I first want to thank these two gentlemen for providing comments to the SP0169.com blog site. I encourage others to provide comments to help us all learn and grow in knowledge of the proper ways to control external corrosion on pipelines.
I do agree with Ed’s assessment of the section 3.2. We do not to write the SP0169 around regulations or regulators from what ever country or entity that may be regulating that industry. All NACE Standard should only be written to provide the industry with the most economically effective ways to prevent corrosion.
I do not agree with all of Ed’s assessment of the remainder of the document, but this is not the first time Ed and I have disagreed! Thanks, Ed.
Roy’s comments are also very good. I do agree with most of it; except for the comments on FBE not have a problem if CP is not available. With few exceptions, if the coating system’s adhesion is good, there cannot be corrosion, because the pipe is isolated from the electrolyte.
I have seen corrosion occur on an FBE coated pipe with no CP. This was not a case of interference problems, etc. Without CP the pipe can corrode at holidays just like any other coating system.
I agree with his comments of the water penetrating and being basically pure water, but there are other conditions that exist that allow corrosion to develop. When contaminants (various salts) remain on the pipe surface before the pipe is coated, the “pure water” that penetrates combines with the salts to form a conductive path for the CP current to provide protection to the pipe surface. Without CP this area would corrode by local cell action or by being anodic to other areas where disbondments and water penetration has occurred.
If Roy’s assumption is correct, the electrochemical reactions taking place would not cause the high pH values recorded under blistered and disbonded FBE. The high pH indicates the electrochemical process is the same as that taking place on bare steel areas exposed to the same electrolyte when adequate CP is available. Therefore the current is being allowed to protect the pipe surface it these areas of disbondment because the FBE is a non-shielding pipeline coating to CP current when disbondments occur and water penetrates between the coating and the pipe surface.
Cathodic protection can be effective if it can get to the pipe surface and is not shielded by coatings or other materials, etc. As long as the coating is adhered, the CP does not need to be effective, because there is no electrolyte to cause corrosion.
There have been many papers written on this topic that explain the processes of shielding by certain types of coating systems. FBE does not have this problem even when protected by using only the -850 mV criterion (without IR drop consideration). We must start understanding this process and putting 2 and 2 together to understand when we do not need to add more CP! We need to educate our engineers and others about shielding and the proper selection of coatings that will not shield CP current if and when disbondments occur.
DO NOT FORGET TO VOTE ON THE SP0169 REVISION. If you have not joined the STG 35 group, you may not be able to vote! If you do not vote the first time, you will not get the chance to vote on other revisions that may take place after the first ballot. I am not sure when it will be voted, but my guess is sometime this year or early 2009.
Sunday, September 7, 2008
Friday, September 5, 2008
Roy Bash Comments
Solid film back pipeline coatings such as coal tar have the property to keep the pipeline perfectly dry. This is the reason that steel never corrodes under these coatings. Dry steel at normal operating temperatures never corrodes. These coatings are supplemented with cathodic protection for protecting the bare steel at places where the coating is not intact. The steel under the intact coating does not receive any cathodic protection current and it does not need any to prevent it from corroding.
Hydroscopic pipeline coatings such as FBE allow water molecules to pass through them, by the process of osmosis, to the pipe surface. This water is pure and pure water is non-corrosive to steel; hence no corrosion, cathodic protection or no cathodic protection.
From basic theory, the hydrogen ion consists of a single hydrogen atom minus its single valence electron embedded in a single water molecule. It is designated in electrochemistry text books as (H+.1H2O) or (H3O+).
When cathodic protection is applied, the FBE coating allows hydrogen ions to pass through it, by the process of electro-endo-osmosis, to the pipe surface. At the pipe surface the ion accepts one electron from the pipe and forms one atom of hydrogen which leaves one molecule of water at the pipe surface. Again, this water is pure and non-corrosive to steel, hence again no corrosion.
The water underneath a hydroscopic coating resulting through the process of osmosis is always pure and non-corrosive to steel. This is the reason that no significant corrosion is ever found under these coatings even in the water with hydrogen bubbles that are often observed under these coatings on cathodically protected pipelines when they are excavated and inspected. Just beware of the overly stringent -0.850v, CSE instant off cp criterion. History has proven the adequacy of the much less stringent -0.850v, CSE CP criterion measured with the CP applied (IR drop ignored) on steel pipelines with FBE coatings, and it reduces considerably the risk of forming the water bubbles compared to the overly stringent -0.850v, CSE instant off CP criterion which has the potential to completely disbond FBE coatings on buried or submerged pipelines over a period of time.
Respectfully submitted,
L.A.(Roy) Bash, P.E.
Hydroscopic pipeline coatings such as FBE allow water molecules to pass through them, by the process of osmosis, to the pipe surface. This water is pure and pure water is non-corrosive to steel; hence no corrosion, cathodic protection or no cathodic protection.
From basic theory, the hydrogen ion consists of a single hydrogen atom minus its single valence electron embedded in a single water molecule. It is designated in electrochemistry text books as (H+.1H2O) or (H3O+).
When cathodic protection is applied, the FBE coating allows hydrogen ions to pass through it, by the process of electro-endo-osmosis, to the pipe surface. At the pipe surface the ion accepts one electron from the pipe and forms one atom of hydrogen which leaves one molecule of water at the pipe surface. Again, this water is pure and non-corrosive to steel, hence again no corrosion.
The water underneath a hydroscopic coating resulting through the process of osmosis is always pure and non-corrosive to steel. This is the reason that no significant corrosion is ever found under these coatings even in the water with hydrogen bubbles that are often observed under these coatings on cathodically protected pipelines when they are excavated and inspected. Just beware of the overly stringent -0.850v, CSE instant off cp criterion. History has proven the adequacy of the much less stringent -0.850v, CSE CP criterion measured with the CP applied (IR drop ignored) on steel pipelines with FBE coatings, and it reduces considerably the risk of forming the water bubbles compared to the overly stringent -0.850v, CSE instant off CP criterion which has the potential to completely disbond FBE coatings on buried or submerged pipelines over a period of time.
Respectfully submitted,
L.A.(Roy) Bash, P.E.
Ed Ondak Comments
Richard,
I have not had the time to digest the document in its entirety. A quick glance, looked pretty good to me. One area that concerns me is 3.2. We should not reference regulatory requirements as a basis for the need for external corrosion. This document will be referenced world wide and some areas do not have regulatory requirements. No one, whether it be a company or an individual, should rely on and do a corrosion control program because a regulatory body says so. That is what brought about the regulations that we are faced with today.
A good corrosion program should be based on the science as we know it today, prudent operation by a company or an individual, considering public safety and the value of the assets that are being protected.
Remember, if we don't protect our assets, we may not have any assets to protect.
Edward Ondak, P.E.
I have not had the time to digest the document in its entirety. A quick glance, looked pretty good to me. One area that concerns me is 3.2. We should not reference regulatory requirements as a basis for the need for external corrosion. This document will be referenced world wide and some areas do not have regulatory requirements. No one, whether it be a company or an individual, should rely on and do a corrosion control program because a regulatory body says so. That is what brought about the regulations that we are faced with today.
A good corrosion program should be based on the science as we know it today, prudent operation by a company or an individual, considering public safety and the value of the assets that are being protected.
Remember, if we don't protect our assets, we may not have any assets to protect.
Edward Ondak, P.E.
Wednesday, August 13, 2008
Update on SP0169 and CTW
The NACE International TCC Managing committee has asked us to be sure that everyone knows this is not a NACE sponsored blog. So notice that we have that now posted on the site. Remember also that we are asking for all comments about the proposed revision to NACE SP0169 document to help everyone keep up with the thoughts and comments of others. I am asking anyone who has good data to prove your point (no matter which position you support) to send that to the blog or make an appearance before the committee and present your findings.
The time is approaching for the NACE CORROSION TECHNOLOGY WEEK (CTW) in Salt Lake City this September 14 thorough 18. Please be advised that there will be another all day session concerning the revision discussions around the SP0169-2007 document.
The meeting is set for Wednesday September 17, 2008 from 8:00 am to 5:00 pm in the Sheraton City Centre Hotel. It will be held in the Seasons North room. Hopefully we can have another great meeting with many of you making constructive comments and suggestions to the TG 360 group.
I have not seen the new revision since the CORROSION 2008 meeting, but I do understand they have been working on the document. Hopefully, this information will be posted on the NACE website before CTW so we can digest it and give constructive information to the committee.
If you can not make the meeting, please pass along any information to the committee or to the SP0169.com blog site. I am planning to be there. Hopefully, there will be good attendance.
If there is a way to provide me any more information on FBE coated pipelines and the internal line inspection (ILI) or ECDA results along with CP data this would be very good information to either confirm or deny the theory that we have proposed as to why we do not need to consider IR drop at all test sites as many propose. Again, we question the need for having to consider IR drop (with a few exceptions) when most FBE coated pipelines were only protected using a -850 mV or more negative "ON" potential criterion at least up until 1992 - 96 time frame when RP0169 was changed to say you "must consider IR drop". We did not and still do not see external corrosion on theses pipelines with exceptions mentioned below. Please read the various postings below for more information if you have not.
We do not propose that FBE is the perfect coating system, simply that it does not shield CP currents when you have adequate CP (-850 mV "ON" or more negative or 100 mV of polarization) even if disbondments occur. Why could not this theory be applied to all pipelines that have non-shielding coatings or in areas where the coating is missing (holidays and damage)? Many in the industry are beginning to better understand the relationship between shielding and non-shielding pipeline coatings in relationship to cathodic protection, because disbonded and CP shielding coatings are where we are still seeing external corrosion on most pipelines, not lack of CP.
I have some more questions about IR drops:
1. Does not a large IR drop mean we have an excess of current in that area?
2. If so, where is the current going?
3. Is it not going to the structure where it is not shielded?
4. If current is being picked up by the structure, is not protection occurring? When using conventional current theory, we say where current enters the metal we have protection, so if it is entering the structure metal, how can we have corrosion? I do understand the idea that there may be some very limited sites on the metal that have microscopic areas that are more negative than that shown by the potentials of the reference cell, but again, if there is large "I" in the IR drop there is large current to over come these cells. When the "R" is large, the corrosion rate is less any way. This is where we must better train our technicians the proper techniques to identify and deal with these situations, not force everyone to use only one method to determine protection.
5. It is strange to me, we can protect an uncoated structure at much positive potentials "ON" than a -850 mV "ON". Why do we need more negative potentials to protect a coated pipe?
6. Does IR drop cause corrosion? (NO)
7. Does IR drop protect the pipe? (NO)
8. Is the IR drop in our potential measurement really an "error" or just part of the "ON" potential? (Of course it is only a part of the "ON" potential which is the correct potential for that location of the reference cell placement.)
9. When taking a polarized potential (Instant OFF) measurement over a structure, what does that potential represent? The entire surface of the structure? The top of the structure (assuming we have the reference cell directly over the pipe)? What about the bottom? What about under shielding disbonded coating? What about the sides of the pipe? What about two feet away?
We can go on and on, but I think you get the point. What we do in the field is not an exact science. We must better train those taking these potentials on how to identify problems area that require further testing, not restrict them to a couple of difficult, time consuming and costly criterion that do not solve many of the external corrosion problems in the pipeline (and other) industry today.
Thanks for all the support and interest in this Blog site. Our goal at Polyguard is only to provide a format for information to be distributed in a way that one does not feel intimidated or lacks the presentation skills of others. We really do want information from everyone! We need arguments that define all sides to this argument. This is the way we challenge each other better to know and understand what is the best way to protect our structures from external corrosion. This make us better neighbors, protects the environment, our companies assets and the helps to conserve our resources.
Richard Norsworthy
richnors@flash.net
The time is approaching for the NACE CORROSION TECHNOLOGY WEEK (CTW) in Salt Lake City this September 14 thorough 18. Please be advised that there will be another all day session concerning the revision discussions around the SP0169-2007 document.
The meeting is set for Wednesday September 17, 2008 from 8:00 am to 5:00 pm in the Sheraton City Centre Hotel. It will be held in the Seasons North room. Hopefully we can have another great meeting with many of you making constructive comments and suggestions to the TG 360 group.
I have not seen the new revision since the CORROSION 2008 meeting, but I do understand they have been working on the document. Hopefully, this information will be posted on the NACE website before CTW so we can digest it and give constructive information to the committee.
If you can not make the meeting, please pass along any information to the committee or to the SP0169.com blog site. I am planning to be there. Hopefully, there will be good attendance.
If there is a way to provide me any more information on FBE coated pipelines and the internal line inspection (ILI) or ECDA results along with CP data this would be very good information to either confirm or deny the theory that we have proposed as to why we do not need to consider IR drop at all test sites as many propose. Again, we question the need for having to consider IR drop (with a few exceptions) when most FBE coated pipelines were only protected using a -850 mV or more negative "ON" potential criterion at least up until 1992 - 96 time frame when RP0169 was changed to say you "must consider IR drop". We did not and still do not see external corrosion on theses pipelines with exceptions mentioned below. Please read the various postings below for more information if you have not.
We do not propose that FBE is the perfect coating system, simply that it does not shield CP currents when you have adequate CP (-850 mV "ON" or more negative or 100 mV of polarization) even if disbondments occur. Why could not this theory be applied to all pipelines that have non-shielding coatings or in areas where the coating is missing (holidays and damage)? Many in the industry are beginning to better understand the relationship between shielding and non-shielding pipeline coatings in relationship to cathodic protection, because disbonded and CP shielding coatings are where we are still seeing external corrosion on most pipelines, not lack of CP.
I have some more questions about IR drops:
1. Does not a large IR drop mean we have an excess of current in that area?
2. If so, where is the current going?
3. Is it not going to the structure where it is not shielded?
4. If current is being picked up by the structure, is not protection occurring? When using conventional current theory, we say where current enters the metal we have protection, so if it is entering the structure metal, how can we have corrosion? I do understand the idea that there may be some very limited sites on the metal that have microscopic areas that are more negative than that shown by the potentials of the reference cell, but again, if there is large "I" in the IR drop there is large current to over come these cells. When the "R" is large, the corrosion rate is less any way. This is where we must better train our technicians the proper techniques to identify and deal with these situations, not force everyone to use only one method to determine protection.
5. It is strange to me, we can protect an uncoated structure at much positive potentials "ON" than a -850 mV "ON". Why do we need more negative potentials to protect a coated pipe?
6. Does IR drop cause corrosion? (NO)
7. Does IR drop protect the pipe? (NO)
8. Is the IR drop in our potential measurement really an "error" or just part of the "ON" potential? (Of course it is only a part of the "ON" potential which is the correct potential for that location of the reference cell placement.)
9. When taking a polarized potential (Instant OFF) measurement over a structure, what does that potential represent? The entire surface of the structure? The top of the structure (assuming we have the reference cell directly over the pipe)? What about the bottom? What about under shielding disbonded coating? What about the sides of the pipe? What about two feet away?
We can go on and on, but I think you get the point. What we do in the field is not an exact science. We must better train those taking these potentials on how to identify problems area that require further testing, not restrict them to a couple of difficult, time consuming and costly criterion that do not solve many of the external corrosion problems in the pipeline (and other) industry today.
Thanks for all the support and interest in this Blog site. Our goal at Polyguard is only to provide a format for information to be distributed in a way that one does not feel intimidated or lacks the presentation skills of others. We really do want information from everyone! We need arguments that define all sides to this argument. This is the way we challenge each other better to know and understand what is the best way to protect our structures from external corrosion. This make us better neighbors, protects the environment, our companies assets and the helps to conserve our resources.
Richard Norsworthy
richnors@flash.net
Friday, June 27, 2008
Response to Mark and Ernie
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
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
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)
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