UPDATE ON TG-360 COMMITTEE MEETING - MARCH 15, 2011
NACE SP0169-2007 REVISION
Draft # 3D January 2011
The TG 360 committee meeting on March 15 at CORROSION 2011 presented us with a new version of the document that addressed many of the negatives from the most recent ballot. I like most of the changes made to the document. The committee worked on more changes during the meeting, but hopefully there were no major changes.
Remember this is still in the DRAFT form and has not been approved. The TG-360 will continue to work on the document. Not sure when the new one will be out for viewing and voting.
There will be a new version out to vote when the committee has time to discuss the changes from the comments made at the TG-360 meeting and address the remaining negatives. Hopefully this will be sometime in May/June time frame if not before. I know we are all ready to get this document out the door!
I am not sure when the new version will be ready, but here are some things that I liked about the most recent changes (on the document handed out at the meeting) and some that I would like to see changed or improved.
The underlined areas are the changes from the voted on version.
The (CAPITAL LETTERING AND regular) will be my comments about some of the sections.
6.1.1 This section lists criteria for CP that indicate whether adequate CP of a metallic piping system has been achieved (see also Section 1, Paragraphs 1.2 and 1.4). Adequate cathodic protection can be achieved at various levels of cathodic polarization depending on the environmental conditions. As such, situations may exist where a single criterion for evaluating the effectiveness of CP may not be satisfactory for all conditions or at all locations along a structure. The use of any approach, including a combination of methods or criteria to achieve adequate corrosion control is the responsibility of the user, and should be based on the experience of the user and the unique conditions influencing their piping systems. In determining if adequate corrosion control has been achieved, the conditions and factors listed in Paragraph 6.2.1.3.1.2 should be considered regardless of what methods or criteria are used. (I LIKE THIS STATEMENT AND THOSE IN 6.2.1.3.1.2)
6.1.2 In selecting the methods or criteria for a specific pipeline, it is the responsibility of the owner to determine whether that level of corrosion control is necessary or sufficient to address the specific conditions. (THIS IS ANOTHER GOOD STATEMENT)
6.1.3 Measurement techniques for evaluating compliance with cathodic protection criteria, and methods for demonstrating that adequate polarization has been achieved are covered in NACE Standard TM0497,“Measurement Techniques Related to Criteria for Cathodic Protection on Underground or SubmergedMetallic Piping Systems.” Fundamental research62 has demonstrated that achieving a polarized potential atleast as negative as -0.850 mV Volt cse or at least 100 mV of cathodic polarization can be expected to reduce the residual general corrosion rate to 1 mil per year (0.025 mm per year) or less.
(I HAVE A PROBLEM WITH LEAVING THIS STATEMENT IN THE CRITERIA SECTION. If the committee will move this to another section or in the Appendix and give some more information of why it is in the document, then I think I would be OK with it. I am not saying it is wrong, but just too many variables involved in getting this data correctly and then trying to apply it to a pipeline. I have made this argument before and have discussed with those who promote it, but they have not convinced me it needs to be in the criteria section.)
6.1.4 In selection of a method or criterion as listed in Paragraph 6.2, it is important that the user includes a means to evaluate the effectiveness of any that method or criterion, whether used separately or in combination. The effectiveness of CP or other external corrosion control measures should be documented. In the absence of such documentation, at least one of the criteria in Paragraph 6.2 shall apply.
6.2.1.1 Criteria that have been documented to successfully control corrosion through empirical evidence on specific piping systems may be used on those piping systems or others with the same characteristics.
6.2.1.2 A minimum of 100 mV of cathodic polarization. Either the formation or the decay of polarization must be measured to satisfy this criterion.
6.2.1.3 A structure-to-electrolyte potential of –850 mV or more negative as measured with respect to a saturated copper/copper sulfate (CSE) reference electrode. This potential may be either a direct measurement of the polarized instant-off potential or a current-applied potential.
Interpretation of a current applied measurement requires consideration of the significance of voltage drops in the earth and metallic paths.
6.2.1.3.1 Consideration is understood to mean the application of sound engineering practice by either of the following:
6.2.1.3.1.1 Measuring or calculating the voltage drop(s) to establish whether a –850 mV potential across the structure-to-electrolyte boundary has been achieved, or
6.2.1.3.1.2 Performing a technical evaluation of the system, including data and information, such as the following that are considered necessary and sufficient for the situation:
6.2.1.3.1.2.1 Reviewing the historical performance of the cathodic protection system, such as: type of cathodic protection; consistency with time of the potentials at individual test points along the line, consistency of cathodic protection current over time, number of years with cathodic protection; remedial cathodic protection activities; consistency of CIS over time, and external corrosion related leak history. (Note: Leak history should not be used as the sole means of determining adequate
levels of cathodic protection). When reviewing the historical performance of the cathodic protection system, physical characteristics and results of direct examinations and the environment should also be considered.
6.2.1.3.1.2.2 Determining if there is physical evidence of corrosion, such as: by direct examination to determine evidence of active corrosion, and correlation of direct examination data with other data such as: close-interval surveys, direct current voltage gradient surveys, and in-line inspection results. When direct examinations are used, the number and extent of the examinations performed as well as a comparison of the
environments and their relevance should be considered.
6.2.1.3.1.2.3 Evaluating the physical and electrical characteristics of the pipe and its environment, such as: type of electrolyte, electrolyte resistivity, pH, dissolved oxygen content, moisture content, degree of aeration, differences in pipe metallurgy and installation dates, and variations in coating types and condition.
6.2.1.3.1.2.4 Physical characteristics and operational data, such as: coated or bare, type of coating and possibility to shield cathodic protection, proximity to other lines, especially other lines in the right-of-way, temperature of the pipe, depth of the pipe, proximity to potential stray current sources such as light rail systems, HVAC and HVDC systems, foreign structures with cathodic protection, proximity and electrical
isolation with structures of varying metals where mixed metal potentials may be a concern, locations where concrete weights and anchors may be installed, and changes in operating conditions over time. Construction related information alone may not provide sufficient information to adequately evaluate the effectiveness of cathodic protection, but should be considered during direct examinations and reviewing historical performances.
6.2.1.3.1.2.5 Evaluation of indirect inspection data, such as: above-grade electrical surveys, in-line inspection, and direct assessment.
6.2.1.3.1.2.6 Use of coupons to establish such things as: levels of current density, free corrosion potential, levels of polarization, corrosion rates, and comparisons between coupon and pipe potentials.
6.2.1.3.1.2.7 Other methods that confirm that sufficient polarization has been achieved to control corrosion.
(THIS INFORMATION ADDS GREAT OPPORTUNITY FOR THE END USER TO APPLY SOUND ENGINEERING PRACTICES AS PER EACH PARTICULAR PIPELINE SYSTEM AND ALLOWS FOR USE OF BASICALLY ANY CRITERION THAT PROVIDES THERE IS NO OR VERY LIMITED AND CONTROLLABLE CORROSION. This does not limit the end-user to only two choices, but places the burden on the end user to provide proof that their particular program is working. We must keep in mind that corrosion control is an ongoing battles that involves many phases of control.)
6.2.1.4.9 When operating pressure and conditions are conducive to high pH stress corrosion cracking, the use of polarized potentials in the cracking range relative to the temperature indicated in Figure 1is not advised.
(THIS AREA JUST NEEDS MORE EXPLAINATION. I AGREE IT IS A VERY IMPORTANT ISSUE AND IS A CONCERN WHEN USING POLARIZED POTENTIAL CRITERION. WE NEED TO MAKE SURE THAT EVERYONE WHO SEES THIS UNDERSTANDS THERE ARE MANY VARIBLES AND CONDITIONS THAT MUST EXIST FOR SCC TO OCCUR. It is always a challenge to place something like this in a standard and give enough information for it to be useful. I would like to hear some other thought on this since I am certainly not the expert on SCC.)
6.4 Alternative Reference Electrodes
6.4.1 Other standard reference electrodes may be substituted for the CSE. Three commonly used portable reference electrodes are listed below. along with tRefer to Table 2 for their voltage equivalents (at 25 °C [77 °F]) to –850 mV referred to a CSE:
6.4.1.1 Saturated KCl calomel reference electrode: –780 mV; and
6.4.1.2 Saturated silver/silver chloride reference electrode used in 25 Ω.cm seawater: –756 mV.
6.4.1.3 Zinc reference electrode; often used as a permanent reference electrode58
6.4.2 In addition to these standard reference electrodes, an alternative metallic element in an electrolyte of fixed concentration may be used in place of the CSE, if the stability of its electrode potential is ensured and if its voltage equivalent referred to a CSE is established.
6.4.3 In situations in which the temperature of the reference electrode is below 15 °C (59 °F) and above 35 °C (95 °F), refer to Table 2.
Table 2 (TABLE 2 WOULD NOT FORMAT PROPERLY, BUT YOU CAN LOOK AT THE VOTED ON VERSION)
Examples: –850 mV CSE measured at 100 °F (37.8 °C) would be corrected to –839.5 –838.5 mV (the actual potential is 11.5 mV less negative than the reading), while –850 mV measured at 40 °F (4.4 °C) would be corrected to –868.5 mV (18.5 mV more negative than the reading).
(This is a very confusing table and issue for many. I think is important, but the companies that make the reference cells do not even like the table and do not consider it correct. Not sure how to approach this one, but again we need to keep it simple. There are so many variables when using reference cells that we need a complete Standard on just reference cells! Look at the variables with zinc [+/- 100 mV] and that does not even take into account the other problems with ZRE. Let’s see what happens.)
I personally think the committee is on the right path and hope to be able to support the next revision. Of course others will not. Hopefully, they will comment also so we can continue to learn and share knowledge.
I also want to thank all for the support and kind words at CORROSION 2011. The SP0169.com blog site would not be successful without every ones support and efforts.
Please let me know if I can help in any way!
Richard Norsworthy
Polyguard Products, Inc.
“We Believe in Non-Shielding Pipeline Coatings!” Go to polyguardproducts.com for more information.
Sunday, March 27, 2011
Saturday, January 1, 2011
Further comments on Mr. Gummow's article
Further comments on Mr. Gummow’s article:
As the various comments start coming in concerning Mr. Gummow’s article and my response, I thought a little follow up would be good.
First, I want to acknowledge that Bob has written a very good article that all should read. If you did not get the magazine, you can find the article by going to www.pgjonline.com. It is in the November 2010 issue. Even though I brought out some other information that was not included in the article that I feel would have made it more accurate, I do understand that when you publish such articles, there is limited space so many times information has to be left out that may have normally been included.
I believe Bob, the TG 360 committee and I all want the best document (SP0169-2007) possible for the corrosion control industry. When we have different viewpoints, we do our best to resolve our differences for the betterment of the industry. I certainly have learned much from Bob and others in the industry and hope to pass along some of this knowledge. Through challenging each other, we not only learn, but also make sure they continue to learn and grow.
Unlike some industry standards, NACE has chosen what I consider to be the best and fairest method for developing standards for the corrosion control industry. They allow all a voice! Some organizations only allow a select few to make these decisions with supposed input from industry. These committees can easily override those who disagree and force the document the direction these few have decided to take the document. If these committees do not have the correct mix of industry experience and knowledge, the document can become an industry headache. Yes, NACE is a laborious and sometimes lengthy process, which causes frustration for some in the industry. I still think the NACE process is the best for our industry, because we have been given the chance to participate by voicing our opinions and democratically voting on the document as many times as it takes!
Some certainly have agendas and want to make sure certain issues are covered in these standards. I think everyone who works on such committees should have areas of expertise and interest. Most of these are good things, but when they get out of line, the voting process brings it back to where it should be, allowing for a more comprehensive and correct document. As far as I know, there has never been a NACE Standard that was not a compromise, meaning that not everyone was happy with the outcome. That is life in a democracy. That is what makes the best overall standard for the industry. The more folks we have contributing, the better the outcome!
I know there are some of you who think this is not the way things should be done, but that is the reason your country does not have colonies anymore! Just kidding. Working together gets much more accomplished than a few dictating to the rest of us what is in their mind the “correct” way.
Neither I, nor anyone else I know of, knows all there is to know about external corrosion control on buried or submerged pipelines. For this reason we must continue to grow in our knowledge. There are many ways to learn and more than one way to do most things. Different experiences, knowledge, skills and abilities will determine how one solves a particular problem. Of course the environment and other conditions must be used to determine what the best solution for the problem should be.
There are those who never read the blog information, Bob’s article or much of anything else because they already think they know what they need to and are not willing to listen to anyone else’s view. To me, these are the most dangerous group, because they are not willing to learn from the discussion or provide further experience through their comments.
Some have accused me of playing politics and only promoting my company. I doubt these folks have ever read the comments that have been posted on the SP0169.com blog site. Yes, I have mentioned my company from time to time because they have supported this blog site by affording me time to address these critical issues and also provided the funds to start and continue this effort as a service to the external corrosion control community. I think that if you go back and read all the information I have posted, you will agree that these posts have rarely been a commercial for Polyguard Products, Inc.
By the way, what companies do you think have the most to gain should the criteria section get changed to include only a polarized -850 mV and 100 mV of polarization criterions? It will not be a coating company such as Polyguard! The companies that will really benefit are those that provide engineering, consulting services, monitoring equipment, surveys, coupon stations and other materials and equipment for the CP industry. If you think there is a conspiracy to make money, maybe you should look another direction than a small coating company.
As most of you know, I have been and will continue to be a big promoter of CP non-shielding coatings when using CP. This is a critical part of external corrosion control. “Non-Shielding” in this context means if the coating system adhesion fails and water penetrates between the pipe and the coating, corrosion on the pipe is significantly reduced or eliminated because cathodic protection (CP) current is able to protect the pipeline in these disbonded areas. It is amazing to me the number folks in this industry that do not understand the concept of using pipeline coatings that are non-shielding to CP. The problem with CP shielding continues to be a major problem with the pipeline industry today.
There have been and continue to be many articles written about CP shielding by most coating types being used today. The most recent one was published in the most recent Materials Performance (December 2010). The title is “Case History: Delamination Failure in a Three-Layer Coating on a 24-in Gas Pipeline”. This is an excellent paper and should be on your reading list! You may also go the polyguardproducts.com website and read many such articles that have been written on the problem with CP shielding pipeline coatings. There are many more such articles that have been written that are not posted. If you would like information on these please send me an e-mail at richnors@flash.net.
Of course, there are those who say this is just smoke and mirrors, along with a variety of other such comments. Most of these folks are with coating companies that have not been interested in this problem or accepted the fact that these problems exist. They do not understand the differences between CP shielding and non-shielding coating and continue to believe their coatings do not fail; therefore there will not be a problem. Others are strictly CP folks who think CP will solve all the external corrosion problems, even under disbonded coatings. There is an excellent NACE International course called “Coatings Used in Conjunction with Cathodic Protection” that discusses many of these issues and would be an excellent course for those who need to better understand relationship of coatings and how the two technologies work together to provide external corrosion control. This course also discusses how the coatings sometimes do not allow the CP to be effective.
All coatings are good. All coatings are bad. There are no perfect coatings. All coatings used with CP have to shield the CP current while adhered. The failure mood of the coating is critical. Does it fail in a way CP can be effective or not? Once again, I challenge you to read the articles and learn more about this problem. Closing your minds to this means the problem will only continue. Why do you think the US Department of Transportation now calls for “non-shielding” coating if a company wants to increase the Maximum Allowable Operating Pressure on pipelines from 72% to 80%? Some are starting to understand there is a choice.
There are coating types that have been proven and continue to be proven to be non-shielding when CP is adequate. The most well-known is fusion bonded epoxy. We now have 50 years of proof of the non-shielding properties of FBE. We also have 23 years of proof of the Polyguard RD-6 coating system having non-shielding properties. Though these may not be 100% in all situations, they do show there are non-shielding coating types should the coating be improperly applied, improper surface preparation, poor selection criteria, etc. Please take time to read more articles about these issues instead of just assuming it is “smoke and mirrors”. I have been promoting the use of non-shielding coatings long before I was employed by Polyguard Products, Inc., but am proud to now be associated with a company that has recognized the value of such coatings. WE BELIEVE IN "NON-SHIELDING"!
There are those who continue to reject the use of the “ON” -850 mV as viable criterion. They seem to think this is all about old technology and that it has no scientific value. My position has been and will continue to be that this criterion has a great track record of over 60 years and has been proven in the field to be very effective when properly used! Those who believe in only polarized potentials also continue to have external corrosion problems because of improper use, shielding, improper monitoring, and use of untrained personnel. There is not a perfect criterion.
The answer is to allow companies to use what has been effective for them in controlling their external corrosion and to continue to learn and train those responsible for these processes to use proper technics, equipment and interpretation of these results. We must NOT restrict companies to criteria that are not practical for many systems, especially those protected with galvanic anodes. Some say coupons are the answer for these companies. Coupons are a very good tool, but do not provide all the information needed and are not pipelines! Much of this has already been posted and discussed.
I want to personally challenge those “experts” that think I am only trying to delay the process or use the SP0169.com blog only as a commercial venture for my company, to provide input to the discussion so we can learn from what they know. We have to all be willing to work together and share our knowledge, no matter where you work, no matter the amount of experience, ability or skills. We all have something to offer, question or challenge.
This is what the SP0169.com blog is all about. There are those who do not feel comfortable in front the TG 360 committee, but will provide comments and ask questions through this process. Some on the committee can intimidate members who are at these meetings and would like to address the issues and ask questions. I am not saying that those on the committee intentionally intimidate anyone, but there have been times when this has happened. The blog can be anonymous or you can leave information and identify yourself.
Posts are reviewed by me. I will post all comments that are about external corrosion and do not directly say bad (in my judgment) things about anyone, NACE or the committee. It is fine to be generically frustrated and there are times when your comments need to be directed to particular events and comments, but these comments can be made in decent and reasonable ways.
I wish everyone a very enjoyable and wonderful 2011! Let’s work together to get the NACE SP0169 revision completed. Then we can begin the process of revising theTM0497 to compliment the SP0169!
Thank you for the opportunity to work with you and communicate our ideas about this very important document for the external corrosion control industry!
Richard Norsworthy
Polyguard Products, Inc.
NACE International Corrosion Specialist
As the various comments start coming in concerning Mr. Gummow’s article and my response, I thought a little follow up would be good.
First, I want to acknowledge that Bob has written a very good article that all should read. If you did not get the magazine, you can find the article by going to www.pgjonline.com. It is in the November 2010 issue. Even though I brought out some other information that was not included in the article that I feel would have made it more accurate, I do understand that when you publish such articles, there is limited space so many times information has to be left out that may have normally been included.
I believe Bob, the TG 360 committee and I all want the best document (SP0169-2007) possible for the corrosion control industry. When we have different viewpoints, we do our best to resolve our differences for the betterment of the industry. I certainly have learned much from Bob and others in the industry and hope to pass along some of this knowledge. Through challenging each other, we not only learn, but also make sure they continue to learn and grow.
Unlike some industry standards, NACE has chosen what I consider to be the best and fairest method for developing standards for the corrosion control industry. They allow all a voice! Some organizations only allow a select few to make these decisions with supposed input from industry. These committees can easily override those who disagree and force the document the direction these few have decided to take the document. If these committees do not have the correct mix of industry experience and knowledge, the document can become an industry headache. Yes, NACE is a laborious and sometimes lengthy process, which causes frustration for some in the industry. I still think the NACE process is the best for our industry, because we have been given the chance to participate by voicing our opinions and democratically voting on the document as many times as it takes!
Some certainly have agendas and want to make sure certain issues are covered in these standards. I think everyone who works on such committees should have areas of expertise and interest. Most of these are good things, but when they get out of line, the voting process brings it back to where it should be, allowing for a more comprehensive and correct document. As far as I know, there has never been a NACE Standard that was not a compromise, meaning that not everyone was happy with the outcome. That is life in a democracy. That is what makes the best overall standard for the industry. The more folks we have contributing, the better the outcome!
I know there are some of you who think this is not the way things should be done, but that is the reason your country does not have colonies anymore! Just kidding. Working together gets much more accomplished than a few dictating to the rest of us what is in their mind the “correct” way.
Neither I, nor anyone else I know of, knows all there is to know about external corrosion control on buried or submerged pipelines. For this reason we must continue to grow in our knowledge. There are many ways to learn and more than one way to do most things. Different experiences, knowledge, skills and abilities will determine how one solves a particular problem. Of course the environment and other conditions must be used to determine what the best solution for the problem should be.
There are those who never read the blog information, Bob’s article or much of anything else because they already think they know what they need to and are not willing to listen to anyone else’s view. To me, these are the most dangerous group, because they are not willing to learn from the discussion or provide further experience through their comments.
Some have accused me of playing politics and only promoting my company. I doubt these folks have ever read the comments that have been posted on the SP0169.com blog site. Yes, I have mentioned my company from time to time because they have supported this blog site by affording me time to address these critical issues and also provided the funds to start and continue this effort as a service to the external corrosion control community. I think that if you go back and read all the information I have posted, you will agree that these posts have rarely been a commercial for Polyguard Products, Inc.
By the way, what companies do you think have the most to gain should the criteria section get changed to include only a polarized -850 mV and 100 mV of polarization criterions? It will not be a coating company such as Polyguard! The companies that will really benefit are those that provide engineering, consulting services, monitoring equipment, surveys, coupon stations and other materials and equipment for the CP industry. If you think there is a conspiracy to make money, maybe you should look another direction than a small coating company.
As most of you know, I have been and will continue to be a big promoter of CP non-shielding coatings when using CP. This is a critical part of external corrosion control. “Non-Shielding” in this context means if the coating system adhesion fails and water penetrates between the pipe and the coating, corrosion on the pipe is significantly reduced or eliminated because cathodic protection (CP) current is able to protect the pipeline in these disbonded areas. It is amazing to me the number folks in this industry that do not understand the concept of using pipeline coatings that are non-shielding to CP. The problem with CP shielding continues to be a major problem with the pipeline industry today.
There have been and continue to be many articles written about CP shielding by most coating types being used today. The most recent one was published in the most recent Materials Performance (December 2010). The title is “Case History: Delamination Failure in a Three-Layer Coating on a 24-in Gas Pipeline”. This is an excellent paper and should be on your reading list! You may also go the polyguardproducts.com website and read many such articles that have been written on the problem with CP shielding pipeline coatings. There are many more such articles that have been written that are not posted. If you would like information on these please send me an e-mail at richnors@flash.net.
Of course, there are those who say this is just smoke and mirrors, along with a variety of other such comments. Most of these folks are with coating companies that have not been interested in this problem or accepted the fact that these problems exist. They do not understand the differences between CP shielding and non-shielding coating and continue to believe their coatings do not fail; therefore there will not be a problem. Others are strictly CP folks who think CP will solve all the external corrosion problems, even under disbonded coatings. There is an excellent NACE International course called “Coatings Used in Conjunction with Cathodic Protection” that discusses many of these issues and would be an excellent course for those who need to better understand relationship of coatings and how the two technologies work together to provide external corrosion control. This course also discusses how the coatings sometimes do not allow the CP to be effective.
All coatings are good. All coatings are bad. There are no perfect coatings. All coatings used with CP have to shield the CP current while adhered. The failure mood of the coating is critical. Does it fail in a way CP can be effective or not? Once again, I challenge you to read the articles and learn more about this problem. Closing your minds to this means the problem will only continue. Why do you think the US Department of Transportation now calls for “non-shielding” coating if a company wants to increase the Maximum Allowable Operating Pressure on pipelines from 72% to 80%? Some are starting to understand there is a choice.
There are coating types that have been proven and continue to be proven to be non-shielding when CP is adequate. The most well-known is fusion bonded epoxy. We now have 50 years of proof of the non-shielding properties of FBE. We also have 23 years of proof of the Polyguard RD-6 coating system having non-shielding properties. Though these may not be 100% in all situations, they do show there are non-shielding coating types should the coating be improperly applied, improper surface preparation, poor selection criteria, etc. Please take time to read more articles about these issues instead of just assuming it is “smoke and mirrors”. I have been promoting the use of non-shielding coatings long before I was employed by Polyguard Products, Inc., but am proud to now be associated with a company that has recognized the value of such coatings. WE BELIEVE IN "NON-SHIELDING"!
There are those who continue to reject the use of the “ON” -850 mV as viable criterion. They seem to think this is all about old technology and that it has no scientific value. My position has been and will continue to be that this criterion has a great track record of over 60 years and has been proven in the field to be very effective when properly used! Those who believe in only polarized potentials also continue to have external corrosion problems because of improper use, shielding, improper monitoring, and use of untrained personnel. There is not a perfect criterion.
The answer is to allow companies to use what has been effective for them in controlling their external corrosion and to continue to learn and train those responsible for these processes to use proper technics, equipment and interpretation of these results. We must NOT restrict companies to criteria that are not practical for many systems, especially those protected with galvanic anodes. Some say coupons are the answer for these companies. Coupons are a very good tool, but do not provide all the information needed and are not pipelines! Much of this has already been posted and discussed.
I want to personally challenge those “experts” that think I am only trying to delay the process or use the SP0169.com blog only as a commercial venture for my company, to provide input to the discussion so we can learn from what they know. We have to all be willing to work together and share our knowledge, no matter where you work, no matter the amount of experience, ability or skills. We all have something to offer, question or challenge.
This is what the SP0169.com blog is all about. There are those who do not feel comfortable in front the TG 360 committee, but will provide comments and ask questions through this process. Some on the committee can intimidate members who are at these meetings and would like to address the issues and ask questions. I am not saying that those on the committee intentionally intimidate anyone, but there have been times when this has happened. The blog can be anonymous or you can leave information and identify yourself.
Posts are reviewed by me. I will post all comments that are about external corrosion and do not directly say bad (in my judgment) things about anyone, NACE or the committee. It is fine to be generically frustrated and there are times when your comments need to be directed to particular events and comments, but these comments can be made in decent and reasonable ways.
I wish everyone a very enjoyable and wonderful 2011! Let’s work together to get the NACE SP0169 revision completed. Then we can begin the process of revising theTM0497 to compliment the SP0169!
Thank you for the opportunity to work with you and communicate our ideas about this very important document for the external corrosion control industry!
Richard Norsworthy
Polyguard Products, Inc.
NACE International Corrosion Specialist
Monday, December 13, 2010
Response to Gummow Article
RESPONSE TO BOB GUMMOW ARTICLE IN PIPELINE AND GAS JOURNAL
November 2010
R. A. (Bob) Gummow has written a very good article “Examining The Controversy Surrounding The -850 mV CP Criteria” that is published in the November 2010 Pipeline and Gas Journal. As usual Bob does a very good job of making his points while barely mentioning some well-known “facts” that do not quite fit his theory and experience. For this reason I would like to provide comments on some of his statements that may concern some in the pipeline and CP industry.
I agree with much of what is addressed in the article. The discussion is mainly about the controversy between using an “ON” -850 mV and the “polarized” -850 mV criterions. The discussion below will be about specific statements and where I believe we “MUST” discuss each side of the debate if we are to actually learn and achieve a better understanding of the proper ways to use these criteria as separate items in the NACE International SP0169 document. Even though some say there is confusion when there are two criterions using the -850 mV as the base number, most of the end users do not have this problem. When allowed to consider their specific system and what criterion actually provides the most economical and efficient process for evaluating the cathodic protection effectiveness for their system, while at the same time providing a safe environment for the pipeline and surrounding communities is the critical issue.
Statements are made that if the CP levels are such that a polarized -850 mV (or more negative potential) or proof of at least 100 mV of polarization would result in (most cases) a corrosion rate of less than 1 mil per year (mpy). This rate of corrosion has been established in several tests using coupons and no one is questioning this fact, but it is something to keep in mind while reading this response. Just how we are going to measure this on a pipeline has not been totally addresses yet.
One of the issues with using the “ON” -850 mV criterion is that of considering IR drops in the soil. There is no doubt that we can see a difference in the “ON” and instant Off potentials. Whether this difference is truly a problem is debatable. One of the problems is that we cannot easily measure the so called “instant off” or polarized potential. That is a discussion for another time.
Assuming that we can measure the instant Off effectively (mostly we try to measure it consistently), then we can subtract the instant Off from the “ON” and that value is the IR drop that is the assumed culprit. It is interesting that this is called an “error” in the “ON” potential. This is not an “error”. It is simply part of the “ON” potential. Whether it should be considered as a problem or not is up to those responsible for interpreting these potentials using their knowledge and experiences on that particular pipeline system according to all the information available, not just CP potentials. This is sound engineering practice. Forcing all to use a polarized potential because of a few tests on coupons, is not sound engineering practice.
The companies that use the “ON” potential as one of their criterion do not try to protect an entire pipeline system at an “ON” -850 mV, but use this “ON” potential as a warning sign that the protection at that site and the surrounding area needs further testing or additional CP. I have yet to see a pipeline system that could be protected at one specific potential for its entirety. It is absurd to even bring this up when discussing the “ON” -850 mV potential criterion, yet this is one argument against using it. Bob has to admit that “likely” when using this criterion the 100 mV of polarization is met or exceeded, therefore since the “ON” potentials are typically much more negative than the -850 mV, these companies are indeed considering IR drop in these potentials. The 5th paragraph under “The -850 mV cse Current Applied Criterion” addresses this fact.
Another interesting statement is when discussing the paper by Mr. Holtsbaum. In the caption under Figure 1, he states “IR Drop versus On Potentials to Illustrate a Dangerous Use of a Constant IR Drop Factor, in this case 100 mV.” I do not think the use of “Dangerous” is called for here, but if you are trying to convince folks that do not know, that you are right then you use such words to get their attention. The statement was perfectly fine without the word “Dangerous”. Had these potentials actually been allowed to depolarize there would have likely been at least 100 mV of polarization which would have proven that these potentials were not dangerous, just not complete. Since I do have copy of Mr. Holtsbaum’s paper, I do not know if this testing was performed or published in this paper.
The last sentence of the ON criterion section says, “Because of the extreme range of the IR drop on coated pipelines, the level of CP cannot be determined by the “ON” potential alone.” This statement could be interpreted to mean that using only any “ON” criterion will result in many pipeline failures. This has not been proven to be true. Yes, there have been pipeline failures on coated pipelines which use this “ON” criterion (also the polarized and 100 mV of polarization criteria), but if we could go back and actually find the root cause of the problem, we would find that most of these failures occurred because of disbonded and CP shielding pipeline coatings, interference or other shielding issues. If this statement were true, then why would companies with FBE coated pipelines not also experience these same external corrosion failure problems? Again, there have been a few external corrosion problems on FBE coated pipelines, but nearly all can be explained as AC or DC interference or shielding from other objects placed in the ditch.
From the time I started in the pipeline industry (1980) and before companies were using an “ON” -850 mV criterion for protection of most of their pipelines. Those coated with FBE starting in 1960 did not and still do not have the same external corrosion problems as those pipes coated with other coating types. This is still true today. This has been proven out through the use of many ILI tools over the last 25 years, as well as ECDA. This points out that if using non-shielding pipeline coatings such as FBE even with an “ON” -850 mV criterion, companies will rarely have external corrosion caused from inadequate CP. This particular issue is conveniently ignored by those who propose that only a polarized -850 mV criterion is the only -850 mV criterion that can be used successfully.
For the most part everyone agrees with the fact that use of the polarized -850 mV criterion would result in more polarization and in some cases would certainly be a better choice. Of course, we must also understand that there can be problems when using this criterion just like when using the “ON” -850 mV. These facts are also conveniently left out of this article, but should be part of any discussion of this topic.
In the section on the comparison of the two -850 mV criterion, the statement is made that there have been no studies made where the current applied (ON) -850 mV potential was held at -850 mV on coated pipe in order to determine what the expected corrosion rate would be. First there is no company I know of that would attempt to do that in real life. As mention before, this NOT the way the “ON” criterion has been used or should be used. A much better test would be to see how many times 100 mV of polarization cannot be attained when the “ON” potential is a -850 mV or more negative on coated pipelines. This would really be useful information. There are a few instances where 100 mV may not be reached, but these are rare because with well coated pipe (assuming no CP shielding) CP current only has to protect the very few bare areas (holidays) and will easily find these. Polarization of these areas takes minimal current allowing current to move on to other openings. Compared to a bare structure that meets the 100 mV of polarization criterion, the well coated pipeline will require considerably less current than an uncoated pipeline. Most of the uncoated pipelines will never reach a polarized -850 mV criterion or the “ON” -850 mV criterion so the 100 mV of polarization is the only choice.
The push of this article seems to be to prepare everyone for the use of a statement in the SP0169 revision that states that if the polarized -850 mV or 100 mV of polarization criterions are used then there will be 1 mil or less corrosion rate. I think most basically agree with this concept if these criteria are used (and current can actually reach the pipe steel), but this is not a statement that should be placed in the SP0169 since there is no way to actually measure this in the field. If a statement like this is used in the SP0169, it must be well explained as to its intent, but I would still be concerned about the problems that could develop if lawyers and expert witnesses start using such statements to try to win law suits against pipeline companies. This is a discussion for another time.
Mark Mateer’s report is used to back up the theory that if everyone would use the polarized -850 mV criterion then we would have less external corrosion problems than if we use the “ON” -850 mV criterion. This may or may not be, but there are several issues that must be addressed before such assumptions can be made. I agree this is a very comprehensive report since it covers a 50 year time frame, but many other issues were not addressed in this article such as:
1. Again there is no discussion of the root cause of corrosion on these pipelines. There is no discussion of coating types, condition or if the coatings were shielding or non-shielding.
2. Even though the criterion used for the mid portion of the pipeline life was -850 mV “ON”, we are not given whether this criterion was properly applied or not.
3. What happened during the period of time when the polarized -850 mV criterion was used that may have also influenced the results beyond that of simply applying more CP?
a. As companies began to learn more about CP, coatings and reasons for external corrosion, they applied more CP and performed more detailed surveys to find areas of coating damage and repaired these areas. The same can be said from the beginning of CP on these pipeline systems until use of the “ON” -850 mV criterion.
b. The use of ILI tools also started at this time which also helped find and correct corrosion problems along with recoating programs and pipe replacements.
c. There were (probably) more and better coated pipelines laid during this 16 year period, which would sway the results. Only if the same pipelines were carried throughout the entire survey could this be reliable data.
d. More training and certification courses were offered during this time from NACE, companies and other organizations providing a much more knowledgeable and experienced work force.
e. During this time corrosion control becomes much more important in these companies and governments, which forced significant changes in the industry with large budgets and more attention paid to corrosion control efforts.
f. I would suspect that nearly every company could show similar results even if they were using an “ON” -850 mV criterion throughout the same time frame because of the reasons mentioned, not just because of using a polarized potential criterion.
Distribution companies are referenced as needing to change to the polarized potential criterion to eliminate their corrosion problems. Of course, the issue here is that most distribution companies do not have a reasonable way of performing the required testing to determine a polarized potential because most of these systems are protected with galvanic anodes that do not have access to install interrupters. Also, many systems have short segments of steel mixed with plastic pipe so electrical continuity is a problem. I have been told all they have to do is install coupons to determine what the polarized potential would be on these systems. Coupons are good tools when used properly, but are not the total answer and the cost of installing, reading and maintain these would be significant with limited improved results. Distribution companies have significantly more problems than transmission pipeline companies.
In the Summary the statement “the claim that the -850 mV current applied potential is as effective in controlling as the -850 mV polarized potential criterion is not borne out in the published literature”, is another statement that could use some discussion. Even though there have been several papers and presentations made to contrary, these are typically ignored.
The first sentence of the second paragraph under the Summary section is another bit of misinformation. I do not know a single company that only relies only on external corrosion failures to determine their external corrosion control program. It is interesting that in Mark Mateer’s article, these companies continued to have external corrosion “failures” even though they switched to a polarized potential criterion. Apparently they had corrosion rates over 1 mil per year! Are Bob and everyone else supporting this issue ready to tell us that there will be no external corrosion problems (at least less than 1 mil per year) if all switch to a polarized -850 mV criterion? I do not think so.
What we need is to continue to educate those who are responsible for corrosion control programs around the world that there are many parts to an external corrosion control program, not just CP and criteria. SP0169 is a critical document to our industry. Let’s do it right by making it flexible enough that companies can use the processes available to control the external corrosion on their systems. Those companies and their workers understand these systems better than anyone else, so all we have to do is continue to education these folks so they have a well-rounded understanding of all these processes and let them make the decision on what is best for their companies.
Another issue that needs to addressed is that of some in NACE teaching that only a polarized potential or 100 mV of polarization are acceptable criteria. If the -850 mV current applied criterion is listed it should also be taught as acceptable as long as it properly applied. Until and if the “ON” criterion is removed from the SP0169, it should be taught as a viable criterion when properly used.
As much as I have said, I want to be perfectly clear that I do respect Mr. Gummow. He is a very intelligent person and truly dedicated to what his experiences and knowledge has given him. I have had the opportunity to teach with him many times and he is a great instructor. Each time I get to teach with him, I learn and will always be grateful for the opportunity. Even though we have differences in opinions, as long as we all learn from and challenge each other we will all improve our knowledge and abilities.
Richard Norsworthy
Polyguard Products, Inc.
November 2010
R. A. (Bob) Gummow has written a very good article “Examining The Controversy Surrounding The -850 mV CP Criteria” that is published in the November 2010 Pipeline and Gas Journal. As usual Bob does a very good job of making his points while barely mentioning some well-known “facts” that do not quite fit his theory and experience. For this reason I would like to provide comments on some of his statements that may concern some in the pipeline and CP industry.
I agree with much of what is addressed in the article. The discussion is mainly about the controversy between using an “ON” -850 mV and the “polarized” -850 mV criterions. The discussion below will be about specific statements and where I believe we “MUST” discuss each side of the debate if we are to actually learn and achieve a better understanding of the proper ways to use these criteria as separate items in the NACE International SP0169 document. Even though some say there is confusion when there are two criterions using the -850 mV as the base number, most of the end users do not have this problem. When allowed to consider their specific system and what criterion actually provides the most economical and efficient process for evaluating the cathodic protection effectiveness for their system, while at the same time providing a safe environment for the pipeline and surrounding communities is the critical issue.
Statements are made that if the CP levels are such that a polarized -850 mV (or more negative potential) or proof of at least 100 mV of polarization would result in (most cases) a corrosion rate of less than 1 mil per year (mpy). This rate of corrosion has been established in several tests using coupons and no one is questioning this fact, but it is something to keep in mind while reading this response. Just how we are going to measure this on a pipeline has not been totally addresses yet.
One of the issues with using the “ON” -850 mV criterion is that of considering IR drops in the soil. There is no doubt that we can see a difference in the “ON” and instant Off potentials. Whether this difference is truly a problem is debatable. One of the problems is that we cannot easily measure the so called “instant off” or polarized potential. That is a discussion for another time.
Assuming that we can measure the instant Off effectively (mostly we try to measure it consistently), then we can subtract the instant Off from the “ON” and that value is the IR drop that is the assumed culprit. It is interesting that this is called an “error” in the “ON” potential. This is not an “error”. It is simply part of the “ON” potential. Whether it should be considered as a problem or not is up to those responsible for interpreting these potentials using their knowledge and experiences on that particular pipeline system according to all the information available, not just CP potentials. This is sound engineering practice. Forcing all to use a polarized potential because of a few tests on coupons, is not sound engineering practice.
The companies that use the “ON” potential as one of their criterion do not try to protect an entire pipeline system at an “ON” -850 mV, but use this “ON” potential as a warning sign that the protection at that site and the surrounding area needs further testing or additional CP. I have yet to see a pipeline system that could be protected at one specific potential for its entirety. It is absurd to even bring this up when discussing the “ON” -850 mV potential criterion, yet this is one argument against using it. Bob has to admit that “likely” when using this criterion the 100 mV of polarization is met or exceeded, therefore since the “ON” potentials are typically much more negative than the -850 mV, these companies are indeed considering IR drop in these potentials. The 5th paragraph under “The -850 mV cse Current Applied Criterion” addresses this fact.
Another interesting statement is when discussing the paper by Mr. Holtsbaum. In the caption under Figure 1, he states “IR Drop versus On Potentials to Illustrate a Dangerous Use of a Constant IR Drop Factor, in this case 100 mV.” I do not think the use of “Dangerous” is called for here, but if you are trying to convince folks that do not know, that you are right then you use such words to get their attention. The statement was perfectly fine without the word “Dangerous”. Had these potentials actually been allowed to depolarize there would have likely been at least 100 mV of polarization which would have proven that these potentials were not dangerous, just not complete. Since I do have copy of Mr. Holtsbaum’s paper, I do not know if this testing was performed or published in this paper.
The last sentence of the ON criterion section says, “Because of the extreme range of the IR drop on coated pipelines, the level of CP cannot be determined by the “ON” potential alone.” This statement could be interpreted to mean that using only any “ON” criterion will result in many pipeline failures. This has not been proven to be true. Yes, there have been pipeline failures on coated pipelines which use this “ON” criterion (also the polarized and 100 mV of polarization criteria), but if we could go back and actually find the root cause of the problem, we would find that most of these failures occurred because of disbonded and CP shielding pipeline coatings, interference or other shielding issues. If this statement were true, then why would companies with FBE coated pipelines not also experience these same external corrosion failure problems? Again, there have been a few external corrosion problems on FBE coated pipelines, but nearly all can be explained as AC or DC interference or shielding from other objects placed in the ditch.
From the time I started in the pipeline industry (1980) and before companies were using an “ON” -850 mV criterion for protection of most of their pipelines. Those coated with FBE starting in 1960 did not and still do not have the same external corrosion problems as those pipes coated with other coating types. This is still true today. This has been proven out through the use of many ILI tools over the last 25 years, as well as ECDA. This points out that if using non-shielding pipeline coatings such as FBE even with an “ON” -850 mV criterion, companies will rarely have external corrosion caused from inadequate CP. This particular issue is conveniently ignored by those who propose that only a polarized -850 mV criterion is the only -850 mV criterion that can be used successfully.
For the most part everyone agrees with the fact that use of the polarized -850 mV criterion would result in more polarization and in some cases would certainly be a better choice. Of course, we must also understand that there can be problems when using this criterion just like when using the “ON” -850 mV. These facts are also conveniently left out of this article, but should be part of any discussion of this topic.
In the section on the comparison of the two -850 mV criterion, the statement is made that there have been no studies made where the current applied (ON) -850 mV potential was held at -850 mV on coated pipe in order to determine what the expected corrosion rate would be. First there is no company I know of that would attempt to do that in real life. As mention before, this NOT the way the “ON” criterion has been used or should be used. A much better test would be to see how many times 100 mV of polarization cannot be attained when the “ON” potential is a -850 mV or more negative on coated pipelines. This would really be useful information. There are a few instances where 100 mV may not be reached, but these are rare because with well coated pipe (assuming no CP shielding) CP current only has to protect the very few bare areas (holidays) and will easily find these. Polarization of these areas takes minimal current allowing current to move on to other openings. Compared to a bare structure that meets the 100 mV of polarization criterion, the well coated pipeline will require considerably less current than an uncoated pipeline. Most of the uncoated pipelines will never reach a polarized -850 mV criterion or the “ON” -850 mV criterion so the 100 mV of polarization is the only choice.
The push of this article seems to be to prepare everyone for the use of a statement in the SP0169 revision that states that if the polarized -850 mV or 100 mV of polarization criterions are used then there will be 1 mil or less corrosion rate. I think most basically agree with this concept if these criteria are used (and current can actually reach the pipe steel), but this is not a statement that should be placed in the SP0169 since there is no way to actually measure this in the field. If a statement like this is used in the SP0169, it must be well explained as to its intent, but I would still be concerned about the problems that could develop if lawyers and expert witnesses start using such statements to try to win law suits against pipeline companies. This is a discussion for another time.
Mark Mateer’s report is used to back up the theory that if everyone would use the polarized -850 mV criterion then we would have less external corrosion problems than if we use the “ON” -850 mV criterion. This may or may not be, but there are several issues that must be addressed before such assumptions can be made. I agree this is a very comprehensive report since it covers a 50 year time frame, but many other issues were not addressed in this article such as:
1. Again there is no discussion of the root cause of corrosion on these pipelines. There is no discussion of coating types, condition or if the coatings were shielding or non-shielding.
2. Even though the criterion used for the mid portion of the pipeline life was -850 mV “ON”, we are not given whether this criterion was properly applied or not.
3. What happened during the period of time when the polarized -850 mV criterion was used that may have also influenced the results beyond that of simply applying more CP?
a. As companies began to learn more about CP, coatings and reasons for external corrosion, they applied more CP and performed more detailed surveys to find areas of coating damage and repaired these areas. The same can be said from the beginning of CP on these pipeline systems until use of the “ON” -850 mV criterion.
b. The use of ILI tools also started at this time which also helped find and correct corrosion problems along with recoating programs and pipe replacements.
c. There were (probably) more and better coated pipelines laid during this 16 year period, which would sway the results. Only if the same pipelines were carried throughout the entire survey could this be reliable data.
d. More training and certification courses were offered during this time from NACE, companies and other organizations providing a much more knowledgeable and experienced work force.
e. During this time corrosion control becomes much more important in these companies and governments, which forced significant changes in the industry with large budgets and more attention paid to corrosion control efforts.
f. I would suspect that nearly every company could show similar results even if they were using an “ON” -850 mV criterion throughout the same time frame because of the reasons mentioned, not just because of using a polarized potential criterion.
Distribution companies are referenced as needing to change to the polarized potential criterion to eliminate their corrosion problems. Of course, the issue here is that most distribution companies do not have a reasonable way of performing the required testing to determine a polarized potential because most of these systems are protected with galvanic anodes that do not have access to install interrupters. Also, many systems have short segments of steel mixed with plastic pipe so electrical continuity is a problem. I have been told all they have to do is install coupons to determine what the polarized potential would be on these systems. Coupons are good tools when used properly, but are not the total answer and the cost of installing, reading and maintain these would be significant with limited improved results. Distribution companies have significantly more problems than transmission pipeline companies.
In the Summary the statement “the claim that the -850 mV current applied potential is as effective in controlling as the -850 mV polarized potential criterion is not borne out in the published literature”, is another statement that could use some discussion. Even though there have been several papers and presentations made to contrary, these are typically ignored.
The first sentence of the second paragraph under the Summary section is another bit of misinformation. I do not know a single company that only relies only on external corrosion failures to determine their external corrosion control program. It is interesting that in Mark Mateer’s article, these companies continued to have external corrosion “failures” even though they switched to a polarized potential criterion. Apparently they had corrosion rates over 1 mil per year! Are Bob and everyone else supporting this issue ready to tell us that there will be no external corrosion problems (at least less than 1 mil per year) if all switch to a polarized -850 mV criterion? I do not think so.
What we need is to continue to educate those who are responsible for corrosion control programs around the world that there are many parts to an external corrosion control program, not just CP and criteria. SP0169 is a critical document to our industry. Let’s do it right by making it flexible enough that companies can use the processes available to control the external corrosion on their systems. Those companies and their workers understand these systems better than anyone else, so all we have to do is continue to education these folks so they have a well-rounded understanding of all these processes and let them make the decision on what is best for their companies.
Another issue that needs to addressed is that of some in NACE teaching that only a polarized potential or 100 mV of polarization are acceptable criteria. If the -850 mV current applied criterion is listed it should also be taught as acceptable as long as it properly applied. Until and if the “ON” criterion is removed from the SP0169, it should be taught as a viable criterion when properly used.
As much as I have said, I want to be perfectly clear that I do respect Mr. Gummow. He is a very intelligent person and truly dedicated to what his experiences and knowledge has given him. I have had the opportunity to teach with him many times and he is a great instructor. Each time I get to teach with him, I learn and will always be grateful for the opportunity. Even though we have differences in opinions, as long as we all learn from and challenge each other we will all improve our knowledge and abilities.
Richard Norsworthy
Polyguard Products, Inc.
Thursday, October 7, 2010
How Instant is Instant
For thosw of you who are concerned about the process of taking accurate "so called" instnat off potentials, the is a very good article in the Journal of Corrosion Sceince and Engineering that helps to explain the issues surrounding this problem.
Please go to the www.jcse.org and search around until you find a copy. It is a very good paper that should be in stack of references, etc.
Once again the Paper is "How Instant is Instant" by B.W.Cherry.
ISSN 1466-8858 Volume 9 Paper 6 - How Instant is Instant? B.W.Cherry Department of Materials Engineering, Monash University, Victoria 3800, Australia.
You will have to register, but the process is easy and worth your time! There are many other articles that are available from the JCSE that will be of interest to us "Rust Idiots".
Thanks,
Richard
Please go to the www.jcse.org and search around until you find a copy. It is a very good paper that should be in stack of references, etc.
Once again the Paper is "How Instant is Instant" by B.W.Cherry.
ISSN 1466-8858 Volume 9 Paper 6 - How Instant is Instant? B.W.Cherry Department of Materials Engineering, Monash University, Victoria 3800, Australia.
You will have to register, but the process is easy and worth your time! There are many other articles that are available from the JCSE that will be of interest to us "Rust Idiots".
Thanks,
Richard
Sunday, September 26, 2010
Results of SP0169 vote 9-22-2010
For results of the most recent vote results go to the NACE website under committees, then look for the "On Line Balloting" and click on it. It will ask you for your login information and password. Then the TCC Balloting Home screen will be there. Chose the "Results" and go to page 11. Under the TG 360 be sure to take the one that dated 9-22-2010.
There you can see all the information on how many votes were cast, number and percentages of affirmatives, negatives and abstains. The breakdown of each group and category that voted, etc. This version got 87% affirmative!
Since this version has passed the 66 2/3 needed for it to move forward, now the committee will have to address the negatives and comments. If technical changes are made, then only those sections will have to be reballoted.
Hopefully, this will get the document on the way to being approved. Once approved, the next battle will be the Test method committee and making sure it is all correctly done there! Please stay dilligent and be sure you get on the voting/balloting list for the revision of the test method!
I want to thank all for your support and effort as this document is now moving forward, but is not there yet! We must be sure nothing is slipped in with no one paying attention!
Polyguard has chosen to continue the SP0169.com blog site through out this process.
Thank you,
Richard Norsworthy
There you can see all the information on how many votes were cast, number and percentages of affirmatives, negatives and abstains. The breakdown of each group and category that voted, etc. This version got 87% affirmative!
Since this version has passed the 66 2/3 needed for it to move forward, now the committee will have to address the negatives and comments. If technical changes are made, then only those sections will have to be reballoted.
Hopefully, this will get the document on the way to being approved. Once approved, the next battle will be the Test method committee and making sure it is all correctly done there! Please stay dilligent and be sure you get on the voting/balloting list for the revision of the test method!
I want to thank all for your support and effort as this document is now moving forward, but is not there yet! We must be sure nothing is slipped in with no one paying attention!
Polyguard has chosen to continue the SP0169.com blog site through out this process.
Thank you,
Richard Norsworthy
Friday, September 3, 2010
Comments with Richard's affirmative vote
Comments to TG 360 Committee – Ballot August 2010
Definitions:
Coating: (1) A liquid, liquefiable, or mastic composition that, after application to a surface, is converted into a solid protective, decorative, or functional adherent film; (2) (in a more general sense) a thin layer of solid material on a surface that provides improved protective, decorative, or functional properties. For the purposes of this standard, “Coating” is defined as an electrically insulating material applied to the surface of a metallic structure that provides an adherent film which protects a metallic structure from the surrounding electrolyte.
Reason for change: Not all coatings are “thin”. Not sure how you would define “thin”.
6.2.1.4.9 When operating pressure and conditions are conducive to high pH stress corrosion cracking, the use of polarized potentials in the cracking range relative to the temperature indicated in Figure 1 is not advised.56
This table concerns me since many times the SCC happens under disbonded coatings and that is not affected by the polarized potential measurements outside of the coating. Could there be precautionary statement to cover these situations?
6.4.3 In situations in which the temperature of the reference electrode is below 15 °C (59 °F) and above 35 °C (95 °F), refer to Table 2.
This table is very confusing to most folks and will cause many problems. Why is there not a difference when the temperature is between 15º C and 35º C? Now when you are out of these ranges we have to calculate these differences. We have already thoroughly confused the industry with reference cell conversions that change continually according to which course they are taking at the time. Is this really a serious problem? If so, why has it not been in the document before? Do we really need this?
Thanks for all the hard work and effort!
Richard Norsworthy
Polyguard Products, Inc.
214-912-9072
Definitions:
Coating: (1) A liquid, liquefiable, or mastic composition that, after application to a surface, is converted into a solid protective, decorative, or functional adherent film; (2) (in a more general sense) a thin layer of solid material on a surface that provides improved protective, decorative, or functional properties. For the purposes of this standard, “Coating” is defined as an electrically insulating material applied to the surface of a metallic structure that provides an adherent film which protects a metallic structure from the surrounding electrolyte.
Reason for change: Not all coatings are “thin”. Not sure how you would define “thin”.
6.2.1.4.9 When operating pressure and conditions are conducive to high pH stress corrosion cracking, the use of polarized potentials in the cracking range relative to the temperature indicated in Figure 1 is not advised.56
This table concerns me since many times the SCC happens under disbonded coatings and that is not affected by the polarized potential measurements outside of the coating. Could there be precautionary statement to cover these situations?
6.4.3 In situations in which the temperature of the reference electrode is below 15 °C (59 °F) and above 35 °C (95 °F), refer to Table 2.
This table is very confusing to most folks and will cause many problems. Why is there not a difference when the temperature is between 15º C and 35º C? Now when you are out of these ranges we have to calculate these differences. We have already thoroughly confused the industry with reference cell conversions that change continually according to which course they are taking at the time. Is this really a serious problem? If so, why has it not been in the document before? Do we really need this?
Thanks for all the hard work and effort!
Richard Norsworthy
Polyguard Products, Inc.
214-912-9072
Wednesday, September 1, 2010
Richard Norsworthy's comments on August 2010 version
At this time I believe this is a copy that I will vote affirmative. There are some areas that need help, but this is the most reasonable version I have seen. There are some excellent changes and improvements in the overall document.
Please take time to review the document and vote as you feel neccessary, but please vote. If you vote affirmative, you can provide comments for the areas that still need some improvements or changes. This does not force the committee to change anything, but they should and I believe will address any comments.
I have not had time to provide my comments yet, but will later.
Even if this version passes, we will continue the SP0169.com blog because the TM0497 now has to begin the revision to accomodate this revision.
Thanks,
Richard
Polyguard Products, Inc.
Please take time to review the document and vote as you feel neccessary, but please vote. If you vote affirmative, you can provide comments for the areas that still need some improvements or changes. This does not force the committee to change anything, but they should and I believe will address any comments.
I have not had time to provide my comments yet, but will later.
Even if this version passes, we will continue the SP0169.com blog because the TM0497 now has to begin the revision to accomodate this revision.
Thanks,
Richard
Polyguard Products, Inc.
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