressed in the following sections.

Electrical Continuity. Many of the aubsea structures currently being installed have hundreds of individual components andmany moving parts. A typical subsea wellhead tree is shown (Figure 1). The anodes for these devices arc typically welded to thesupport fkune(s). If all the pieces of the assembly are not electrically tia with a sutliciently low nsistance, to the frame, then theunbended component is free to corrode at whatever rate applies to that material in seawater. Some causes of discontinuity are:

1. Bolted joining of coated components. This often results in the f~ener and one of the two components being out ofcircuit with the cathodic protection system. This causes special problems if the fastener is made from a materialsubject to crevice corrosion.

2. Fluorocarbon (Xylan) coated fasteners that are used because of their predictable torque properties, and limitedatmospheric corrosion protectio~ are often left isolated because of the dielectric properties of the coating. Damageto the heads of bolts and nuts from wrenches leave the fmteners to corrode fkely.

3. Necessary articulated joints oflen results in discontinuities across the articulation mechanism.4. Mechanical connectors and stabbing posts that may appear to guarantee electrical contact can, and have left entire

sections of subsea assemblies discontinuous.

Continuity Testing. Most subsea development projects include a phase called System Integration Testing (SIT). All thevarious components of the system are stacked up or connected on dry land to simulate the completed otlkhore installation. This is aperfect opportunity to veri& electrical continuity throughout the assembly. Continuity is verified flum a common test point on thecomponent where the anodes are attached, to all other components that comprise the assembly. A standard muhimeter can be used tocheck the resistance, the author’s company recommends that a value of 0.3Q or less be verified (excluding test lead resistance). Thesame test points (F@re 2) are used as inspection points for life cycle monitoring of the system. Dkcontinuities (and there willusually be some), can be fixed onshore quite easily. An example of a typical discontinuity found during an inspection is shown inFigure 3.

Fixing!Continuity Problems. Some ways in which continuity problems arc addressed are:

1. Tack weld across bolted joints.2. Use stainless steel wire jumpers between components.3. Use star (serrated) washers under bolt heads.4. Remove coatings under bolt heads.5. Use conductive fastener coatings.6. Locate anodes on more components.

Material Imwmpatibilities. The wide array of materials and corrosion resistant alloys used on these projects can causeproblems. It is important to review all materials that will be exposed to cathodic protection for their susceptibility to hydrogendamage at the expected potential. Materials that shouJd be closely checked include some alloys of titani~ some stainless steels (400series for example) and 17-4 PH. Sometimes it is difficult to prevent components km receiving cathodic protection even though thematerial selection engineer may not have intended it.

Cathodic Shielding. Connectors used to make subsea pipeline connections are extremely intricate mechanical devices withtight, flood~ interior spaces comprising combinations of materials. It is important to remember that concentrated areas of uncoatedsteel (albeit stainless steel) in metallic compartments may be subject to cathodic shielding and may not receive enough current toprovide adequate cathodic protection. Care should be taken to ensure that these areas are provided with anodes tilde and outside thecompartment. Other areas potentially subject to shielding include components with mechanically attached dielectric buoyancymodules (syntactic foam), these can behave like ultra-thick disbonded coatings. Control pods oflen have control tubing manifoldsunder a protective steel cover. These areas must receive special attention from the cathodic protection designer.

Mud Buried Steel. The mud buried steel, pilings, well casings, mud mats anchors etc., have a surface area which is often anorder of magnitude greater than the steel surfhce in the water zone. In addition to the large ~ the surfaces are usually not coated.Even though these areas require significantly lower current densities the large area can amount to a disproportionately high anodeweight requirement and available anode attachment real estate is usually at a premium. Be sure that these areas are accounted forconservatively and consider the following points and design options when accounting for the mud buried area.

1. Use current attenuation models to calculate how fm it would be possible for an anode to “throw” current. Don’taccount for steel areas below this, because the corrosion rate will usually be minimal. The titers company


accounts for only the first 200 feet of pilings and well conductors below the seabed at a maintenance current densityof 20 rnAlm2(2 mA/ft?).

2. Consider the use of sealed thermal sprayed aluminum coatings (TSA) to reduce current requirement. In this case,the titer suggest using the same current density, still on the first 200 feeg but apply a coating factor of 15’7.bare.

3. Install attachments on the top of pilings which simplifi attachment of cables with an ROV. With this provision inplace it is relatively simple to install some seabed anode sleds at a remote location to provide the current to theseareas and p~vent drain from the close fitted anodes on the subsea equipment. This provision is recommended on allthese types of project.

4. Don’t forget that pilings have an inside too. The top section of pilings normally extend some distance above the pileguide, they are usually bare steel and thus represent a significant percentage of the seawater immersed bare steelarea. Don’t forget this! Cathodic protection current will be lost to the inside as well as the outsi& surfiwes of thesepilings. Coating of the upper sections of pilings is strongly recmnmend~ sealed TSA coatings will work very wellhere, they can be applied to both surfices.

ROV Comrxitibility. At extreme depths >1000 fee~ all work on the facilities will have to be performed by a RemotelyOperated Vehicle (ROV). These machines, while continually improving, are still machines with limited dexterity and a tether/umbilical. To keep the CP design ROV friendly, follow these simple steps:

1. Locate anodes in areas where they will not interfere with ROV operations, and avoid designs that introduce potentialw points for the tether.

2. When locating ROV test points, include a grab rail for the vehicle to hold while monitoring the point. This willreduce wear and tear on the ROV’S manipulators and on the monitoring equipment (Figure 2) shows a typical CPtest point on a tree, note the grab rail. An ROV stab type current density sensor is shown in Figure 4, note the grabrail.

3. For potential monitoring, provide clearly marked, bare steel test stab locations. The high quality coatings used onmany of these fdities do not allow stabb~ probes to easily penetrate. Attempting to establish a clean tip contactthrough a high quality marine epoxy paint could damage the subsea equipment and puts tremendous strain on theROV hydraulic systems.

4. When spec@ing CP probes or Current probes select a mount that will easily fit the ROV manipulator and whichwill require minimum interf’e to the ROV electronic and fiber optic systems. (Figure 5) pictures a recentlydeveloped self contained deep water CP probe designed for operation to 10,000 feet, while requiring no electricalinterface to the ROV. A standard tip contact CP probe, which requires surface interfiwing, is also shown (Figure 6).

SPEC!IAL CONSIDERATIONS FOR DEEP WATER PIPELINES

what’s special

Basic design criteria for deep-water pipelines and flowlines are not much different from shallow water systems, but there aremore risks associated with deep water. The following suggestions are offered to rninimk the risk of problems with these systems.Some of these suggestions would incidentally improve shallow water system diability also.

Anode Tarxxs. Most deepwater pipelines are not stabilized with concrete weight coatings, thus the bracelet anodesCQrmnonlyused me proud of the pipeline, this can result in anode detachment during the lay process due to snagging of the anode onthe pipe lay equipment. This problem has been described in a number of papers [3][4]. The use of cast polymethane tapers to anchorthe anode and provide a smooth diameter transition has proven to be a very effective remedy, the location of both anode halves canalso reduce the risk of snagging (be sure and figure that all the anodes will arrive on the seabed at the six o’ clock position), this is notas favorable as the tapers but may be the only workable solution if anodes have to be attached on the lay barge, these methods arediscussed in more detail [5].

PiN LaY Immection. The best opportunity to identify and repair problems exists at the installation stage. Technology isavailable which will veri@ that anodes are attached to the pipe and that the coating is not badly damaged befo~ the pipe hits theseabed [5]. In additiom the post lay inspection performed by all operators to check the location of the line, is a rarely used opportunityto veri~ that all’s well with the pipeline corrosion control systems. Speci@ that a CP probe be attached to the ROV during the postlay (as built) inspection run.


Introduction

Wkhout the ROV there would be no oil and gas development in water depths greater than 1500 feet. These underwaterrobots are complex machines without brains, we have to make it simple for them to do the work of corrosion technicians. The role ofROV’S in corrosion monitoring is fhrther discussed [6]. With subsea developments we do not have the luxury of running cables to thesurface, we therefore must use the ROV. ROV operable equipment is now available to @orm the following task:

Potential Surveys. A wide range of equipment is available for point and continuous potential surveys on the subseaequipment and the associated pipelines.

Current Den@ aud Anode Current Measurement. Historically this has been achieved using the electric field gradientmethod [7]. A newly developed fixed monitoring improvement allows a current density monitor or monitored anode to be deployedfor measurement with an ROV (Figure 4), by stabbing a self contained readout into the fixed contacts the voltage drop shunt cau beaccurately recorded. TMs system will provide important in-sire repeatable, steady state polarization data to be used in fhtmv CPdesign improvement.

CONCLUSIONS

Be safe .. .. not sorry! Pay close attention to the stmcture, it’s continuity, what it’s made of, it’s geometry and how it will beprotected over it’s life cycle. Be conservative in coating and CP designs, but make retrofit provisions by providing simple ROVattachment points. Ensure that only quality materials are used in the corrosion control system and last but not least .. .. Hire acorrosion engineer to review all the design specifications, coatings vs. materials vs. CP.

[1] Det No~ke Veritas (DnV) – Recommended Practice RP B401 – “Cathodic Protection Design” -1993[2] NACE International – TM0190-98 – “Impressed CurrentTest Method for Laboratory Testing of Aluminum Anodes”[3] CORROSION ’97 – Paper 470 – RH. Winters, A. Holk – “Cathodic Protection Retrofit of an Offshore Pipeline”[4] CORROSION ’93- Paper 527- I.J. Rippon et al. – “Shorting Pipeline and Jacket Cathodic Protection Systems”[5] Offshore Magazine April 1996 – J. Britton – “Protecting Pipeline Corrosion Control Systems During Pipe Lay”[6] Underwater Magazine – Fall 98 P. 47 – J. Britton – “An ROV interface for Corrosion Monitoring Equipment”

[n CORROSION ’92 – Paper 422 – J. Britton “Continuous Surveys of Cathodic Protection System Performance on BuriedPipelines in the Gulf of Mexico”

Element Typical Cold WaterIron (Fe) O.lo%max 0.007%maxZmc (Zn) 2.8 – 7.0% 4.75 – 5.75%

copper (Cu) 0.006V0max 0.005% maxSilicon (Si) 0.20??max 0.10% rnaxIridium (In) 0.01 – 0.03% 0.015– 0.025%

Cadmium(Cd) Not Specified 0.002%maxOthers(each) 0.02%max 0.02%max

Aluminum Remainder Remainder

Table 1 – Anode Chemistry for Cold Water


Figure 2. C.P. Test Pent on Upper Left Corner of Panel




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Cathodic Protection in Deepwater