Response to Mark and Ernie,
Mark and Ernie, thank you very much for your comments. These are the discussions that we will all learn from.
I would like to clarify a couple of points about my comments to be sure everyone is aware of what I think are some very critical points.
Mark Mateer says - “The reason FBE seems so effective is that is doesn't create any shielding problems that plague other coatings, not because it works better with any particular criterion.”
This is one of the points that I do not think everyone has understood. I am not saying FBE performance has anything to do with the criteria selected. Too the contrary, my point is that no matter which of the three criteria are used, we rarely (if ever) see external corrosion on FBE coated pipelines with the exceptions noted in the earlier presentation. The point is that most companies used an “ON” -850 mV (without considering IR drop) for the first 30+ years of FBE and some still use this criterion because it works for them. If considering IR drop is so important, why would we not have external corrosion on these pipelines? Toby Fore’s paper “First Generation of Fusion Bonded Epoxy Coatings Performance After 30 Years of Service – A Case Study” (CORROSION 2006 –Paper 06045) points this out very well. Even though the potentials at the sites studied were more negative than -850 mV “ON” versus copper/copper sulfate electrode, the point is that the criterion used was an “ON” -850 mV without IR drop consideration and there are no external corrosion problems!
There have been many cases of FBE disbondment, but because of the non-shielding property, the “ON” -850 mV (without IR drop considered) is adequate protection. If the “ON” -850 mV is adequate for the areas of non-shielding, disbonded, FBE coated pipelines it will be sufficient for any structure that has a non-shielding coating that allows the CP current to be effective or a bare structure with no shielding. Coatings that do shield CP current in disbonded areas, do not allow CP to be effective so corrosion can and many times does develop when water penetrates.
Mark Mateer says - “From a past PRCi study, we know that 850 IR considered works about 95% of the time when used correctly. In contrast, 850 polarized is about 98% effective and the 100 mV shift criteria is 100% effective.”
I have not seen a complete copy of this document, but I think there are many issues with this report. I do agree with the statement that the -850 mV criterion is more effective than -850 mV “ON” criterion, but only because you are applying more current, so you may force some current under disbonded coating. We must also include the problems that we create because of all the current we are now using. As Johnny, pointed out, the problems with interference are enough to make us stop and consider what other potential problems we are creating. Corrosion problems from interference happen much faster than those from inadequate CP. Of course, we also have to consider the potential damage from more coating disbondment problems and possible hydrogen embrittlement, etc. (Especially as we move toward higher strength steel pipelines). More energy consumption and increased cost of surveys and equipment must also be considered. Ondak and Rizzo mention this in their paper at CORROSION 2008 – “ELECTROCHEMICAL ANALYSIS OF PIPELINE CP CRITERIA” – Paper 08068.
I would not say that the 100 mV criterion is 100% effective, especially for pipelines that have disbonded and shielding pipeline coating, or in other areas of shielding, etc. Bob Gummow addresses many of the problems with this criterion in his paper “Technical Consideration on the Use of the 100 mV Cathodic Polarization Criterion” Paper 07035 from CORROSION 2007. Though I do not agree with all Bob has to say or has written, I know he has a very vast knowledge of CP criteria, etc. and I have learned many things from him.
How many times do we find that we do not have 100 mV of polarization when we have an “ON” -850 mV? Not many from my experience. When protecting bare pipe using the 100 mV of polarization do we see corrosion once the pipe is polarized? If we provide enough current to meet the 100 mV of polarization on an uncoated pipe, we rarely have external corrosion unless there is shielding or interference. Same as on coated pipelines with non-shielding coatings. How about that! But we must consider IR drop to have effective protection according to certain folks and NACE SP0169 - 2007.
Ernie Kleckha says - “A good impressed current cathodic protection system can throw some current under a disbonded coating or at least increase the pH.”
Areas where we have coatings that shield CP current in disbonded areas, we have the potential for corrosion. As Ernie mentioned in his comments, you can throw “some” current under disbonded, shielding, coatings, but this is very hard to determine and almost impossible to measure in an effective way. There is no way of knowing if adequate current will penetrate under these coatings from above ground surveys.
I have seen times when a coating that would normally shield CP, allowed enough CP current to increase the pH to a protective level under the disbonded coating. These areas did not have external corrosion, because the CP could be effective! Again, if a coating is non-shielding in that environment (for what ever reason) it will allow enough current to effectively protect these surfaces.
THE POINT IS THAT IF WE USE COATINGS THAT ALLOW CP CURRENT TO BE EFFECTIVE, WE DO NOT HAVE EXTERNAL CORROSION PROBLEMS WHEN WE USE AN “ON” -850 mV WITHOUT IR DROP CONSIDERATION CRITERION! [Exceptions as mentioned earlier] WHY DO WE CONTINUE TO USE COATINGS THAT SHIELD CP IF DISBONDMENTS OCCUR?
Ernie Kleckha says - “I think we should use the IR drop and not just “consider the IR drop.” We can use IR drop to find pickup points, discharge points, AC and DC interference, and many other potentials damaging conditions.”
I agree with Ernie! There are times when considering IR drop is useful. As I and others have said many times, TRAINING cathodic protection personnel when it is important to “consider” and use IR drop is where we should be spending our time, not forcing everyone to consider IR drop for all readings!
There is certainly much confusion in the industry about what to do with “IR” drop. Roy Bash covers many topics in his CORROSION 2008 paper “Pipe-to-Soil Potential Measurements, The Basic Science”. Again, I may not understand or agree with all Roy has to say, but I certainly learn from his discussions and do agree with much of it.
Conclusion
There have been many papers written about this subject, but few actually discuss the real reasons for corrosion that is found on the pipelines or test structures. I think we are missing what is right in front of us. If FBE coated pipelines do not have external corrosion problems when using the “ON” -850 mV criterion without consideration for IR drop (with the exceptions listed before), even though there are many cases of disbonded FBE, then why are we having such any issue with using this criterion? We have over forty years of proof!
The issue is not the criterion being used. It is the use of coatings that shield CP when there is a disbondment, interference from all the CP in the ground, high powered AC interference and such related issues. The GTI Report # GRI-00-0231 (in which Kevin Garrity was an author) even states “Disbonded coating does not affect the cathodic protection currents but does not (?) significantly affect the electrical currents outside of the disbonded region.” What this is saying is that under disbonded coating that shields you cannot effectively control the corrosion with CP. Just because you have corrosion, does not mean your CP is inadequate. Just because you meet or exceed an certain SP0169-2007 criterion does not mean you will not have corrosion.
We encourage more debate and comments on these topics.
Thanks for visiting SP0169.com!
Richard Norsworthy
Friday, June 27, 2008
Monday, June 23, 2008
Mark Mateer Comments
In response to Richrad's request for information about FBE and CP, I believe the correct explanation for the success of FBE with the 850 IR considered criteria does not relate to criteria at all. From a past PRCi study, we know that 850 IR considered works about 95% of the time when used correctly. In contrast, 850 polarized is about 98% effective and the 100 mV shift criteria is 100% effective. The reason FBE seems so effective is that is doesn't create any shielding problems that plague other coatings., not because it works better wtih any particular criteria.
I don't believe FBE wotks any better with 850 IR considered than any other criteria, it is just a good coating that works well under almost all conditions. 850 IR considered will work well if done properly. It does have more room for error, which is the point of contention.
Thanks
Mark Mateer
I don't believe FBE wotks any better with 850 IR considered than any other criteria, it is just a good coating that works well under almost all conditions. 850 IR considered will work well if done properly. It does have more room for error, which is the point of contention.
Thanks
Mark Mateer
Ernie Klechka Comment
Richard,
I really liked you NACE presentation. Are the photographs available for inclusion in the CCCP class?
I do disagree with your comments that IR drop is not important. As you are aware we can use IR drop to find stray current on pipelines.
You also seem to imply that IR drop is a constant. You and I both know that IR drop will change in current pickup and discharge areas, near anode ground beds, and at areas with high current demand.
I agree that much of the problem centers around shielding. Coating that shield the pipeline cause erroneous conclusions concerning cathodic protection. Probably the area of shielding that causes the most concern is casings. However, shielding is not the only problem on pipelines.
Your slides show several poorly coated field welds. To me this points to poor field coating repair practices. Sure shrink sleeves can be poorly applied or subject to soil stresses that cause disbondment and shielding, but the cathodic protection system should not be allowed to be compromised because of a poor coating. A good impressed current cathodic protection system can through some current under a disbonded coating or at least increase the pH.
I think we should use the IR drop and not just “consider the IR drop.” We can use IR drop to find pickup points, discharge points, AC and DC interference, and many other potentials damaging conditions.
ERNEST W. KLECHKA P.E. ( ALASKA AND OHIO)
I really liked you NACE presentation. Are the photographs available for inclusion in the CCCP class?
I do disagree with your comments that IR drop is not important. As you are aware we can use IR drop to find stray current on pipelines.
You also seem to imply that IR drop is a constant. You and I both know that IR drop will change in current pickup and discharge areas, near anode ground beds, and at areas with high current demand.
I agree that much of the problem centers around shielding. Coating that shield the pipeline cause erroneous conclusions concerning cathodic protection. Probably the area of shielding that causes the most concern is casings. However, shielding is not the only problem on pipelines.
Your slides show several poorly coated field welds. To me this points to poor field coating repair practices. Sure shrink sleeves can be poorly applied or subject to soil stresses that cause disbondment and shielding, but the cathodic protection system should not be allowed to be compromised because of a poor coating. A good impressed current cathodic protection system can through some current under a disbonded coating or at least increase the pH.
I think we should use the IR drop and not just “consider the IR drop.” We can use IR drop to find pickup points, discharge points, AC and DC interference, and many other potentials damaging conditions.
ERNEST W. KLECHKA P.E. ( ALASKA AND OHIO)
Tuesday, June 10, 2008
Another view point from an operator
I am a relatively new to the corrosion control industry. I have been exclusively dealing with corrosion control for the last 9 years. Before that I was involved in the construction phase of our industry. I have been following the developments in the debate to change the CP criteria with much interest.
I am responsible for corrosion control on a distibution system that has been around since 1934. Needless to say we have a lot of bare pipe as well as any coating that you can think of. Seeig as the regulatory bodies do not differentiate a pipeline in it's own corridore from a distribution line installed in close proximity to other utilities the -.85cse (instant)off criteria will impact us also.
For now let's lay aside the cost and hassle of complying with -.85cse off. Neither cost nor hassle should dictate our criteria no more that regulatory bodies desiring to make thier job easier. However, the current densities required to operate a system like ours at -.85cse off will cause adverse problems. First the interference we will create with water, sewer, and other infrastructure will corrosion problem not only on our system but also on the other utilities. Next, the high current densities wil cause disbondment on some of our older coatings and will create a whole new set of problems. We have not seen any corrosion on FBE coated pipe that cannot be attributed to other circumstances. If the science proved that we needed this new criteria I would gladly support the efforts. However, these efforts to change the criteria seem to be driven by market forces and not scientific reasons.
Johnny Martin
Willmut Gas Co.
I am responsible for corrosion control on a distibution system that has been around since 1934. Needless to say we have a lot of bare pipe as well as any coating that you can think of. Seeig as the regulatory bodies do not differentiate a pipeline in it's own corridore from a distribution line installed in close proximity to other utilities the -.85cse (instant)off criteria will impact us also.
For now let's lay aside the cost and hassle of complying with -.85cse off. Neither cost nor hassle should dictate our criteria no more that regulatory bodies desiring to make thier job easier. However, the current densities required to operate a system like ours at -.85cse off will cause adverse problems. First the interference we will create with water, sewer, and other infrastructure will corrosion problem not only on our system but also on the other utilities. Next, the high current densities wil cause disbondment on some of our older coatings and will create a whole new set of problems. We have not seen any corrosion on FBE coated pipe that cannot be attributed to other circumstances. If the science proved that we needed this new criteria I would gladly support the efforts. However, these efforts to change the criteria seem to be driven by market forces and not scientific reasons.
Johnny Martin
Willmut Gas Co.
Wednesday, June 4, 2008
ANOTHER REASON WE NEED TO FIGHT THE PROPOSED CRITERIA SECTION CHANGES
When we look at all the reasons proposed for the changes to the SP0169-2007 (RP0169) one consideration that must be involved in the discussion is the cost to implement the proposed criteria changes. Though some say cost should not be considered in providing the industry with a Standard Practice, it must be considered when companies are asked to spend a considerable amount of money, with little or no improvement to the integrity of their systems.
There are many other changes that are needed, but I believe there are few needed to the Section 6 that is the main topic of discussion. Some of those changes are discussed in the other Blog topics.
In this section I would like to discuss the cost of implementing and maintaining some of the proposed changes to the criteria section. When I have asked some of the experts about how do companies that use galvanic anodes that have no access (or even if they do) prove a polarized potential or 100 mV of polarization, they say the companies can install coupons to confirm these two criterion.
There are many inherent problems with coupons and their design. Some of the issues with coupons include, but are not limited to:
1. Where is the coupon placed in relationship to the structure? (How close what position around the pipe, etc.)
2. What size should the coupons be? (They always say it should represent the size of the largest holiday in the area. Now how are we going to know that? If the pipe is bare?)
3. What shape should the coupon be? (Round, square, rectangular, etc.)
4. Should the coupons be coated on one side?
5. What material should the coupon be made of?
6. Where should the reference cell be placed in relationship to the coupon? (Should it be in the tube above the coupon with native soil, special backfill, or no backfill? Should it just be placed on the ground above the soil?)
7. Should the reference be Copper/Copper Sulfate or zinc?
8. Should you wet the soil in the tube before the potentials are taken?
9. Where should the reference cell be placed in relationship to coupon?
10. There are many different types of commercial coupon test stations, what are the differences?
11. Does the potential reading really represent the potential of the pipe?
Once you figure out what type of coupon to use and where to place it (etc.), then you have to pay for it, install it and maintain it. The coupon test stations with stationary reference cells, must concern themselves with how long the reference cell will be accurate, etc.
Below is one example of the cost of using these coupons on a large gas distribution/pipeline system in the southern USA.
“Richard, it would cost (Company name with held) in excess of $100,000,000 to install coupon test station on magnesium protected distribution CP Zones and in excess of $5,500,000 for additional impressed current on our transmission systems. There would also be an increase in labor and transportation to monitor the -850 "off". These are conservative numbers!”
These numbers can easily be multiplied by each company that has galvanic protected pipelines and may be forced to use coupons to prove their protection level. These numbers do not reflect the cost of maintaining and replacing as needed.
Another large gas distribution/pipeline company in the central northern USA provides similar information and opposes such changes. They do not see any need for IR drop consideration from their many years of using an “ON” -850 mV criterion with no CP related failures reported.
The following is extracted from a power point presentation and a letter to the TG 360 committee:
• Does not support revisions to Section 6 that would eliminate the -850 mV “On” criteria or requirement that reading needs to be corrected for IR drop.
• CP (corrosion) problems that we have identified are not caused by lack of CP, but rather by stray current, interference, or third party damage.
• Proposed changes in SPO 169 would probably require large effort to install coupon test stations and increase in CP output
• It is possible that large expenditures could be made that would result in no improvement in system integrity. It would be more prudent to direct resources to known issues.
“We have operated our system successfully using the -850 mV “On” criteria for the past 37 years and are experiencing declining leak rates on steel pipe. We have not had a reportable incident caused by a corrosion leak on protected steel pipe in many years. Operating our corrosion control program under the current standards in combination with a leak survey program has been very effective in maintaining system integrity. The proposed changes to SPO 169 could cause a significant increase in our operating expense with little or no benefit.
If these changes are adopted into DOT code, we would need to install coupon test stations to validate the IR drop measurement. It could potentially cost millions of dollars to install these test stations and increase CP output, and result in little or no improvement in system integrity.”
These are just two examples of companies that have a real problem with the potential cost of the proposed changes that may require installation of coupon test stations to prove the criteria is being met.
Transmission pipeline companies that use mostly impressed current CP will be required to do polarized potential surveys which once again means additional cost and effort. There has not been a decision made on how often these companies may have to do such surveys to satisfy the regulatory requirements of each country, state or local government. If these surveys have to be performed annually, this presents a real economic challenge.
With NACE International wanting to project a GREEN image, why do we want to propose such a drastic change in the cost of performing a CP survey to satisfy a criterion that will require significant effort, energy usage (the amount energy used can be 2 to 3 times more to achieve a polarized -850 mV versus an -850 mV ON {without IR drop considered} and up to 5 times more than using a 100 mV polarization change), more vehicles and equipment to do these more complicated surveys, potential for more interference leaks caused from more CP being used, as well as potential damage from hydrogen and further disbondment of coatings. This will not project a GREEN image.
Politically NACE is now tied to ANSI and ISO so they have to follow certain guidelines when changing standards. One problem that some have on this committee is that the fear if we do not make these changes, it will say that NACE is not progressive in providing change to improve these documents. Since ISO, other organizations and some countries require more stringent criteria, they are of the belief NACE must follow because these organizations must know what they are doing and if we want to be the leader in corrosion control, we must change to be more stringent! I have no problem with change when it is needed and proven to be needed, but just to change because some else does makes no sense to me.
2 + 2 equals 4 in most parts of the world and it works. What if a certain group decides that it should be 7? Does everyone automatically without reservation change to seven because a few experts decide it is better because one of them wrote a paper about it or someone in a particular country is doing it?
NACE should be and I think is the leader in the corrosion community because we have consensus documents, not one formatted by some select committee that knows more than any one else or can afford to go to the meetings. I think progress also includes correcting mistakes made by former committees. For example, when we were forced to consider IR drop in the -850 mV criterion back in 1992 (I think), this was a mistake that has led some to believe that it is the same as the polarized potential so why not just have the one polarized -850 mV criterion. This was a compromised change in order to get the document out the door. Some will know what I am talking about. This was wrong then and is now. Change it back to “IR should be considered” when unusual circumstances require it.
The cost to the world wide industry will be tremendous with little or no improvement. There are certainly times when more stringent criterion is needed, but it should be forced on every situation, because it works in some unusual environment.
I challenge those who are in favor of the proposed changes to provide us with the significant documentation that proves the changes are needed so we can all review and comment. I also challenge those who believe as I do that we need to go back to a reasonable criterion that allows us to use the -850 mV ON with consideration for IR drop only when unusual circumstances require it to get your information together. The industry has over 50 years of data that can be used to prove much of what we are saying, but it is typically ignored in favor of some scientific papers that many times did not prove the point in most folk’s minds.
By the way, I am still waiting for someone to prove me wrong about the use of FBE coating and the fact that we do not have significant, if any, external corrosion problems even though most have used the -850 mV “ON” without consideration for IR drop (at least the first 30 + years of FBE usage). There have been disbondments, adhesion failures and blistering of FBE since the beginning, yet unlike most coatings there are not the shielding problems. So why do we not have external corrosion if we must have a polarized -850 mV? This is an important issue and the industry must use the data from the ILI pig data and ECDA data to prove this to the committee.
If you have not done so please read the other postings. Go to the Polyguard website at http://www.polyguardproducts.com and read articles about why we still have external corrosion on pipelines (because of coatings that shield CP when they fail) that are cathodically protected.
Please send comments and we will post them. We need everyone’s input to keep this problem in front of the cathodic protection industry around the world. Thanks for your help and please let me know if I can help you with pipeline coatings or CP questions, etc.
Richard Norsworthy
Polyguard Products, Inc.
richnors@flash.net
There are many other changes that are needed, but I believe there are few needed to the Section 6 that is the main topic of discussion. Some of those changes are discussed in the other Blog topics.
In this section I would like to discuss the cost of implementing and maintaining some of the proposed changes to the criteria section. When I have asked some of the experts about how do companies that use galvanic anodes that have no access (or even if they do) prove a polarized potential or 100 mV of polarization, they say the companies can install coupons to confirm these two criterion.
There are many inherent problems with coupons and their design. Some of the issues with coupons include, but are not limited to:
1. Where is the coupon placed in relationship to the structure? (How close what position around the pipe, etc.)
2. What size should the coupons be? (They always say it should represent the size of the largest holiday in the area. Now how are we going to know that? If the pipe is bare?)
3. What shape should the coupon be? (Round, square, rectangular, etc.)
4. Should the coupons be coated on one side?
5. What material should the coupon be made of?
6. Where should the reference cell be placed in relationship to the coupon? (Should it be in the tube above the coupon with native soil, special backfill, or no backfill? Should it just be placed on the ground above the soil?)
7. Should the reference be Copper/Copper Sulfate or zinc?
8. Should you wet the soil in the tube before the potentials are taken?
9. Where should the reference cell be placed in relationship to coupon?
10. There are many different types of commercial coupon test stations, what are the differences?
11. Does the potential reading really represent the potential of the pipe?
Once you figure out what type of coupon to use and where to place it (etc.), then you have to pay for it, install it and maintain it. The coupon test stations with stationary reference cells, must concern themselves with how long the reference cell will be accurate, etc.
Below is one example of the cost of using these coupons on a large gas distribution/pipeline system in the southern USA.
“Richard, it would cost (Company name with held) in excess of $100,000,000 to install coupon test station on magnesium protected distribution CP Zones and in excess of $5,500,000 for additional impressed current on our transmission systems. There would also be an increase in labor and transportation to monitor the -850 "off". These are conservative numbers!”
These numbers can easily be multiplied by each company that has galvanic protected pipelines and may be forced to use coupons to prove their protection level. These numbers do not reflect the cost of maintaining and replacing as needed.
Another large gas distribution/pipeline company in the central northern USA provides similar information and opposes such changes. They do not see any need for IR drop consideration from their many years of using an “ON” -850 mV criterion with no CP related failures reported.
The following is extracted from a power point presentation and a letter to the TG 360 committee:
• Does not support revisions to Section 6 that would eliminate the -850 mV “On” criteria or requirement that reading needs to be corrected for IR drop.
• CP (corrosion) problems that we have identified are not caused by lack of CP, but rather by stray current, interference, or third party damage.
• Proposed changes in SPO 169 would probably require large effort to install coupon test stations and increase in CP output
• It is possible that large expenditures could be made that would result in no improvement in system integrity. It would be more prudent to direct resources to known issues.
“We have operated our system successfully using the -850 mV “On” criteria for the past 37 years and are experiencing declining leak rates on steel pipe. We have not had a reportable incident caused by a corrosion leak on protected steel pipe in many years. Operating our corrosion control program under the current standards in combination with a leak survey program has been very effective in maintaining system integrity. The proposed changes to SPO 169 could cause a significant increase in our operating expense with little or no benefit.
If these changes are adopted into DOT code, we would need to install coupon test stations to validate the IR drop measurement. It could potentially cost millions of dollars to install these test stations and increase CP output, and result in little or no improvement in system integrity.”
These are just two examples of companies that have a real problem with the potential cost of the proposed changes that may require installation of coupon test stations to prove the criteria is being met.
Transmission pipeline companies that use mostly impressed current CP will be required to do polarized potential surveys which once again means additional cost and effort. There has not been a decision made on how often these companies may have to do such surveys to satisfy the regulatory requirements of each country, state or local government. If these surveys have to be performed annually, this presents a real economic challenge.
With NACE International wanting to project a GREEN image, why do we want to propose such a drastic change in the cost of performing a CP survey to satisfy a criterion that will require significant effort, energy usage (the amount energy used can be 2 to 3 times more to achieve a polarized -850 mV versus an -850 mV ON {without IR drop considered} and up to 5 times more than using a 100 mV polarization change), more vehicles and equipment to do these more complicated surveys, potential for more interference leaks caused from more CP being used, as well as potential damage from hydrogen and further disbondment of coatings. This will not project a GREEN image.
Politically NACE is now tied to ANSI and ISO so they have to follow certain guidelines when changing standards. One problem that some have on this committee is that the fear if we do not make these changes, it will say that NACE is not progressive in providing change to improve these documents. Since ISO, other organizations and some countries require more stringent criteria, they are of the belief NACE must follow because these organizations must know what they are doing and if we want to be the leader in corrosion control, we must change to be more stringent! I have no problem with change when it is needed and proven to be needed, but just to change because some else does makes no sense to me.
2 + 2 equals 4 in most parts of the world and it works. What if a certain group decides that it should be 7? Does everyone automatically without reservation change to seven because a few experts decide it is better because one of them wrote a paper about it or someone in a particular country is doing it?
NACE should be and I think is the leader in the corrosion community because we have consensus documents, not one formatted by some select committee that knows more than any one else or can afford to go to the meetings. I think progress also includes correcting mistakes made by former committees. For example, when we were forced to consider IR drop in the -850 mV criterion back in 1992 (I think), this was a mistake that has led some to believe that it is the same as the polarized potential so why not just have the one polarized -850 mV criterion. This was a compromised change in order to get the document out the door. Some will know what I am talking about. This was wrong then and is now. Change it back to “IR should be considered” when unusual circumstances require it.
The cost to the world wide industry will be tremendous with little or no improvement. There are certainly times when more stringent criterion is needed, but it should be forced on every situation, because it works in some unusual environment.
I challenge those who are in favor of the proposed changes to provide us with the significant documentation that proves the changes are needed so we can all review and comment. I also challenge those who believe as I do that we need to go back to a reasonable criterion that allows us to use the -850 mV ON with consideration for IR drop only when unusual circumstances require it to get your information together. The industry has over 50 years of data that can be used to prove much of what we are saying, but it is typically ignored in favor of some scientific papers that many times did not prove the point in most folk’s minds.
By the way, I am still waiting for someone to prove me wrong about the use of FBE coating and the fact that we do not have significant, if any, external corrosion problems even though most have used the -850 mV “ON” without consideration for IR drop (at least the first 30 + years of FBE usage). There have been disbondments, adhesion failures and blistering of FBE since the beginning, yet unlike most coatings there are not the shielding problems. So why do we not have external corrosion if we must have a polarized -850 mV? This is an important issue and the industry must use the data from the ILI pig data and ECDA data to prove this to the committee.
If you have not done so please read the other postings. Go to the Polyguard website at http://www.polyguardproducts.com and read articles about why we still have external corrosion on pipelines (because of coatings that shield CP when they fail) that are cathodically protected.
Please send comments and we will post them. We need everyone’s input to keep this problem in front of the cathodic protection industry around the world. Thanks for your help and please let me know if I can help you with pipeline coatings or CP questions, etc.
Richard Norsworthy
Polyguard Products, Inc.
richnors@flash.net
Thursday, May 22, 2008
criteria and FBE
To All,
I am in the process of writing a paper for NACE 2009. The paper will be about the relationship of FBE and cathodic protection criteria. As I mentioned in my speech before the TG 360 group (changes to SP0169) the industry rarely sees external corrosion on FBE coated pipelines even though most of the pipelines have been protected by using the "ON" -850 mV criterion, especially for the first 30 + years that FBE has been used.
I need to find as many case histories as possible for showing that this is true. We can do this generically, but it will hold more weight if we can actually show the company, etc. Preferably, we will have case histories where we can show no or otherwise explained external corrosion on FBE coated pipelines over the period of time when the only criterion used was an "ON" -850 mV.
Since FBE allows CP to be effective should there be disbondment we do not normally see external corrosion on FBE coated pipelines. Most of the times we have seen external corrosion was in areas where the CP was shielded or there was an interference problem. In most cases, companies used only an "ON" -850 mV, yet we did not and do not see external corrosion on FBE coated pipelines.
So what I need are case histories that show (as much as possible):
1. What criterion (criteria) was (were) being used?
2. What potentials ranges were in the area inspected? (with or without IR drop consideration if possible to give this information)
3. Did ILI or ECDA show external corrosion? (PHOTOS where possible)
a. If so, was it under the FBE or other coatings?
b. If so, were there other reasons why the corrosion existed? (shielding, AC or DC interference, etc)
c. Were pH readings taken?
d. Was it evaluated to see if it occurred during times CP was not applied or effective? (if data is available, etc.)
e. Was it active or old corrosion?
4. Age of the system.
5. Thickness of the FBE.
6. Soil or environment in which the pipe is in service.
7. Service temperature of the product.
8. Type of girth weld coating used.
9. If you have examples of surveys (CIS, DCVG, ACVG) showing protected levels (especially with the polarized -850 mV), yet you still had external corrosion (caused from coatings that shielded, etc.) when the line was inspected, this is valuable information also to prove the point that nothing is 100%. Once again case histories and photos are valuable!
10. Any thing else that will help!
If any one would like to co-author the paper, you are more than welcome to work with me on this project. This information is critical to demonstrating why an "ON" -850 mV is an acceptable level of cathodic protection, even when not considering IR drop. Now is the time for all good women and men to step up give the industry something to help us solve this problem. We all know field data is more accurate and valuable than the lab and test data being quoted by some on the committee.
As we know if these folks get their way they will force us to all go to a polarized -850 mV or the 100 mV of polarization. Please help those of us who know from field experience what we are doing is working without having to consider IR drop except in very unusual areas and circumstances that can be given.
Since the PCRI report is quoted often in the defense of the polarized -850 mV criterion, I need a copy if anyone has one. If not let me know how to get a copy and I will buy it. From some of the data that has been shown, I do not think it show any definite conclusions.
This will also be posted on the SP0169.com blog site. If you have not visited it there are some good comments and information. We will be glad to add yours to it. It can be anonymous if you wish, but I would at least like to know who you are and I decide what goes on, etc. I also welcome comments and case histories from each side of this issue, because that is the way we all learn and make our industry better.
Thanks for your help and we must pull this information together to head off the proposed changes. We can make this a very good document if we work together with a united effort.
Richard Norsworthy
Polyguard Products, Inc.
214-912-9072
I am in the process of writing a paper for NACE 2009. The paper will be about the relationship of FBE and cathodic protection criteria. As I mentioned in my speech before the TG 360 group (changes to SP0169) the industry rarely sees external corrosion on FBE coated pipelines even though most of the pipelines have been protected by using the "ON" -850 mV criterion, especially for the first 30 + years that FBE has been used.
I need to find as many case histories as possible for showing that this is true. We can do this generically, but it will hold more weight if we can actually show the company, etc. Preferably, we will have case histories where we can show no or otherwise explained external corrosion on FBE coated pipelines over the period of time when the only criterion used was an "ON" -850 mV.
Since FBE allows CP to be effective should there be disbondment we do not normally see external corrosion on FBE coated pipelines. Most of the times we have seen external corrosion was in areas where the CP was shielded or there was an interference problem. In most cases, companies used only an "ON" -850 mV, yet we did not and do not see external corrosion on FBE coated pipelines.
So what I need are case histories that show (as much as possible):
1. What criterion (criteria) was (were) being used?
2. What potentials ranges were in the area inspected? (with or without IR drop consideration if possible to give this information)
3. Did ILI or ECDA show external corrosion? (PHOTOS where possible)
a. If so, was it under the FBE or other coatings?
b. If so, were there other reasons why the corrosion existed? (shielding, AC or DC interference, etc)
c. Were pH readings taken?
d. Was it evaluated to see if it occurred during times CP was not applied or effective? (if data is available, etc.)
e. Was it active or old corrosion?
4. Age of the system.
5. Thickness of the FBE.
6. Soil or environment in which the pipe is in service.
7. Service temperature of the product.
8. Type of girth weld coating used.
9. If you have examples of surveys (CIS, DCVG, ACVG) showing protected levels (especially with the polarized -850 mV), yet you still had external corrosion (caused from coatings that shielded, etc.) when the line was inspected, this is valuable information also to prove the point that nothing is 100%. Once again case histories and photos are valuable!
10. Any thing else that will help!
If any one would like to co-author the paper, you are more than welcome to work with me on this project. This information is critical to demonstrating why an "ON" -850 mV is an acceptable level of cathodic protection, even when not considering IR drop. Now is the time for all good women and men to step up give the industry something to help us solve this problem. We all know field data is more accurate and valuable than the lab and test data being quoted by some on the committee.
As we know if these folks get their way they will force us to all go to a polarized -850 mV or the 100 mV of polarization. Please help those of us who know from field experience what we are doing is working without having to consider IR drop except in very unusual areas and circumstances that can be given.
Since the PCRI report is quoted often in the defense of the polarized -850 mV criterion, I need a copy if anyone has one. If not let me know how to get a copy and I will buy it. From some of the data that has been shown, I do not think it show any definite conclusions.
This will also be posted on the SP0169.com blog site. If you have not visited it there are some good comments and information. We will be glad to add yours to it. It can be anonymous if you wish, but I would at least like to know who you are and I decide what goes on, etc. I also welcome comments and case histories from each side of this issue, because that is the way we all learn and make our industry better.
Thanks for your help and we must pull this information together to head off the proposed changes. We can make this a very good document if we work together with a united effort.
Richard Norsworthy
Polyguard Products, Inc.
214-912-9072
Saturday, May 3, 2008
Comments from Tom Laundrie
I was reading the TG 211 Proposed Nace Technical Committee Report, "Report on the 100-mV Cathodic Polarization Criterion" Draft #3b. Some of the statements used in this document can be applied to the logic of leaving the -0.85 volt On Criterion in the SP0169 document. These quotes are taken out of the section on Advantages and Disadvantages for Pipeline Applications.
First I'd like to point out that it has been shown that all we really need to reduce corrosion to an acceptable level is 100 mV of polarization, and that in most cases the -0.85 Volt On Criterion is already conservative and has a "safety factor" built in to it.
Secondly, the document points out that the 100 mV criteria uses much less current and is much less likely to cause problems. This same logic can be applied to using the -.85 On Criterion as opposed to the -0.85 Volt Instant-Off Criterion.
Advantages and Disadvantages for Pipeline Applications
For pipelines, the 100-mV cathodic polarization criterion has advantages and disadvantages when compared to the -850 mVCSE criterion. As indicated in Figure 3, the current density to achieve 100 mV of cathodic polarization is typically less than to achieve the -850 mVCSE polarized potential criterion, especially in well-aerated and well-drained soils in which the native corrosion potential may be in the -200 to -400 mVCSE range. The 100-mV criterion therefore is normally more cost-effective because of the lower current requirements. The Dearing example21 demonstrated that if the -850 mVCSE criterion were to be restored on the section of pipeline under test, additional expenditures for more cathodic protection current would have had to be made, whereas to satisfy the 100-mV cathodic polarization criterion, the existing current output was sufficient and could probably have been reduced. Such a reduction in current would result in further savings in power costs and extended groundbed life. This makes the application of the 100-mV criterion to bare or poorly coated structures more appealing because the current demand on these structures is usually high. The reduction in current demand also reduces the influence of the cathodic protection system on foreign pipelines, reducing the likelihood of stray current interference.
Attempting to achieve a minimum of -850 mVCSE on a coated pipeline may result in highly negative polarized potentials that can create the risk of hydrogen embrittlement on susceptible structures, such as high-strength steels, some types of stainless steels, and prestressed concrete cylinder pipe (PCCP) as indicated in SP0169.1 Similarly, the standard cautions against the use of excessively negative polarized potentials to minimize coating damage, such as cathodic blistering and cathodic disbondment. The use of the 100-mV cathodic polarization criterion would typically minimize both these risks. On structures composed of amphoteric materials such as galvanized steel, aluminum, and lead, all of which are subject to corrosion at highly alkaline conditions, satisfying the 100-mV criterion would normally result in a lower pH than if a polarized potential criterion were utilized.
Third: They go on to point out the cost disadvantage of measuring the 100 mV Criterion and the errors that can occur and must be accounted for (sounds like "consideration").
Although there is sometimes an economic benefit to operating cathodic protection systems based on the 100-mV cathodic polarization criterion, some of this advantage is lost because the testing regimen is more complex. Because this criterion typically relies on measuring either a native corrosion potential before the system is energized or a decayed off potential after the system has operated for a period of time, this is an extra step compared to “on/off” potential surveys conducted for comparison to a polarized potential criterion. This additional step increases the survey costs and introduces the possibility of measurement errors.
Although it is not necessary to deenergize the system until all polarization has dissipated (only until a minimum of 100 mV of depolarization has been achieved), it is usual for the systems to be turned off for periods of time that may extend into weeks. Pawson22 indicated that in the majority of cases on bare pipelines, the pipeline potentials were still depolarizing after 100 days and that, for two particular bare pipelines, there was no correlation between the original native corrosion potential and the depolarized potentials.
During the depolarization time period, protection is being lost, and the risk of corrosion activity increases. Also, when the decay period is long, seasonal and weather effects can interfere with the depolarization, either accelerating or retarding the depolarization, thereby introducing error. For long periods of depolarization, potentials are typically recorded to ensure the accuracy of the data and verify that local soil conditions did not change significantly.
Fourth: The document points out the errors involved with using Coupons to represent the pipe potentials.
Coupons are often used in situations in which it is difficult to obtain accurate native corrosion potentials or depolarized potentials because of the presence of uninterruptible current sources. Nekoska35 has stated that a coupon potential “always decays to its corrosion potential.” However, the coupon depolarized potential does not necessarily represent the pipe depolarized potential nor the depolarized potential of a similar-sized holiday in similar soil conditions because depolarization at a pipe holiday is affected by the depolarization process at other pipe coating holidays. The coupon, therefore, could have different decay characteristics than a pipeline coating holiday.
Thanks,
Tom Laundrie
Sr. Materials Engineering Specialist
NACE Cathodic Protection Specialist
First I'd like to point out that it has been shown that all we really need to reduce corrosion to an acceptable level is 100 mV of polarization, and that in most cases the -0.85 Volt On Criterion is already conservative and has a "safety factor" built in to it.
Secondly, the document points out that the 100 mV criteria uses much less current and is much less likely to cause problems. This same logic can be applied to using the -.85 On Criterion as opposed to the -0.85 Volt Instant-Off Criterion.
Advantages and Disadvantages for Pipeline Applications
For pipelines, the 100-mV cathodic polarization criterion has advantages and disadvantages when compared to the -850 mVCSE criterion. As indicated in Figure 3, the current density to achieve 100 mV of cathodic polarization is typically less than to achieve the -850 mVCSE polarized potential criterion, especially in well-aerated and well-drained soils in which the native corrosion potential may be in the -200 to -400 mVCSE range. The 100-mV criterion therefore is normally more cost-effective because of the lower current requirements. The Dearing example21 demonstrated that if the -850 mVCSE criterion were to be restored on the section of pipeline under test, additional expenditures for more cathodic protection current would have had to be made, whereas to satisfy the 100-mV cathodic polarization criterion, the existing current output was sufficient and could probably have been reduced. Such a reduction in current would result in further savings in power costs and extended groundbed life. This makes the application of the 100-mV criterion to bare or poorly coated structures more appealing because the current demand on these structures is usually high. The reduction in current demand also reduces the influence of the cathodic protection system on foreign pipelines, reducing the likelihood of stray current interference.
Attempting to achieve a minimum of -850 mVCSE on a coated pipeline may result in highly negative polarized potentials that can create the risk of hydrogen embrittlement on susceptible structures, such as high-strength steels, some types of stainless steels, and prestressed concrete cylinder pipe (PCCP) as indicated in SP0169.1 Similarly, the standard cautions against the use of excessively negative polarized potentials to minimize coating damage, such as cathodic blistering and cathodic disbondment. The use of the 100-mV cathodic polarization criterion would typically minimize both these risks. On structures composed of amphoteric materials such as galvanized steel, aluminum, and lead, all of which are subject to corrosion at highly alkaline conditions, satisfying the 100-mV criterion would normally result in a lower pH than if a polarized potential criterion were utilized.
Third: They go on to point out the cost disadvantage of measuring the 100 mV Criterion and the errors that can occur and must be accounted for (sounds like "consideration").
Although there is sometimes an economic benefit to operating cathodic protection systems based on the 100-mV cathodic polarization criterion, some of this advantage is lost because the testing regimen is more complex. Because this criterion typically relies on measuring either a native corrosion potential before the system is energized or a decayed off potential after the system has operated for a period of time, this is an extra step compared to “on/off” potential surveys conducted for comparison to a polarized potential criterion. This additional step increases the survey costs and introduces the possibility of measurement errors.
Although it is not necessary to deenergize the system until all polarization has dissipated (only until a minimum of 100 mV of depolarization has been achieved), it is usual for the systems to be turned off for periods of time that may extend into weeks. Pawson22 indicated that in the majority of cases on bare pipelines, the pipeline potentials were still depolarizing after 100 days and that, for two particular bare pipelines, there was no correlation between the original native corrosion potential and the depolarized potentials.
During the depolarization time period, protection is being lost, and the risk of corrosion activity increases. Also, when the decay period is long, seasonal and weather effects can interfere with the depolarization, either accelerating or retarding the depolarization, thereby introducing error. For long periods of depolarization, potentials are typically recorded to ensure the accuracy of the data and verify that local soil conditions did not change significantly.
Fourth: The document points out the errors involved with using Coupons to represent the pipe potentials.
Coupons are often used in situations in which it is difficult to obtain accurate native corrosion potentials or depolarized potentials because of the presence of uninterruptible current sources. Nekoska35 has stated that a coupon potential “always decays to its corrosion potential.” However, the coupon depolarized potential does not necessarily represent the pipe depolarized potential nor the depolarized potential of a similar-sized holiday in similar soil conditions because depolarization at a pipe holiday is affected by the depolarization process at other pipe coating holidays. The coupon, therefore, could have different decay characteristics than a pipeline coating holiday.
Thanks,
Tom Laundrie
Sr. Materials Engineering Specialist
NACE Cathodic Protection Specialist
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