Technical Paper

Cathodic protection design in deep water: Be safe, not sorry!

by Jim Britton (1999)

 Download this paper

Abstract

Offshore structures in deep water are now quite common. However, a deep water development project still requires significant capital investment on the part of the operator. Corrosion failure is not acceptable. This paper presents a common sense approach to cathodic protection design on deep water projects. Some practical tips for avoiding pitfalls are presented as well as an analysis of the role of ROV's in maintenance and monitoring of these assets.

Introduction

The worldwide development of deep water oil and gas prospects has resulted in the emergence of many alternative schemes and structures designed to produce oil and gas more cost effectively. Early developments used large fixed jacket structures such as the Shell Cognac and Bullwinkle platforms, which are located in water depths of 1000 feet and 1350 feet respectively in the Gulf of Mexico. As drilling moved to even greater depths, these fixed structures were no longer cost effective, and new structure designs emerged: Tension Leg Platforms (TLP's), Floating Production Systems (FPS's), SPAR designs. All of these structures have process facilities located on the surface, above subsea wellheads. The completion of remote subsea wells connected by flow lines and control umbilicals to a surface production facility is now the most common design, being a very cost effective method for developing smaller reservoirs. These remote wells are often several miles from the production facility, and it is not uncommon for several subsea wells to be connected to a single subsea manifold structure, which is in turn connected by pipeline to a production or storage facility on the surface. Cathodic protection (CP) for these wells, manifolds, flow lines, jumpers and umbilicals is the main focus of this paper. 

Environmental considerations

Understanding deep water - There are three major factors impacting cathodic protection design in deep water. It is important to understand these factors and how they work together to drive CP designs in this environment:

In summary, designing deep-water cathodic protection systems requires the following basic design criteria modification:

Cathodic protection design (basic considerations)

Design conservatively - If "conservative" is defined as "being within sensible limits," then we must design deep water cathodic protection systems very conservatively. The cost associated with deep-water oil and gas projects is measured in tens, or even hundreds of millions of dollars. Costs associated with in-situ repairs quickly escalate when there is a problem. For this reason, corrosion failures are not an option. Cathodic protection systems for these pieces of equipment have relative costs in the tens of thousands of dollars. Cathodic protection is relatively cheap; use it wisely. Try to get it right the first time.

Use coatings - As previously stated, cathodic protection design in cold water requires more cathodic protection current per unit area, and in cold water a standard anode geometry will make less current available. It quickly becomes obvious that covering up some surface area with coatings makes a CP design much more manageable. Coatings also provide additional benefits such as increased in-situ visibility, and corrosion protection during onshore fabrication and storage.

Coating efficiency - What is the appropriate coating breakdown-factor to use? This question has been debated among corrosion engineers for decades. Published guidelines vary in their advice on this subject. One prominent code considers some coatings completely worthless after 20 years [1]. The same guideline later provides this statement: "Operator's experience of a specific paint coating system may justify the use of less conservative coating breakdown factors than specified in this document." Clearly conservative common sense must rule. For pipelines, it is common practice to assign a coating breakdown factor of 5% over the design life. For coatings on seawater immersed surfaces near the bottom, we would recommend increasing this numbers to 10-15% initial damage and 20-25% over the design life. This will require more anodes, but remember: be safe, not sorry.

Quality control - It is critical that sacrificial anodes work as designed. Anodes which fail to activate, or which perform with significantly reduced galvanic efficiency could mean that an anode retrofit will be required prematurely. Deep water anode retrofit projects are not impossible, but they are usually very expensive. Anode performance can be guaranteed if the following quality control guidelines are observed:

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

 2. Use an anode alloy with a proven track record. The Al-In-Zn-Si anode alloys are preferable because their behavior in mud environments is more predictable, and because there are less environmental concerns than with Mercury (Hg) or Tin (Sn) activated materials. Aluminum (Al-In-Zn-Si) anodes are more efficient and lighter than zinc anodes and have the highest available open circuit potential.

3. Ensure that the anode specifications require that the testing be performed at the minimum anticipated service temperature.

Figure 1 - Typical subsea wellhead assembly

Figure 2 - Cathodic Protection Test Point on Upper Left Corer of Panel

Figure 3 - Typical electrical discontinuity across linkage mechanism

B. Continuity Testing - Most subsea development projects include a phase called System Integration Testing (SIT). All the various components of the system are stacked up or connected on dry land to simulate the completed offshore installation. This is a perfect opportunity to verify electrical continuity throughout the assembly. Continuity is verified from a common test point on the component where the anodes are attached to all other components that comprise the assembly. A standard multi meter can be used to check the resistance, we recommend that a value of 0.3 Ω or less be verified (excluding test lead resistance). The same test points (Figure 2) are used as inspection points for life cycle monitoring of the system. Discontinuities (and there will usually be some) can be fixed onshore quite easily. An example of a typical discontinuity found during an inspection is shown in Figure 3.

Fixing Continuity Problems - Some ways to address continuity problems are:

C. Material Incompatibilities - The wide array of materials and corrosion resistant alloys used on these projects can cause problems. It is important to review all materials that will be exposed to cathodic protection for their susceptibility to hydrogen damage at the expected potential. Materials that should be closely checked include: some alloys of titanium, some stainless steels (400 series for example) and 17-4 PH. Sometimes it is difficult to prevent components from receiving cathodic protection even though the material selection engineer may not have intended it.<

D. Cathodic Shielding - The connectors used to make subsea pipeline connections are extremely intricate mechanical devices with tight, flooded interior spaces comprising a large combination of materials. It is important to remember that concentrated areas of uncoated steel (albeit stainless steel) in metallic compartments may be subject to cathodic shielding and may not receive enough current to be adequately protected. Care should be taken to ensure that these areas are provided with anodes inside and outside the compartment. Other areas potentially subject to shielding include components with mechanically attached dielectric buoyancy modules (syntactic foam), these can behave like ultra-thick disbonded coatings. Control pods often have control tubing manifolds under a protective steel cover. These areas must receive special attention from the cathodic protection designer.

E. Mud buried steel - The mud buried steel (pilings, well casings, mud mats anchors etc.) has a surface area which is often an order of magnitude greater than the steel surface in the water zone. In addition to the large area, the surfaces are usually not coated. Even though these areas require significantly lower current densities, the large area can amount to a disproportionately high anode weight requirement, and available anode attachment real estate (areas at which to possibly connect anodes) is usually at a premium. Be sure that these areas are accounted for conservatively and consider the following points and design options when accounting for the mud buried area.

F. ROV compatibility - At extreme depths >1000 feet, all work on the facilities will have to be performed by a Remotely Operated Vehicle (ROV). These machines, while continually improving, are still machines with limited dexterity and a tether / umbilical. To keep the cathodic protection design ROV friendly, follow these simple steps:

Figure 4 - ROV stab on a current density sensor - grab rail on left

3. For potential monitoring, provide clearly marked, bare steel test stab locations. The high quality coatings used on many of these facilities do not allow stabbing probes to easily penetrate. Attempting to establish a clean tip contact through a high quality marine epoxy paint could damage the subsea equipment. It also puts tremendous strain on the ROV hydraulic systems.

4. When specifying cathodic protection probes or current probes, select a mount that will easily fit the ROV manipulator and which will require minimum interface to the ROV electronic and fiber optic systems. Figure 5 shows a recently developed self contained deep water CP probe designed for operation at up to 10,000 feet, while requiring no electrical interface to the ROV. A standard tip contact CP probe, which requires surface interfacing, is also shown (Figure 6).

Figure 5 - 10,000 feet rated self-contained CP probe (updated image)

Figure 6 - Standard dual element ROV CP probe (updated image)

Special considerations for deep water pipelines

Q: What is special about a deep water pipeline?

A: Basic design criteria for deep water pipelines and flowlines are not much different from shallow water systems, but there are more risks associated with a pipeline located in deep water. The following suggestions are offered to minimize the risk of problems with these cathodic protection systems. Some of these suggestions would incidentally improve shallow water system reliability also.

A. Anode tapers - Most deepwater pipelines are not stabilized with concrete weight coatings, thus the bracelet anodes commonly used are proud of the pipeline. As a result anodes sometimes detach during the lay process due to the anode snagging on the pipe lay equipment [3][4]. The use of cast polyurethane tapers to anchor the anode and provide a smooth diameter transition has proven to be a very effective remedy to this problem. Placing both anode halves a particular way can also reduce the risk of snagging. One want to be sure that all of the anodes will arrive on the seabed at the six o' clock position. This process is not as favorable as the tapers but may be the only workable solution if anodes have to be attached on the lay barge [5].

B. Pipe lay inspection - The best opportunity to identify and repair problems is always during the installation. Technology is available which will verify that anodes are attached to the pipe and that the coating is not badly damaged before the pipe hits the seabed [5]. In addition, the required post-lay inspection performed by all operators to check the location of the line is also a great opportunity to verify the pipeline's corrosion control system performance. Specify that a cathodic protection probe be attached to the ROV during the post lay (as-built) inspection run.

Cathodic protection testing and monitoring with ROVs

Introduction - Without the ROV there would be no oil and gas development in water depths greater than 1500 feet. These underwater robots are complex machines without brains. We have to make it simple for them to do the work of corrosion technicians [6]. With subsea developments we do not have the luxury of running cables to the surface. Therefore, we must use the ROV. Equipment made especially for ROV's is now available to perform the following tasks:

Electrical potential surveys - A wide range of equipment is available for point and continuous potential surveys on subsea equipment and the associated pipelines.

Current density and anode current measurement - Historically this has been achieved using the electric field gradient method [7]. A newly developed fixed monitoring instrument allows a current density monitor or monitored anode to be deployed for measurement with an ROV (Figure 4). By stabbing a self contained readout into the fixed contacts the voltage drop shunt can be accurately recorded.

Conclusions

When designing a CP system in deep water, be safe, not sorry! Pay close attention to the structure, its continuity, what it's made of, its geometry, and how it will be protected over its life cycle. Be conservative with coating and cathodic protection designs, but make retrofit provisions by providing simple ROV attachment points. Ensure that only quality materials are used in the corrosion control system. And last but not least, hire a corrosion engineer to review all the design specifications, coatings vs. materials vs. cathodic protection.

References

[1] Del Norske Veritas (DnV) - Recommended Practice RP 8401 - "Cathodic Protection Design" - 1993
[2] NACE International- TMOI90-98 - "Impressed Current Test Method for Laboratory Testing of Aluminum Anodes"
[3] CORROSION '97 - Paper 470 - R. H. Winters, A. Holk -"Cathodic Protection Retrofit of an Offshore Pipeline"
[4] CORROSION '93 - Paper 527 - LJ. Rippon et aI. - "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 ROY interface for Corrosion Monitoring Equipment"
[7] CORROSION '92 - Paper 422 - J. Britton "Continuous Surveys of Cathodic Protection System Performance on Buried Pipelines in the Gulf of Mexico"

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Cathodic Protection Design in Deep Water: Be Safe, Not Sorry!

by Jim Britton (1999)

 Download this paper

ABSTRACT

Offshore structures in deep water are now quite common. However, a deep water development project still requires significant capital investment on the part of the operator. Corrosion failure is not acceptable. This paper presents a common sense approach to cathodic protection design on deep water projects. Some practical tips for avoiding pitfalls are presented as well as an analysis of the role of ROV's in maintenance and monitoring of these assets.

Introduction

The worldwide development of deep water oil and gas prospects has resulted in the emergence of many alternative schemes and structures designed to produce oil and gas more cost effectively. Early developments used large fixed jacket structures such as the Shell Cognac and Bullwinkle platforms, which are located in water depths of 1000 feet and 1350 feet respectively in the Gulf of Mexico. As drilling moved to even greater depths, these fixed structures were no longer cost effective, and new structure designs emerged: Tension Leg Platforms (TLP's), Floating Production Systems (FPS's), SPAR designs. All of these structures have process facilities located on the surface, above subsea wellheads. The completion of remote subsea wells connected by flow lines and control umbilicals to a surface production facility is now the most common design, being a very cost effective method for developing smaller reservoirs. These remote wells are often several miles from the production facility, and it is not uncommon for several subsea wells to be connected to a single subsea manifold structure, which is in turn connected by pipeline to a production or storage facility on the surface. Cathodic protection (CP) for these wells, manifolds, flow lines, jumpers and umbilicals is the main focus of this paper.

Environmental Considerations

Understanding Deep Water - There are three major factors impacting cathodic protection design in deep water. It is important to understand these factors and how they work together to drive CP designs in this environment:

In summary, designing deep-water cathodic protection systems requires the following basic design criteria modification:

Cathodic Protection Design (basic considerations)

Design Conservatively - If "conservative" is defined as "being within sensible limits," then we must design deep water cathodic protection systems very conservatively. The cost associated with deep-water oil and gas projects is measured in tens, or even hundreds of millions of dollars. Costs associated with in-situ repairs quickly escalate when there is a problem. For this reason, corrosion failures are not an option. Cathodic protection systems for these pieces of equipment have relative costs in the tens of thousands of dollars. Cathodic protection is relatively cheap; use it wisely. Try to get it right the first time.

Use Coatings - As previously stated, cathodic protection design in cold water requires more cathodic protection current per unit area, and in cold water a standard anode geometry will make less current available. It quickly becomes obvious that covering up some surface area with coatings makes a CP design much more manageable. Coatings also provide additional benefits such as increased in-situ visibility, and corrosion protection during onshore fabrication and storage.

Coating Efficiency - What is the appropriate coating breakdown-factor to use? This question has been debated among corrosion engineers for decades. Published guidelines vary in their advice on this subject. One prominent code considers some coatings completely worthless after 20 years [1]. The same guideline later provides this statement: "Operator's experience of a specific paint coating system may justify the use of less conservative coating breakdown factors than specified in this document." Clearly conservative common sense must rule. For pipelines, it is common practice to assign a coating breakdown factor of 5% over the design life. For coatings on seawater immersed surfaces near the bottom, we would recommend increasing this numbers to 10-15% initial damage and 20-25% over the design life. This will require more anodes, but remember: be safe, not sorry.

Quality Control - It is critical that sacrificial anodes work as designed. Anodes which fail to activate, or which perform with significantly reduced galvanic efficiency could mean that an anode retrofit will be required prematurely. Deep water anode retrofit projects are not impossible, but they are usually very expensive. Anode performance can be guaranteed if the following quality control guidelines are observed:

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

 2. Use an anode alloy with a proven track record. The Al-In-Zn-Si anode alloys are preferable because their behavior in mud environments is more predictable, and because there are less environmental concerns than with Mercury (Hg) or Tin (Sn) activated materials. Aluminum (Al-In-Zn-Si) anodes are more efficient and lighter than zinc anodes and have the highest available open circuit potential.

3. Ensure that the anode specifications require that the testing be performed at the minimum anticipated service temperature.

Table 1

Anode Chemistry Modification for Cold Water Service

Special Considerations for Subsea Production Equipment

The mechanical complexity of a subsea wellhead assembly or a subsea production manifold causes a number of unusual problems for a cathodic protection designer. The wide array of specialized materials used can result in unexpected compatibility issues. It is important to be aware of pitfalls and to design the cathodic protection systems around them. Some problems specific to subsea production equipment are addressed in the following sections.

B. Continuity Testing - Most subsea development projects include a phase called System Integration Testing (SIT). All the various components of the system are stacked up or connected on dry land to simulate the completed offshore installation. This is a perfect opportunity to verify electrical continuity throughout the assembly. Continuity is verified from a common test point on the component where the anodes are attached to all other components that comprise the assembly. A standard multi meter can be used to check the resistance, we recommend that a value of 0.3 Ω or less be verified (excluding test lead resistance). The same test points (Figure 2) are used as inspection points for life cycle monitoring of the system. Discontinuities (and there will usually be some) can be fixed onshore quite easily. An example of a typical discontinuity found during an inspection is shown in Figure 3.

Fixing Continuity Problems - Some ways to address continuity problems are:

C. Material Incompatibilities - The wide array of materials and corrosion resistant alloys used on these projects can cause problems. It is important to review all materials that will be exposed to cathodic protection for their susceptibility to hydrogen damage at the expected potential. Materials that should be closely checked include: some alloys of titanium, some stainless steels (400 series for example) and 17-4 PH. Sometimes it is difficult to prevent components from receiving cathodic protection even though the material selection engineer may not have intended it.<

D. Cathodic Shielding - The connectors used to make subsea pipeline connections are extremely intricate mechanical devices with tight, flooded interior spaces comprising a large combination of materials. It is important to remember that concentrated areas of uncoated steel (albeit stainless steel) in metallic compartments may be subject to cathodic shielding and may not receive enough current to be adequately protected. Care should be taken to ensure that these areas are provided with anodes inside and outside the compartment. Other areas potentially subject to shielding include components with mechanically attached dielectric buoyancy modules (syntactic foam), these can behave like ultra-thick disbonded coatings. Control pods often have control tubing manifolds under a protective steel cover. These areas must receive special attention from the cathodic protection designer.

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

F. ROV Compatibility - At extreme depths >1000 feet, all work on the facilities will have to be performed by a Remotely Operated Vehicle (ROV). These machines, while continually improving, are still machines with limited dexterity and a tether / umbilical. To keep the cathodic protection design ROV friendly, follow these simple steps:

3. For potential monitoring, provide clearly marked, bare steel test stab locations. The high quality coatings used on many of these facilities do not allow stabbing probes to easily penetrate. Attempting to establish a clean tip contact through a high quality marine epoxy paint could damage the subsea equipment. It also puts tremendous strain on the ROV hydraulic systems.

4. When specifying cathodic protection probes or current probes, select a mount that will easily fit the ROV manipulator and which will require minimum interface to the ROV electronic and fiber optic systems. Figure 5 shows a recently developed self contained deep water CP probe designed for operation at up to 10,000 feet, while requiring no electrical interface to the ROV. A standard tip contact CP probe, which requires surface interfacing, is also shown (Figure 6).

Special considerations for deep water pipelines

Q: What is special about a deep water pipeline?

A: Basic design criteria for deep water pipelines and flowlines are not much different from shallow water systems, but there are more risks associated with a pipeline located in deep water. The following suggestions are offered to minimize the risk of problems with these cathodic protection systems. Some of these suggestions would incidentally improve shallow water system reliability also.

A. Anode Tapers - Most deepwater pipelines are not stabilized with concrete weight coatings, thus the bracelet anodes commonly used are proud of the pipeline. As a result anodes sometimes detach during the lay process due to the anode snagging on the pipe lay equipment [3][4]. The use of cast polyurethane tapers to anchor the anode and provide a smooth diameter transition has proven to be a very effective remedy to this problem. Placing both anode halves a particular way can also reduce the risk of snagging. One want to be sure that all of the anodes will arrive on the seabed at the six o' clock position. This process is not as favorable as the tapers but may be the only workable solution if anodes have to be attached on the lay barge [5].

B. Pipe Lay Inspection - The best opportunity to identify and repair problems is always during the installation. Technology is available which will verify that anodes are attached to the pipe and that the coating is not badly damaged before the pipe hits the seabed [5]. In addition, the required post-lay inspection performed by all operators to check the location of the line is also a great opportunity to verify the pipeline's corrosion control system performance. Specify that a cathodic protection probe be attached to the ROV during the post lay (as-built) inspection run.

Cathodic Protection Testing and Monitoring with ROV's

Introduction - Without the ROV there would be no oil and gas development in water depths greater than 1500 feet. These underwater robots are complex machines without brains. We have to make it simple for them to do the work of corrosion technicians [6]. With subsea developments we do not have the luxury of running cables to the surface. Therefore, we must use the ROV. Equipment made especially for ROV's is now available to perform the following tasks:

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

Current Density and Anode Current Measurement - Historically this has been achieved using the electric field gradient method [7]. A newly developed fixed monitoring instrument allows a current density monitor or monitored anode to be deployed for measurement with an ROV (Figure 4). By stabbing a self contained readout into the fixed contacts the voltage drop shunt can be accurately recorded.

Conclusions

When designing a CP system in deep water, be safe, not sorry! Pay close attention to the structure, its continuity, what it's made of, its geometry, and how it will be protected over its life cycle. Be conservative with coating and cathodic protection designs, but make retrofit provisions by providing simple ROV attachment points. Ensure that only quality materials are used in the corrosion control system. And last but not least, hire a corrosion engineer to review all the design specifications, coatings vs. materials vs. cathodic protection.

References

[1] Del Norske Veritas (DnV) - Recommended Practice RP 8401 - "Cathodic Protection Design" - 1993
[2] NACE International- TMOI90-98 - "Impressed Current Test Method for Laboratory Testing of Aluminum Anodes"
[3] CORROSION '97 - Paper 470 - R. H. Winters, A. Holk -"Cathodic Protection Retrofit of an Offshore Pipeline"
[4] CORROSION '93 - Paper 527 - LJ. Rippon et aI. - "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 ROY interface for Corrosion Monitoring Equipment"
[7] CORROSION '92 - Paper 422 - J. Britton "Continuous Surveys of Cathodic Protection System Performance on Buried Pipelines in the Gulf of Mexico"