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.
Tuesday, June 10, 2008
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
Saturday, April 12, 2008
Tom Hamilton comments.
I was trained as a metallurgical engineer. My first exposure to corrosion was in a course taught by Henry Van Droffelaar and Jim Atkinson. The notes from that undergraduate corrosion course were published and distributed by NACE in book form, “Corrosion and its Control”. I continued post-graduate studies in corrosion with Dr. Atkinson.
My transmission pipeline career began at TransCanada PipeLines. While I was there, we sponsored the development of the first instrumentation to allow instant-off pipe to soil readings on our close interval surveys. In that era, we also hired the best consultants in our business, including Bob Gummow, Tom Barlo and John Dabkowski, to extend our knowledge of the CP arts.
I was an early believer in using instant off surveys to limit the unpleasant effects of IR drop on our P/S readings. This technique was the principal method we used in the ‘80’s to account for IR drops in our field measurements. At first I found it interesting (confusing) that previously in the lab, we had not used interrupted readings when we recorded data. It was explained to me that this was because in the lab we were typically using conductive electrolytes, placing the tip of our Luggin capillary very close to the specimen surface, and limiting the IR drop in our measurement circuit to virtually zero using electronics. That made sense.
I thought I had a pretty good understanding of CP criteria and pipe to soil measurements. At TransCanada we had hosted two sites for the PRCI research that Dr. Barlo had led. The 100mV criterion made sense to me. Current interruption made sense to me, as I had measured huge errors in measurements that I had made over the years on many miles of CIPS that I had done, and on thousands of miles of pipe that I had taken care of. I learned my fieldcraft from Robin Pawson. I knew well the errors that can corrupt a P/S reading due to poor survey technique. Unbalanced or otherwise poorly maintained half cells. Poor half cell contact that can overwhelm even meters with high input impedance. The price of selecting a very very high input impedance for your survey. Lots of things that take time effort and experience for new practitioners to learn. It sure helps to have good mentors around for guidance!
So how did I end up on this side of the fence in the present debate? Curiously, I initially threw in with the “850 On” crowd because of my libertarian political leanings. You see, a couple of years ago, I worked on the revision of RP 0502, a practice that I had worked with for some years. We techies were interested in making revisions to that document since it had proven itself to be overly conservative in places, and we knew we could improve on it by applying various lessons learned during the five years of implementation. We were going to add value to the RP based on the results of our surveys, and on the many excavations we had performed. Science was going to be advanced, and our Companies were going to receive value due to our changing of these overly conservative requirements.
I was shocked when our committee was shut down. It seems that science was not to advance that day. It was made very clear to us that if we made any movement in a non-conservative direction, that the credibility of NACE might be undermined, since the DOT might decide that they did not like our changes, and could simply refuse to acknowledge our revised version in their regulations!
The same phenomenon seems to be at work today, on yet another NACE committee. Both science and empirical data are being undermined by political process. You see, it is much easier for the DOT (or PHMSA) to “persuade” our committees to change our recommended practices than it is for them to field large numbers of qualified auditors. I am very aware of this phenomenon. I have compliance auditors reporting to me. We much prefer to audit hard numbers rather than trying to audit thoughts or whims. I know that. It is impossible to audit someone’s intentions. Or their motivations. It is only possible to audit their work output versus agreed-upon requirements. Their adherence to written policy and procedures.
I know that it is difficult to audit a Company’s “consideration” of IR drop. Difficult, but not impossible. And that gets my dander up. Why should our Recommended Practices be modified into something that they were not intended to be, just to satisfy the Regulators? Why are the legitimate technical positions and opinions of the founding members of this association being ignored and marginalized? Why do the critics not have to prove the inadequacy of the criterion before they throw it out?
It is assumed that we have a criterion problem. I’ve not seen that in my 29 years of practice. My embarrassing leaks have always been due to inadequate CP, not inadequate criteria. It’s the practice of engineering that has failed me, not the theory of engineering principles.
I for one will continue to throw my support behind the movement to restore the original 850 On criterion, as stated in the original version of RP 0169.
And by the way, the more I look into the science behind the 850 On criterion, the more I think we’d better pause and confirm once and for all its technical applicability. I’ve not seen anything yet that leads me to believe we’d better throw it out…So I’m also going to support the movement to more fully understand the science behind the 850 On criterion.
Perhaps you’ll join us?
These comments are provided by Tom Hamilton and are his comments and experiences, not those of his company.
My transmission pipeline career began at TransCanada PipeLines. While I was there, we sponsored the development of the first instrumentation to allow instant-off pipe to soil readings on our close interval surveys. In that era, we also hired the best consultants in our business, including Bob Gummow, Tom Barlo and John Dabkowski, to extend our knowledge of the CP arts.
I was an early believer in using instant off surveys to limit the unpleasant effects of IR drop on our P/S readings. This technique was the principal method we used in the ‘80’s to account for IR drops in our field measurements. At first I found it interesting (confusing) that previously in the lab, we had not used interrupted readings when we recorded data. It was explained to me that this was because in the lab we were typically using conductive electrolytes, placing the tip of our Luggin capillary very close to the specimen surface, and limiting the IR drop in our measurement circuit to virtually zero using electronics. That made sense.
I thought I had a pretty good understanding of CP criteria and pipe to soil measurements. At TransCanada we had hosted two sites for the PRCI research that Dr. Barlo had led. The 100mV criterion made sense to me. Current interruption made sense to me, as I had measured huge errors in measurements that I had made over the years on many miles of CIPS that I had done, and on thousands of miles of pipe that I had taken care of. I learned my fieldcraft from Robin Pawson. I knew well the errors that can corrupt a P/S reading due to poor survey technique. Unbalanced or otherwise poorly maintained half cells. Poor half cell contact that can overwhelm even meters with high input impedance. The price of selecting a very very high input impedance for your survey. Lots of things that take time effort and experience for new practitioners to learn. It sure helps to have good mentors around for guidance!
So how did I end up on this side of the fence in the present debate? Curiously, I initially threw in with the “850 On” crowd because of my libertarian political leanings. You see, a couple of years ago, I worked on the revision of RP 0502, a practice that I had worked with for some years. We techies were interested in making revisions to that document since it had proven itself to be overly conservative in places, and we knew we could improve on it by applying various lessons learned during the five years of implementation. We were going to add value to the RP based on the results of our surveys, and on the many excavations we had performed. Science was going to be advanced, and our Companies were going to receive value due to our changing of these overly conservative requirements.
I was shocked when our committee was shut down. It seems that science was not to advance that day. It was made very clear to us that if we made any movement in a non-conservative direction, that the credibility of NACE might be undermined, since the DOT might decide that they did not like our changes, and could simply refuse to acknowledge our revised version in their regulations!
The same phenomenon seems to be at work today, on yet another NACE committee. Both science and empirical data are being undermined by political process. You see, it is much easier for the DOT (or PHMSA) to “persuade” our committees to change our recommended practices than it is for them to field large numbers of qualified auditors. I am very aware of this phenomenon. I have compliance auditors reporting to me. We much prefer to audit hard numbers rather than trying to audit thoughts or whims. I know that. It is impossible to audit someone’s intentions. Or their motivations. It is only possible to audit their work output versus agreed-upon requirements. Their adherence to written policy and procedures.
I know that it is difficult to audit a Company’s “consideration” of IR drop. Difficult, but not impossible. And that gets my dander up. Why should our Recommended Practices be modified into something that they were not intended to be, just to satisfy the Regulators? Why are the legitimate technical positions and opinions of the founding members of this association being ignored and marginalized? Why do the critics not have to prove the inadequacy of the criterion before they throw it out?
It is assumed that we have a criterion problem. I’ve not seen that in my 29 years of practice. My embarrassing leaks have always been due to inadequate CP, not inadequate criteria. It’s the practice of engineering that has failed me, not the theory of engineering principles.
I for one will continue to throw my support behind the movement to restore the original 850 On criterion, as stated in the original version of RP 0169.
And by the way, the more I look into the science behind the 850 On criterion, the more I think we’d better pause and confirm once and for all its technical applicability. I’ve not seen anything yet that leads me to believe we’d better throw it out…So I’m also going to support the movement to more fully understand the science behind the 850 On criterion.
Perhaps you’ll join us?
These comments are provided by Tom Hamilton and are his comments and experiences, not those of his company.
Monday, March 24, 2008
NACE CORROSION 2008 - TG360 (SP0169) MEETING
I want thank everyone who participated in the TG 360 (SP0169) meetings last week at NACE CORROSION 2008. Hopefully we have helped the committee with making a better decision about what revisions are made to the SP0169 document.
For those that were not there or want a copy of my presentation to the committee, we will be posting that on the web very soon. It hit me Monday night (March 17) that we have in over 40 years thousands of miles of FBE coated pipelines over the world that have been in service. For the first 30 to 35 years the only criteria that was used to protect these pipelines was an "ON" -850 mV or more negative without much consideration (if any) for IR drop. Some still use this criteria today for these lines.
We have now run many ILI (smart pigs) thorough these pipe lines over last 20 years, yet find very little, if any, external corrosion on these pipelines. When external corrosion is located it is usually because of shielding from a foreign object (rocks, plastics, other metal in close proximity, high resistant soils, etc.), from other coatings (usually on girth welds or repairs) that have disbonded and shield the CP (such as solid film backed tapes, shrink sleeves, etc.) or from AC or DC interference. There are cases where inadequate CP (if any) was applied for a period of time and corrosion may have developed.
For those of you who have FBE coated pipelines, please look at this data and see what I am talking about. If we can prove this fact, this disproves the theory that we must always consider IR drop or use a Polarized -850 mV to protect our pipelines.
If these things are true would we not have extensive external corrosion on FBE coated pipelines? Especially where FBE coating failure and disbondments have occurred! From my experiences and discussions with many companies external corrosion is a very rare occurrence on FBE coated pipelines. This also proves the validity of using pipelines coatings when possible that have proven non-shielding (to CP) properties if disbondments occur(such as FBE or Polyguard RD-6).
There is nothing in this industry that is 100%. I am sure there are some rare instances where external corrosion has occurred that cannot be explained. In those cases none of the criteria would have likely worked.
Pipelines coated with coatings other than FBE still have external corrosion occurring, but again these are in areas of disbonded coating that is still shielding the CP. In these cases, increasing cathodic protection will have minimal affect in most cases.
The point here is that increasing the amount of CP or changing to a more stringent criteria will not give the end user much BANG for their BUCK. The scales are weighted in this argument on the side of leaving the criteria as it stands and using better tools (ILI and ECDA) and training for those responsible to actually be able to control the external corrosion problems without tying their hands to more stringent criteria. Using these tools to find areas of shielding (whether coatings or other) and correcting those areas by recoating with coatings that have proven non-shielding properties will help eliminate many of the ongoing external corrosion problems.
I will ask anyone who has data, reports and papers that can be posted on this site to please send those, but more importantly send this data to the committee. By the way this site accepts comments from all sides of this issue, not just opposition to these changes. We all learn from those who study this issue and who have written papers and made presentations in support of the proposed changes. There are times when considering IR drop and using a polarized -850mV criterion are needed and valid, but I do feel these are rare occurrences.
Richard Norsworthy
For those that were not there or want a copy of my presentation to the committee, we will be posting that on the web very soon. It hit me Monday night (March 17) that we have in over 40 years thousands of miles of FBE coated pipelines over the world that have been in service. For the first 30 to 35 years the only criteria that was used to protect these pipelines was an "ON" -850 mV or more negative without much consideration (if any) for IR drop. Some still use this criteria today for these lines.
We have now run many ILI (smart pigs) thorough these pipe lines over last 20 years, yet find very little, if any, external corrosion on these pipelines. When external corrosion is located it is usually because of shielding from a foreign object (rocks, plastics, other metal in close proximity, high resistant soils, etc.), from other coatings (usually on girth welds or repairs) that have disbonded and shield the CP (such as solid film backed tapes, shrink sleeves, etc.) or from AC or DC interference. There are cases where inadequate CP (if any) was applied for a period of time and corrosion may have developed.
For those of you who have FBE coated pipelines, please look at this data and see what I am talking about. If we can prove this fact, this disproves the theory that we must always consider IR drop or use a Polarized -850 mV to protect our pipelines.
If these things are true would we not have extensive external corrosion on FBE coated pipelines? Especially where FBE coating failure and disbondments have occurred! From my experiences and discussions with many companies external corrosion is a very rare occurrence on FBE coated pipelines. This also proves the validity of using pipelines coatings when possible that have proven non-shielding (to CP) properties if disbondments occur(such as FBE or Polyguard RD-6).
There is nothing in this industry that is 100%. I am sure there are some rare instances where external corrosion has occurred that cannot be explained. In those cases none of the criteria would have likely worked.
Pipelines coated with coatings other than FBE still have external corrosion occurring, but again these are in areas of disbonded coating that is still shielding the CP. In these cases, increasing cathodic protection will have minimal affect in most cases.
The point here is that increasing the amount of CP or changing to a more stringent criteria will not give the end user much BANG for their BUCK. The scales are weighted in this argument on the side of leaving the criteria as it stands and using better tools (ILI and ECDA) and training for those responsible to actually be able to control the external corrosion problems without tying their hands to more stringent criteria. Using these tools to find areas of shielding (whether coatings or other) and correcting those areas by recoating with coatings that have proven non-shielding properties will help eliminate many of the ongoing external corrosion problems.
I will ask anyone who has data, reports and papers that can be posted on this site to please send those, but more importantly send this data to the committee. By the way this site accepts comments from all sides of this issue, not just opposition to these changes. We all learn from those who study this issue and who have written papers and made presentations in support of the proposed changes. There are times when considering IR drop and using a polarized -850mV criterion are needed and valid, but I do feel these are rare occurrences.
Richard Norsworthy
Friday, March 14, 2008
Commentary on SP0169
COMMENTARY ON SPO169 PROPOSED REVISION
BY
RICHARD NORSWORTHY
ABSTRACT
As important as cathodic protection criteria is to external corrosion control, it may not be the most important issue facing those concerned with proposed changes to SP0169-2002(7). The document clearly states the intent of the document is effective control of external corrosion. Many seem to ignore the intent of this document and concern themselves only with cathodic protection and related criteria. Changes are needed in this document, but most are not in criteria section.
As we struggle with the proper revision of this very controversial Standard Practice we must not lose site of the purpose of this NACE Standard. This standard practice presents procedures and practices for achieving effective control of external corrosion on buried or submerged metallic piping systems. Confusion remains over the intent of this Standard Practice.
As important as cathodic protection is to buried and submerged structures that are also coated, it is not the most important factor in controlling external corrosion. Some consider design along with electrical isolation to be the most important. Pipeline coatings actually protect more pipelines from external corrosion than cathodic protection and electrical isolation. Coatings are often thought of as the “first line of defense” in the war against corrosion.
Each protection method is important in controlling external corrosion on pipelines and related structures. Each has a particular role, but must be used in conjunction with the others to successfully protect these structures. Nearly all companies must deal with pipeline systems that are over tens years old. Most companies have operating pipelines over fifty years old, which means the electrical isolation, the cathodic protection system and the coating systems (if used) have out lived their design life.
DESIGN
In the design phase of a project, the proper use of all these factors must be considered to control external corrosion. Electrical isolation when properly used allows the cathodic protection to be effective and economical on that part of the structure it is intended to protect and not be consumed by foreign or un-intended metal structures.
COATINGS
If coatings are properly selected and applied to the pipeline before and during construction, the amount of cathodic protection needed is considerably less. This section of the SP0169 should be stronger to provide guidance for selecting pipeline coatings for new pipe, girth welds, rehabilitation and repair. Since corrosion under disbonded coating is a major cause of external corrosion, one must consider how effective the CP system will be if the coating adhesion were to fail. Will the CP system be effective in controlling external corrosion under disbonded coating if electrolyte penetrates? Most pipeline coatings shield cathodic protection when disbondments occur. Some coating systems are non-shielding and compatible with CP if a disbondment occurs therefore the corrosion rate is significantly reduced or eliminated. Ideally, these two systems work together so that if the coating disbonds allowing ground water to contact the pipe surface the CP system will continue to function. These are called non-shielding, CP friendly, CP compatible, fail safe or partially shielding pipeline coatings.
CATHODIC PROTECTION
CP systems are designed around the coated pipeline using all the related equations and past experiences. CP current is only effective where it has a path to the pipe. Pipeline coating systems must have electrical insulating or dielectric strength in order to divert the CP current to the areas of the pipe where the coating has holidays or damage that exposes the metal to the current. Disbonded, shielding coatings do not allow sufficient current to the pipe steel therefore external corrosion becomes a problem.
Non-shielding coatings, will allow enough CP current to significantly reduce or eliminate corrosion on the pipe metal if the coating disbonds and electrolyte penetrates. This requirement has lead to the distinction between coatings that shield the pipe from the CP system and those that are classified as permeable or CP-compatible.
SHIELDING VERSUS NON-SHIELDING PIPELINE COATINGS
There have been numerous articles written about CP shielding and the corrosion problems that develop. Many articles have also been written about the value of using pipeline coatings that are non-shielding. Only a few are referenced in this article. The relative tendency of pipeline girth weld coatings to shield cathodic protection (CP) current was studied in the laboratory. A key consideration should be "Will the coating shield CP if the bond fails? '' However, all coatings experience some disbondment and, therefore, the behavior of a disbonded coating is important in the overall performance of a coating system. Even with adequate cathodic protection (CP), corrosion can occur under most disbonded coatings. With adequate CP, fusion bonded epoxies (FBE) do not totally shield CP currents ; therefore corrosion is not a major problem. However, FBE maintains its insulation properties in the presences of moisture and cathodic protection current.
TODAY’S TECHNOLOGY
Internal line inspection tools (ILI) and External Corrosion Direct Assessment (ECDA) allows companies to see the condition of pipelines, no matter the age. In some cases, external corrosion is a significant issue. CP may not have been adequate, especially in the early days, because of a lack of knowledge, improper design and monitoring. Too many companies use CP as a “cure all” for external corrosion on coated pipelines, but find out they still have active external corrosion through ILI or ECDA. Today, inadequate CP is rarely the cause of external corrosion.
Stray currents from DC or AC sources cause corrosion problems. Shielding of the CP current by soils, rocks, and other non-conductive materials may be the reason for external corrosion. Even though the US Department of Transportation regulations call for use of ‘non-shielding coating’ most pipeline coating companies do not understand or test coatings for potential CP shielding problems. Slight water absorption only corrodes steel if the cathodic protection is not adequate, or if electrical shielding is present. The industry is beginning to recognize the importance of selecting pipeline coatings that allow CP to be effective, if there is disbondment.
EFFECTIVE EXTERNAL CORROSION CONTROL
As more and more companies begin to realize many of their external corrosion problems are not from lack of CP, but from other causes, they can more effectively spend their dollars and man power. There are great examples of this problem. A close internal survey found inadequate CP. The pipe is exposed, to find deteriorated pipeline coatings which have allowed pipe metal to be exposed to the electrolyte, but there is no external corrosion, because the CP could effectively protect the exposed metal even though it showed to be inadequate. Where criterion is achieved, external corrosion was located through ILI or ECDA. This corrosion is usually caused by disbonded, coatings that are shielding the CP therefore the CP was adequate. ILI on a newer pipeline coated with FBE show no corrosion except at the girth welds where a shielding coating was used. Adding more CP or changing criterion will not stop this corrosion! Field inspection to renew or repair badly deteriorated coatings is crucial in reducing pipeline corrosion.
DO WE NEED TO CHANGE THE CRITERIA?
Criteria as stated in SP0169-2007 are sufficient for controlling corrosion if CP current is allowed to be effective. Proper educate of corrosion control and pipeline integrity personnel to identify the actual cause of external corrosion is more critical than changing criteria.
Taking the pH under any disbonded coating is a very good indicator of CP effectiveness. An alkaline or high pH (9 to 13), on the pipe surface or under disbonded coating is an indication that CP current is effective and corrosion is reduced or eliminated. If less than a pH of 9, corrosion is possible. The lower the pH the more likely corrosion will be a problem.
Field data derived from pipe exposures with actual CP potentials taken at the time of the excavation will indicate if adequate protection is being achieved. These potentials along with pH readings (especially under disbonded coating) and proper evaluation of the coating will indicate if CP is adequate. ILI tools find possible points of external corrosion that must be properly evaluated before increasing CP. External corrosion is rarely present under coatings that are compatible with CP.
CONCLUSIONS
Adding more CP does not control all external corrosion problems. More CP may cause further disbondment exposing more pipe to possible corrosion because of the shielding affects of the coating. The industry is misappropriating many dollars on un-needed CP to meet a certain criterion, instead of rehabilitating pipeline coatings that shield CP, correcting other shielding situations, interference, shorted casings, metal shorts, or failed electrical isolation devices. Meeting CP criteria does not solve most external corrosion.
The role of effective pipeline coatings is often overlooked when evaluating external corrosion. When ILI tools or ECDA show no indications of external corrosion under disbonded or blistered coatings with electrolyte under the coating, these are non-shielding coatings. The pH of this water is usually 9 or above. Under shielding coatings corrosion is usually found and the pH is under 7. Therefore, the committee and industry should concentrate more effort on using non-shielding coatings and replacing shielding coatings that have disbonded to allow CP to be effective and effectively control external corrosion.
SP0169 - 2007
G. Mills, “The Role of The Pipe Coating as an Engineered Part of The Cathodic Protection System”; NACE CORROSION 88; Paper 237
T. Jack, F. King, M. Kolar, and R. Worthingham; “A Permeable Coating Model For Predicting the Environment at the Pipe Surface Under CP-Compatible Coatings”; NACE CORROSION 2004; Paper # 04158.
T. Jack, F. King, Y. Cheng, and R. Worthingham, “Permeable Coatings and CP Compatibility. Proc. IPC ’02 4th International Pipeline Conference, (ASME, New York, NY 2002), paper IPC2002-27267, pps. ,1889-1893.
G.R. Ruschau and Y.Chen, “Determining The CP Shielding Behavior of Pipeline Coatings in The Laboratory”; CORROSION 2006; Paper 06043
D.P. Moore, "Cathodic Shielding Can Be a Major Problem After a Coating Fails",
Materials Performance 39, 4 (2000): pg. 44
J. A. Beavers & N. G. Thompson, ""Corrosion Beneath Disbonded Pipeline Coatings",
Materials Performance April 1997, pg. 13
R. Norsworthy, “Select Effective Pipeline Coatings”; Hart’s Pipeline Digest, February 1997, pg 17
T. A. Pfaff, “FBE Serves a Broad Market”; Hart’s Pipeline Digest, October 1996, pg. 2
J. Alan Kehr, “Fusion Bonded Epoxy (FBE) – A Foundation for Pipeline Corrosion
Protection”; NACE Press, pg 471 vii Page 55
R. Norsworthy, “Proven Protection”, World Pipelines, October 2007, pg. 49
“Coatings Used in Conjunction with Cathodic Protection”; NACE Technical Committee Report; July 2000; pg. 4
D. Song, F. M. Song, D. W. Kirk, and D. E. Cormack; “Barrier Properties of Two Field Pipeline Coatings”; Materials Performance, April 2005, pg 26
BY
RICHARD NORSWORTHY
ABSTRACT
As important as cathodic protection criteria is to external corrosion control, it may not be the most important issue facing those concerned with proposed changes to SP0169-2002(7). The document clearly states the intent of the document is effective control of external corrosion. Many seem to ignore the intent of this document and concern themselves only with cathodic protection and related criteria. Changes are needed in this document, but most are not in criteria section.
As we struggle with the proper revision of this very controversial Standard Practice we must not lose site of the purpose of this NACE Standard. This standard practice presents procedures and practices for achieving effective control of external corrosion on buried or submerged metallic piping systems. Confusion remains over the intent of this Standard Practice.
As important as cathodic protection is to buried and submerged structures that are also coated, it is not the most important factor in controlling external corrosion. Some consider design along with electrical isolation to be the most important. Pipeline coatings actually protect more pipelines from external corrosion than cathodic protection and electrical isolation. Coatings are often thought of as the “first line of defense” in the war against corrosion.
Each protection method is important in controlling external corrosion on pipelines and related structures. Each has a particular role, but must be used in conjunction with the others to successfully protect these structures. Nearly all companies must deal with pipeline systems that are over tens years old. Most companies have operating pipelines over fifty years old, which means the electrical isolation, the cathodic protection system and the coating systems (if used) have out lived their design life.
DESIGN
In the design phase of a project, the proper use of all these factors must be considered to control external corrosion. Electrical isolation when properly used allows the cathodic protection to be effective and economical on that part of the structure it is intended to protect and not be consumed by foreign or un-intended metal structures.
COATINGS
If coatings are properly selected and applied to the pipeline before and during construction, the amount of cathodic protection needed is considerably less. This section of the SP0169 should be stronger to provide guidance for selecting pipeline coatings for new pipe, girth welds, rehabilitation and repair. Since corrosion under disbonded coating is a major cause of external corrosion, one must consider how effective the CP system will be if the coating adhesion were to fail. Will the CP system be effective in controlling external corrosion under disbonded coating if electrolyte penetrates? Most pipeline coatings shield cathodic protection when disbondments occur. Some coating systems are non-shielding and compatible with CP if a disbondment occurs therefore the corrosion rate is significantly reduced or eliminated. Ideally, these two systems work together so that if the coating disbonds allowing ground water to contact the pipe surface the CP system will continue to function. These are called non-shielding, CP friendly, CP compatible, fail safe or partially shielding pipeline coatings.
CATHODIC PROTECTION
CP systems are designed around the coated pipeline using all the related equations and past experiences. CP current is only effective where it has a path to the pipe. Pipeline coating systems must have electrical insulating or dielectric strength in order to divert the CP current to the areas of the pipe where the coating has holidays or damage that exposes the metal to the current. Disbonded, shielding coatings do not allow sufficient current to the pipe steel therefore external corrosion becomes a problem.
Non-shielding coatings, will allow enough CP current to significantly reduce or eliminate corrosion on the pipe metal if the coating disbonds and electrolyte penetrates. This requirement has lead to the distinction between coatings that shield the pipe from the CP system and those that are classified as permeable or CP-compatible.
SHIELDING VERSUS NON-SHIELDING PIPELINE COATINGS
There have been numerous articles written about CP shielding and the corrosion problems that develop. Many articles have also been written about the value of using pipeline coatings that are non-shielding. Only a few are referenced in this article. The relative tendency of pipeline girth weld coatings to shield cathodic protection (CP) current was studied in the laboratory. A key consideration should be "Will the coating shield CP if the bond fails? '' However, all coatings experience some disbondment and, therefore, the behavior of a disbonded coating is important in the overall performance of a coating system. Even with adequate cathodic protection (CP), corrosion can occur under most disbonded coatings. With adequate CP, fusion bonded epoxies (FBE) do not totally shield CP currents ; therefore corrosion is not a major problem. However, FBE maintains its insulation properties in the presences of moisture and cathodic protection current.
TODAY’S TECHNOLOGY
Internal line inspection tools (ILI) and External Corrosion Direct Assessment (ECDA) allows companies to see the condition of pipelines, no matter the age. In some cases, external corrosion is a significant issue. CP may not have been adequate, especially in the early days, because of a lack of knowledge, improper design and monitoring. Too many companies use CP as a “cure all” for external corrosion on coated pipelines, but find out they still have active external corrosion through ILI or ECDA. Today, inadequate CP is rarely the cause of external corrosion.
Stray currents from DC or AC sources cause corrosion problems. Shielding of the CP current by soils, rocks, and other non-conductive materials may be the reason for external corrosion. Even though the US Department of Transportation regulations call for use of ‘non-shielding coating’ most pipeline coating companies do not understand or test coatings for potential CP shielding problems. Slight water absorption only corrodes steel if the cathodic protection is not adequate, or if electrical shielding is present. The industry is beginning to recognize the importance of selecting pipeline coatings that allow CP to be effective, if there is disbondment.
EFFECTIVE EXTERNAL CORROSION CONTROL
As more and more companies begin to realize many of their external corrosion problems are not from lack of CP, but from other causes, they can more effectively spend their dollars and man power. There are great examples of this problem. A close internal survey found inadequate CP. The pipe is exposed, to find deteriorated pipeline coatings which have allowed pipe metal to be exposed to the electrolyte, but there is no external corrosion, because the CP could effectively protect the exposed metal even though it showed to be inadequate. Where criterion is achieved, external corrosion was located through ILI or ECDA. This corrosion is usually caused by disbonded, coatings that are shielding the CP therefore the CP was adequate. ILI on a newer pipeline coated with FBE show no corrosion except at the girth welds where a shielding coating was used. Adding more CP or changing criterion will not stop this corrosion! Field inspection to renew or repair badly deteriorated coatings is crucial in reducing pipeline corrosion.
DO WE NEED TO CHANGE THE CRITERIA?
Criteria as stated in SP0169-2007 are sufficient for controlling corrosion if CP current is allowed to be effective. Proper educate of corrosion control and pipeline integrity personnel to identify the actual cause of external corrosion is more critical than changing criteria.
Taking the pH under any disbonded coating is a very good indicator of CP effectiveness. An alkaline or high pH (9 to 13), on the pipe surface or under disbonded coating is an indication that CP current is effective and corrosion is reduced or eliminated. If less than a pH of 9, corrosion is possible. The lower the pH the more likely corrosion will be a problem.
Field data derived from pipe exposures with actual CP potentials taken at the time of the excavation will indicate if adequate protection is being achieved. These potentials along with pH readings (especially under disbonded coating) and proper evaluation of the coating will indicate if CP is adequate. ILI tools find possible points of external corrosion that must be properly evaluated before increasing CP. External corrosion is rarely present under coatings that are compatible with CP.
CONCLUSIONS
Adding more CP does not control all external corrosion problems. More CP may cause further disbondment exposing more pipe to possible corrosion because of the shielding affects of the coating. The industry is misappropriating many dollars on un-needed CP to meet a certain criterion, instead of rehabilitating pipeline coatings that shield CP, correcting other shielding situations, interference, shorted casings, metal shorts, or failed electrical isolation devices. Meeting CP criteria does not solve most external corrosion.
The role of effective pipeline coatings is often overlooked when evaluating external corrosion. When ILI tools or ECDA show no indications of external corrosion under disbonded or blistered coatings with electrolyte under the coating, these are non-shielding coatings. The pH of this water is usually 9 or above. Under shielding coatings corrosion is usually found and the pH is under 7. Therefore, the committee and industry should concentrate more effort on using non-shielding coatings and replacing shielding coatings that have disbonded to allow CP to be effective and effectively control external corrosion.
SP0169 - 2007
G. Mills, “The Role of The Pipe Coating as an Engineered Part of The Cathodic Protection System”; NACE CORROSION 88; Paper 237
T. Jack, F. King, M. Kolar, and R. Worthingham; “A Permeable Coating Model For Predicting the Environment at the Pipe Surface Under CP-Compatible Coatings”; NACE CORROSION 2004; Paper # 04158.
T. Jack, F. King, Y. Cheng, and R. Worthingham, “Permeable Coatings and CP Compatibility. Proc. IPC ’02 4th International Pipeline Conference, (ASME, New York, NY 2002), paper IPC2002-27267, pps. ,1889-1893.
G.R. Ruschau and Y.Chen, “Determining The CP Shielding Behavior of Pipeline Coatings in The Laboratory”; CORROSION 2006; Paper 06043
D.P. Moore, "Cathodic Shielding Can Be a Major Problem After a Coating Fails",
Materials Performance 39, 4 (2000): pg. 44
J. A. Beavers & N. G. Thompson, ""Corrosion Beneath Disbonded Pipeline Coatings",
Materials Performance April 1997, pg. 13
R. Norsworthy, “Select Effective Pipeline Coatings”; Hart’s Pipeline Digest, February 1997, pg 17
T. A. Pfaff, “FBE Serves a Broad Market”; Hart’s Pipeline Digest, October 1996, pg. 2
J. Alan Kehr, “Fusion Bonded Epoxy (FBE) – A Foundation for Pipeline Corrosion
Protection”; NACE Press, pg 471 vii Page 55
R. Norsworthy, “Proven Protection”, World Pipelines, October 2007, pg. 49
“Coatings Used in Conjunction with Cathodic Protection”; NACE Technical Committee Report; July 2000; pg. 4
D. Song, F. M. Song, D. W. Kirk, and D. E. Cormack; “Barrier Properties of Two Field Pipeline Coatings”; Materials Performance, April 2005, pg 26
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