The TG 360 committee met at Corrosion Technology Week in Las Vegas to discuss the last vote on the SP0169 revision. As indicated before the document now has a 90.2% approval, so the committee can now move forward with addressing all the negatives and comments.
My feeling from the portion of the meeting that I was able to attend, was that most of the negatives were getting resolved or were over ridden by a vote of the committee. The few changes that were made (to me) were not technical in nature. That of course is up to the TG 360 and the TCC group.
If it is decided that the changes are editoral and not technical, then the corrections can be made and the document reviewed by the TCC or who ever does it. If they have any corrections, then those will be made and the document can be published.
If it is decided that the changes are technical in nature, then these parts of the document will be re-balloted. If that happens, only the parts that have been changed will be voted on, not the entire document. Then any negatives will be addressed again, etc., etc., and etc.!
We should know more soon. The committee is as ready as anyone to get this document out to the industry.
One thing that does concen me is the movement to make these ISO documents that NACE adopts. I am not sure this is the way to go. We need to keep an eye on this movement to ensure NACE and all the hard work we do is not lost. This will be a discussion for future posts.
Thanks for all your support and interest in this very important document!
Richard Norsworthy
Polyguard Products, Inc.
We believe in Non-Shielding Pipeline Coatings!
Monday, October 10, 2011
Monday, August 1, 2011
Jim Jenkins comments
"The -850 mV criterion for cathodic protection of steel is with respect to a copper-copper sulfate reference electrode. As the potential of the reference electrode changes with temperature, it is appropriate to state the reference electrode temperature at which the -850 mV is applicable. This is not explicitly contained in the proposed standard."
Jim Jenkins
Jim Jenkins
Thursday, July 28, 2011
Re-posted comments
Comments for SP0169 Re-ballot July 2011
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 that isolates a metallic structure from the surrounding electrolyte.
Why did we remove the last statement? The first part is not a true definition of a coating used with CP. I would suggest leaving it in.
6.1.1 [Last sentence] A commonly used benchmark for demonstrating effective external corrosion control is 0.025 mm per year (1 mil per year) or less.
This statement is still an issue because there is not a reasonable way to measure this on a pipeline. Coupons can be measured, but not pipelines. Why do we need this?
Delete this sentence.
6.2.1.1 Criteria that have been documented through empirical evidence to accurately indicate corrosion control effectiveness on specific piping systems may be used on those piping systems or others with the same characteristics.
Remove the word “accurately”. How do we define accurately? The sentence works just fine without it. The same for 6.2.5.1, 6.2.6.1, and 6.2.7.1 statements.
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;
This statement needs to be changed to read “…to establish whether a -850 mV potential or more negative potential across the structure-to-electrolyte …”
Reasoning for change: We do not want to restrict the potential to just -850 mV. There is no way to hold the potential at a certain level. The question is do we restrict the upper limit of the polarized potential?
6.2.1.4.7 When operating pressure and conditions are conducive to high pH stress corrosion cracking, polarized potentials in the cracking range relative to the temperature indicated in Figure 1 should be avoided.
One of the issues with this statement and the table is that it does not take into consideration that SCC on pipelines almost always, if not always, develops under disbonded and CP shielding pipeline coatings. How are we to measure the polarized potential of the pipe in this case? I do not doubt that the information given is correct for the potential ranges and temperatures given, but there is just no way to determine this in the field under disbonded CP shielding coatings. Most the studies and research are performed on uncoated steel pieces, not under disbonded coatings.
I would suggest that we leave this information as a precaution without the table. There needs to be a separate SP0 for SCC that explains all the information. The pH levels are critical as well as the stress level and whether the stress is residual or applied. This is an important issue, but not sure this is the way to cover it.
Suggested replacement statement:
6.2.1.4.7 When operating pressure and conditions are conducive to high pH stress corrosion cracking, polarized potentials and temperatures in the cracking range should be avoided. Pipelines that have or have the potential for disbonded CP shielding coatings should be monitored for SCC through the use of ILI with Electro Magnetic Acoustical Transducer (EMAT) technology or ECDA methods to determine if SCC exists. Certain types of EMAT technology will also detect disbonded coating as well as SCC. Existing disbonded coatings and potentially CP shielding coatings should be removed and where practical replaced with a non-shielding coating system.
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 that isolates a metallic structure from the surrounding electrolyte.
Why did we remove the last statement? The first part is not a true definition of a coating used with CP. I would suggest leaving it in.
6.1.1 [Last sentence] A commonly used benchmark for demonstrating effective external corrosion control is 0.025 mm per year (1 mil per year) or less.
This statement is still an issue because there is not a reasonable way to measure this on a pipeline. Coupons can be measured, but not pipelines. Why do we need this?
Delete this sentence.
6.2.1.1 Criteria that have been documented through empirical evidence to accurately indicate corrosion control effectiveness on specific piping systems may be used on those piping systems or others with the same characteristics.
Remove the word “accurately”. How do we define accurately? The sentence works just fine without it. The same for 6.2.5.1, 6.2.6.1, and 6.2.7.1 statements.
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;
This statement needs to be changed to read “…to establish whether a -850 mV potential or more negative potential across the structure-to-electrolyte …”
Reasoning for change: We do not want to restrict the potential to just -850 mV. There is no way to hold the potential at a certain level. The question is do we restrict the upper limit of the polarized potential?
6.2.1.4.7 When operating pressure and conditions are conducive to high pH stress corrosion cracking, polarized potentials in the cracking range relative to the temperature indicated in Figure 1 should be avoided.
One of the issues with this statement and the table is that it does not take into consideration that SCC on pipelines almost always, if not always, develops under disbonded and CP shielding pipeline coatings. How are we to measure the polarized potential of the pipe in this case? I do not doubt that the information given is correct for the potential ranges and temperatures given, but there is just no way to determine this in the field under disbonded CP shielding coatings. Most the studies and research are performed on uncoated steel pieces, not under disbonded coatings.
I would suggest that we leave this information as a precaution without the table. There needs to be a separate SP0 for SCC that explains all the information. The pH levels are critical as well as the stress level and whether the stress is residual or applied. This is an important issue, but not sure this is the way to cover it.
Suggested replacement statement:
6.2.1.4.7 When operating pressure and conditions are conducive to high pH stress corrosion cracking, polarized potentials and temperatures in the cracking range should be avoided. Pipelines that have or have the potential for disbonded CP shielding coatings should be monitored for SCC through the use of ILI with Electro Magnetic Acoustical Transducer (EMAT) technology or ECDA methods to determine if SCC exists. Certain types of EMAT technology will also detect disbonded coating as well as SCC. Existing disbonded coatings and potentially CP shielding coatings should be removed and where practical replaced with a non-shielding coating system.
Comments on SP0169 Re- Ballot - July 2011
Richard Norsworthy's Comments for SP0169 Re-ballot July 2011
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 that isolates a metallic structure from the surrounding electrolyte.
Why did we remove the last statement? The first part is not a true definition of a coating used with CP. I would suggest leaving it in.
6.1.1 [Last sentence] A commonly used benchmark for demonstrating effective external corrosion control is 0.025 mm per year (1 mil per year) or less.
This statement is still an issue because there is not a reasonable way to measure this on a pipeline. Coupons can be measured, but not pipelines. Why do we need this?
Delete this sentence.
6.2.1.1 Criteria that have been documented through empirical evidence to accurately indicate corrosion control effectiveness on specific piping systems may be used on those piping systems or others with the same characteristics.
Remove the word “accurately”. How do we define accurately? The sentence works just fine without it. The same for 6.2.5.1, 6.2.6.1, and 6.2.7.1 statements.
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;
This statement needs to be changed to read “…to establish whether a -850 mV potential or more negative potential across the structure-to-electrolyte …”
Reasoning for change: We do not want to restrict the potential to just -850 mV. There is no way to hold the potential at a certain level. The question is do we restrict the upper limit of the polarized potential?
6.2.1.4.7 When operating pressure and conditions are conducive to high pH stress corrosion cracking, polarized potentials in the cracking range relative to the temperature indicated in Figure 1 should be avoided.
One of the issues with this statement and the table is that it does not take into consideration that SCC on pipelines almost always, if not always, develops under disbonded and CP shielding pipeline coatings. How are we to measure the polarized potential of the pipe in this case? I do not doubt that the information given is correct for the potential ranges and temperatures given, but there is just no way to determine this in the field under disbonded CP shielding coatings. Most the studies and research are performed on uncoated steel pieces, not under disbonded coatings.
I would suggest that we leave this information as a precaution without the table. There needs to be a separate SP0 for SCC that explains all the information. The pH levels are critical as well as the stress level and whether the stress is residual or applied. This is an important issue, but not sure this is the way to cover it.
Suggested replacement statement:
6.2.1.4.7 When operating pressure and conditions are conducive to high pH stress corrosion cracking, polarized potentials and temperatures in the cracking range should be avoided. Pipelines that have or have the potential for disbonded CP shielding coatings should be monitored for SCC through the use of ILI with Electro Magnetic Acoustical Transducer (EMAT) technology or ECDA methods to determine if SCC exists. Certain types of EMAT technology will also detect disbonded coating as well as SCC. Existing disbonded coatings and potentially CP shielding coatings should be removed and where practical replaced with a non-shielding coating system.
These are my comments at this time. Please forward yours!
Thanks very much!
Richard
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 that isolates a metallic structure from the surrounding electrolyte
6.1.1 [Last sentence] A commonly used benchmark for demonstrating effective external corrosion control is 0.025 mm per year (1 mil per year) or less.
This statement is still an issue because there is not a reasonable way to measure this on a pipeline. Coupons can be measured, but not pipelines. Why do we need this?
Delete this sentence.
6.2.1.1 Criteria that have been documented through empirical evidence to accurately indicate corrosion control effectiveness on specific piping systems may be used on those piping systems or others with the same characteristics.
Remove the word “accurately”. How do we define accurately? The sentence works just fine without it. The same for 6.2.5.1, 6.2.6.1, and 6.2.7.1 statements.
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;
This statement needs to be changed to read “…to establish whether a -850 mV potential or more negative potential across the structure-to-electrolyte …”
Reasoning for change: We do not want to restrict the potential to just -850 mV. There is no way to hold the potential at a certain level. The question is do we restrict the upper limit of the polarized potential?
6.2.1.4.7 When operating pressure and conditions are conducive to high pH stress corrosion cracking, polarized potentials in the cracking range relative to the temperature indicated in Figure 1 should be avoided.
One of the issues with this statement and the table is that it does not take into consideration that SCC on pipelines almost always, if not always, develops under disbonded and CP shielding pipeline coatings. How are we to measure the polarized potential of the pipe in this case? I do not doubt that the information given is correct for the potential ranges and temperatures given, but there is just no way to determine this in the field under disbonded CP shielding coatings. Most the studies and research are performed on uncoated steel pieces, not under disbonded coatings.
I would suggest that we leave this information as a precaution without the table. There needs to be a separate SP0 for SCC that explains all the information. The pH levels are critical as well as the stress level and whether the stress is residual or applied. This is an important issue, but not sure this is the way to cover it.
Suggested replacement statement:
6.2.1.4.7 When operating pressure and conditions are conducive to high pH stress corrosion cracking, polarized potentials and temperatures in the cracking range should be avoided. Pipelines that have or have the potential for disbonded CP shielding coatings should be monitored for SCC through the use of ILI with Electro Magnetic Acoustical Transducer (EMAT) technology or ECDA methods to determine if SCC exists. Certain types of EMAT technology will also detect disbonded coating as well as SCC. Existing disbonded coatings and potentially CP shielding coatings should be removed and where practical replaced with a non-shielding coating system.
These are my comments at this time. Please forward yours!
Thanks very much!
Richard
Tuesday, April 26, 2011
Link to SCC and CP report
Below is a link to a very good report that gives great information on the potential problems with stress corrosion cracking and cathodic protection levels on higher strength steels. This has been a real concern of some in the industry as we move to more negative potentials to acheive criteria as in the polarized -850 mV criterion.
The move is toward higher strength steels because of the cost difference in weight and shipping. The problem is the higher strength steel can become embrittled and potentially crack when introduced to high levels of hydrogen.
The link for this site is:
http://primis.phmsa.dot.gov/matrix/FilGet.rdm?fil=5327
If this document is not referenced in the SP0169, it should be as a cautionary statement.
At this time, I have not heard from the committee on their progress. Hopefully, we will see the newest revision out for re-ballot soon. If so, we are all hopeful it is a version that we can vote affirmative!
If any of you have something to add to the blog that will help others to learn, please e-mail it to me. This has been a great source for learning and distributing information on this very critical document.
If there is any way I can help, please let me know. Thanks for all the help and support through these years of the SP0169 battle.
Richard
The move is toward higher strength steels because of the cost difference in weight and shipping. The problem is the higher strength steel can become embrittled and potentially crack when introduced to high levels of hydrogen.
The link for this site is:
http://primis.phmsa.dot.gov/matrix/FilGet.rdm?fil=5327
If this document is not referenced in the SP0169, it should be as a cautionary statement.
At this time, I have not heard from the committee on their progress. Hopefully, we will see the newest revision out for re-ballot soon. If so, we are all hopeful it is a version that we can vote affirmative!
If any of you have something to add to the blog that will help others to learn, please e-mail it to me. This has been a great source for learning and distributing information on this very critical document.
If there is any way I can help, please let me know. Thanks for all the help and support through these years of the SP0169 battle.
Richard
Sunday, March 27, 2011
Udate on CORROSION 2011/SP0169
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.
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.
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
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