More comments on TM0497

After reviewing the TM0497 reaffirmation ballot changes to that document and after thinking about this over the weekend, I am now strongly leaning towards voting negative and at that same time sending a ballot nullification/disqualification request e-mail, with my reasons for that stance (i.e., technical not editorial revisions, etc.), to the NACE STG 05 Technology Coordinator, STG 05 Chair, and TG 020 Chair (see links below). A point that was stated noting that NACE really does not want TM0497 withdrawn is a very good point. There is also a good chance, in this case, that NACE will immediately start rewriting TM0497 no matter which way the vote goes. I agree that the best outcome would be to have TM0497 reaffirmed as originally/currently written (under a new/second reaffirmation balloting process) – not with the changes made just prior to this first balloting process, at least a portion of which I now believe need to be nullified/disqualified. If enough folks vote negative, NACE will be in a difficult position and will most likely want to either go completely back to the original wording or will want to otherwise negotiate to make allowances for everyone’s concerns.

http://web.nace.org/Departments/Technical/Directory/Committee.aspx?id=e1dc32a6-5fef-db11-9194-0017a4466950

Information from NACE Technical Committee Publicaitons Manual

From NACE Technical Committee Publications Manual:


2.3 For the purposes of determining the type of revisions made to a document or draft document, and thereby determining whether a revision requires ballot, reaffirmation, etc., the following definitions shall be used:

2.3.1 Technical revision—A revision that impacts (a) the systematic procedure by which a complex or scientific task is accomplished using the document or (b) the conclusions reached after using the document.

2.3.2 Editorial revision—A revision intended to make the document suitable for publication without altering the technical intent of any portion of the document. The revision is usually grammatical, typographical, or explanatory in nature or is a revision to the document’s format.

2.3.3 Major (technical or editorial) revision—Extensive, numerous, or any revision(s) that alter the substance or intent of a document.

2.3.4 Minor (technical or editorial) revision—A few specific revisions that do not alter the substance or intent of a document. To be adopted, all technical changes must be balloted.


3.9.5.5 The letter ballot shall provide for three types of votes:

3.9.5.5.1 Affirmative. The voter may note perceived editorial errors and their corrections.

3.9.5.5.2 Negative. The voter should show a perceived technical inaccuracy or omission in the draft standard or address points dealing with perceived ambiguity or a lack of clarity that result in perception of a technical inaccuracy.

3.9.5.5.2.1 A negative must be accompanied by a written comment (relevant to the portion of the document being balloted), preferably including technical explanation and justification.

3.9.5.5.2.2 A negative must include a suggested revision or action that would serve to resolve the negative.

3.9.5.5.2.3 Votes received that do not meet these criteria shall be handled in accordance with Paragraph 3.9.8.6.

3.9.5.5.2.4 The Task Group is not required to consider negative votes (1) without comments or (2) accompanied by comments not related to the proposal under consideration, i.e., the revisions or draft being balloted. Such votes shall be recorded as “negative without comments” without further notice to the voter. Comments shall not be solicited from the voter, and such votes shall not be recirculated to the STG(s).


3.9.5.6 Votes not meeting any one of the following criteria shall not be accepted:

3.9.5.6.1 The vote must be signed; however, if the ballot was sent to the voter via a personal e-mail address, or if the voter has a personal e-mail address registered with Headquarters, the vote may be submitted and accepted via e-mail from that e-mail address. A personal e-mail address is one that is accessible to an identified individual. A group e-mail address is accessible to two or more people. Online votes must be properly submitted using a member number or password set up within the NACE online voting system.

3.9.5.6.2 The vote must be returned by the deadline stated on the ballot or, in the case of a Headquarters-issued deadline extension, by the extended deadline.

3.16.1 Minor editorial changes may be made at any time when the intent and/or technical content of the standard (or section thereof) is not changed. Examples of minor editorial changes would be items such as:

3.16.1.1 Correcting typographical errors in text or data.

3.16.1.2 Changes in product designations that are not a result of changes in the composition of the product that was included in the approved standard.

3.16.1.3 Additions required when an item that requires a “note” or “caution” because of safety conditions or changes in safety or environmental considerations is discovered.


3.16.3.1 Negatives cast against proposed major editorial revisions must provide an explanation of the perceived editorial inaccuracy and a suggested revision or action that would serve to resolve the negative

3.16.4 Editorial changes (excluding minor typographical errors) should be published immediately in Materials Performance and an errata sheet added to all copies of the document sold until it is reprinted.


3.17.3 Reaffirmation

3.17.3.1 If a standard is to be reaffirmed in its existing form or requires only minor editorial changes, the proposal to reaffirm (or to reaffirm with editorial changes) shall be distributed in the same manner as described in Specific Technology Group Review and Approval (Paragraph 3.9) for reaffirmation approval with a four-week deadline for letter ballot response. Concurrently, the proposed reaffirmed standard shall be distributed to RPC for editorial review.


3.17.3.3 If the standard is not reaffirmed by two-thirds (2/3) of all the sponsoring STG members, excluding abstentions, in either a written or meeting ballot, the standard shall be considered in need of revision or withdrawal.


3.17.4.1.1 If technical changes to a standard are proposed, they shall be substantiated with technical information by the submitter. Such documentation should be retained in the Task Group’s files.


3.17.5.5.3.1 RPC shall serve as the final arbiter when determining whether revisions are editorial or technical.


3.17.5.7.1 Minor technical revisions to NACE standards do not require ratification by the Board of Directors.



12 APPEALS PROCESS FOR ALLEGED PROCEDURAL INFRACTION

12.1 Persons who have directly and materially affected interests and who have been or may be adversely affected by a substantive or procedural action or inaction of NACE with regard to the development of a proposed standard or report, or the revision, reaffirmation, or withdrawal of an existing standard or report shall have the right to appeal the alleged procedural infraction. He/she should notify in writing the TCC chair and Headquarters, with copies to the Technology Coordinator, sponsoring STG chairs, and Task Group chair.

12.1.1 The written notification shall contain all substantiation of the perceived infraction and clearly state the portion(s) of the Technical Committee Publications Manual and/or NACE policies that was (were) alleged violated.

12.1.2 Headquarters must receive the notification within four weeks of the perceived infraction.

12.1.3 The notice must contain only perceived procedural infractions.

12.1.4 Procedural appeals include whether a technical appeal was afforded due process.

More Comments on TM0497

Either way can have a negative outcome

If we vote negative because of the changes, it can allow NACE to start immediately revising TM0497 based on the current proposed/revised SP0169 (since TM0497 was not reaffirmed), which I believe will completely remove the -850 mV “On” criterion from the picture (both from SP0169 & from TM0497). If we vote affirmative, then the potentially detrimental (weakening) changes will go forward. However, there will be a longer (lag) time, before any further revisions are made to TM0497, while they wait on the results of the SP0169 balloting process. At least reasonable portions of the -850 mV “On” criterion approach will remain in TM0497 for a time.

I haven’t completely thought it all through yet. At first glance at this moment, I would have a tendency to vote affirmative and then send NACE a note/letter stating that I believe the changes and the balloting were inappropriate, noting that I believe part of the changes constituted technical, not editorial, changes and, therefore, the whole voting/balloting process should be nullified/discarded.

More Comment on TM0497

Question:
If we vote "Affirmative", are we agreeing with the changes they are proposing to TM0497?

Should we vote "negative" and try to keep the original document without the proposed changes?

I didn't completely understand the comments on the blog. Is that person saying to vote negative?

I have already submitted my vote, but it appears that it will let you change your vote. I would guess that you can change it until Dec. 9.

Other comments on TM0497

I couldn’t disagree more.



There are subtle but significant changes to TM0497 that weaken this document and constitute technical not editorial changes. NACE by-laws do not allow reaffirmation of standards if technical changes have been made.



I have requested that NACE suspend balloting and am awaiting a decision on this matter.



Some have requested that NACE postpone any changes to TM0497 until SP0169 is resolved. I support this effort, as the documents are complimentary. If TM0497 is to be reaffirmed, it should be done without changes in the same manner that SP0169 was reaffirmed.

Jim Chmilar comments

Richard, IF you do not agree with the “document as is” then I do not understand how you can vote to re-affirm?

I, myself believe the document needs to be improved TODAY and will be voting to not re-affirm it, because it needs additional information on measurement techniques and that does not depend on the state of SP0169.

The present draft version of the revisions to SP0169 (which is still in TG 360 committee draft stage as everyone knows) I believe does expand the criteria to include the new one that some are proposing, ie a potential valve of –850 mV without consideration or correction for IR drop. Please read all of section 6.2.3.1 which includes a listing of FOUR criteria in 6.2.3.1.1 to 6.2.3.1.4 and in particular 6.2.3.1.3 which is proposed to say “Criteria that have been shown to successfully control corrosion on piping systems can continue to be used on those piping systems” and 6.2.3.1.4 “Other criteria that can be demonstrated to achieve the corrosion control objectives of the operator.” Do these two criteria not allow all those who have been using 850 ON without any correction, or 300 Millivolt shift, or E log I to be in-compliance with the standard?? No need to answer this now, I am sure I will be hearing it when the SP0169 ballot comes out.



It is time for well wishes and hope everybody enjoys the coming Christmas Season.

Cheers

Jim Chmilar

TM0497 and SP0169 comments

It would seem that Jim Chmilar (TG-360 Chairman) intends to go out for ballot on the proposed/revised SP0169, before CORROSION 2009. There are many who do not believe in Jim’s version of what the “FOUR criteria” will allow. Those individuals believe the facts remain that the -850 mV “On” criterion has been removed, only the -850 mV “polarized” (actually instant-off) and the 100 mV polarization criteria remain in black and white, the regulators and other auditors will only want to deal with black and white, and other wording (and lack of wording) within the proposed/revised SP0169, as well as the yet-to-be-created proposed/revised TM0497, along with the most likely perceived ambiguity of the 3rd and 4th “criteria” in the proposed/revised SP0169, will almost certainly make it virtually impossible to ever utilize the -850 mV “On” criterion or any other alternative criterion. In other words, there are many who believe that only the -850 mV “polarized” and the 100 mV polarization criteria will end up being allowed.



Everyone does need to read the proposed/revised SP0169 very, very carefully. It is the belief of a number of individuals that everyone needs to formally insist the PRCI studies be completed, fully reviewed and incorporated, before the proposed/revised SP0169 goes to ballot. In addition, they believe that everyone should formally insist that the proposed/revised SP0169 and proposed/revised TM0497 go to ballot simultaneously, once both of these proposed revisions have been completed and appropriate changes/incorporations have been made to both based on the PRCI studies, as well as the consensus determinations of the industries most affected by these documents. These are both supposed to be consensus documents. It appears there are many who believe that objective is not truly being achieved.

TM0497-Reaffirmation

I strongly disagree with your position that proposed changes discussed in my original correspondence do not constitute technical changes to TM0497.



If the procedure to assess the adequacy of cathodic protection using the 850 mV Current Applied Criterion (Method 1) is modified as proposed, the tone / intent of TM0497 changes. In light of the ongoing debate within NACE over the 850 mV Current Applied Criterion and the omission of this verbiage from the working draft of SP0169, these changes would be proclaimed by some as a clear message that NACE no longer considers these techniques to be valid.



I agree with the proposal from Mark Brogger – let the dust settle on SP0169 and then let’s work on TM-0497. Until then, reaffirm as written.



Additional instances of technical changes are as follows.



· Section 8.6.3 (b) has been changed, but this change is not highlighted in the document. This omission is reason enough to pull the ballot, as members are only asked to review changes. It also raises the question as to how many other changes were not highlighted in the document.



The proposed text is as follows:



8.6.3 Cathodic protection shall be judged adequate at the test site if: (a) The pipe-to-electrolyte potential measurement is negative 850 mV, or more negative, with respect to a CSE; and (b) The significance of voltage drops has been considered by applying the principles described in Paragraphs 8.6.1 (reference Paragraph 1.3 for exceptions).



The current text is as follows:



8.6.3 Cathodic protection shall be judged adequate at the test site if: (a) The pipe-to-electrolyte potential measurement is negative 850 mV, or more negative, with respect to a CSE; and (b) The significance of voltage drops has been considered by applying the principles described in Paragraphs 8.6.1 or 8.6.2.



Paragraph 8.6.2 discusses physical evidence of corrosion which relates to Item (d) Determining whether there is physical evidence of corrosion contained in the Note in Section 8.1 and also in SP0169. Deletion of both is a major technical change to TM0497.



The most widespread impact of this change would relate to the use of ILI data to consider the significance of voltage drops in accordance with 8.6.2 (c). Section 8.6.3 of TM0497 currently allows an operator to judge CP as adequate when current applied potentials are more negative than 850 mV and the significance of voltage drops has been considered by verification of ILI metal loss indications in accordance with 8.6.2(c). The proposed technical changes would require additional steps to consider the significance of voltage drops.



· The addition of “Ductile Iron Pipe” throughout the document.



This was never a simple omission (and thus an editorial change).



· The addition of “non-mandatory” to Appendices B and C



TM0497 is a test method which by definition provides description of techniques to determine whether a specific criterion has been complied with at a test site. As the methods described in Appendices B and C are contained within SP0169, I can’t understand how a technically correct procedure that has been recognized by NACE for years could now be reclassified as non-mandatory.



Again, I request that NACE immediately stop balloting on TM0497. We can discuss the path forward in Atlanta .



As you can see, this individual and his company are very concerned. For those who “signed up” to vote, they may want to consider the possibility of sending NACE a similar note. They also need to remember that the voting deadline is December 9, 2008.



Thanks

Reminder to Ballot

Reminder to Ballot TMO497-2002:

Just a reminder that there is a ballot being sent out soon for the reaffirmation of the TMO497-2002, “Measurement Techniques Related to Criteria for Cathodic Protection on Underground or Submerged Metallic Piping Systems”. If you are interested in voting on this TG 020 document you must go to the NACE Website and follow the instructions as shown below. This will have to be done by November 7, 2008.

This will be good practice for the SP0169-2002 revision when it comes out for vote (maybe later this year). You must first join the STG 05 or 35 committee, then sign up to vote (as shown below). Then you wait for NACE to send the revised or reaffirmation document to vote on. Again, there is a need for voters that are not in the “user/consumer” classification, so if possible sign up in another group of voters.

STEP 1: Please review the abstract by going to http://web.nace.org/ where you will view the NACE login page. You will be prompted to enter your user name and password. Once you have done so and are logged in, click on the tab in the upper right-hand corner titled “Committees.” Then, click on “Online Balloting” (on the right-hand column on this page). The next page you will see offers you Action Items, Results and a Logout option.
------------------------------------------------------------------------
STEP 2: The next page you will see is TCC Balloting Home.

To join a voting list, click on the Action Items button. This will take you to a listing of open Ballots, Reballots, Review and Comments, and voting lists.

Under the heading “Join Ballot Voting Lists,” find the appropriate TG number and click “Respond.”

STEP 3: To review the abstract prior to responding, click on the document title link at the top of the page.

The abstract is in Adobe Acrobat PDF format, which means you will need Acrobat Reader software on your computer. If you do not have it, you may download it FREE from the Adobe Web site,

http://www.adobe.com/products/acrobat/readstep.html

STEP 4: After reviewing the abstract, you may join the voting list or decline to join by clicking the “Back” button at the top left corner of the screen and choosing “yes” or “no” on the TCC Ballot Response page. Please remember to indicate your classification.

Be sure to click on the SUBMIT RESPONSE button at the bottom of the page to submit your response.

After you have submitted your response, the TCC Response Confirmation page will appear stating that your response has been recorded. In addition, you will receive an e-mail confirmation of your response.

Contact Daniela with any questions or problems with getting signed up to vote on this document.


Daniela Matthews
Technical Liaison/Editor
NACE International
Toll Free 1-800 797 NACE (6223)
Direct Tel: (281) 228-6287
Fax: (281) 228-6387
email: daniela.matthews@nace.org

Thank you for help and attention to this matter. Please pass this information on to others!! Also we need comments on the SP0169.com blog site from all sides of the issue so we can all learn and challenge each other to be sure we get the best document possible!

Richard Norsworthy
Polyguard Products, Inc.
214-912-9072

SP0169 updates and voting!

There are several points that must be questioned and answered before this document goes to ballot. At this time, I am not sure they will be answered before the first ballot is sent to the voters.

Those of you who want to vote on this document must pay attention to the new voting process for NACE document approval. Request a copy of the Technical Committee Publications Manual for all the details.

1. Be sure you are a member of the STG 35 group. This can be accomplished over the internet by going to the NACE International website and following the process for becoming a member of that STG group. You should then receive a copy of the ballot when sent out for vote. We are not sure when the draft will be sent out for vote, but some think it will be before the end of the year.
2. Once you receive the ballot, you must indicate on the ballot what group you are voting in. Some of these groups are:
a. End user
b. Consultant
c. Manufacturer/producer
d. Not sure of the other groups, but I think there are 7 categories
3. It is important to understand that the group you vote in is very critical. If more than 50% of the votes are from one group, NACE has to find more voters to fill in so that the majority voters are from more than one group. Of course the problem is that these (fill in) voters may not be knowledgeable of the document and the concerns that may exist. Since many votes will be from end-users, that group could easily be over 50% of the total votes. If you can legitimately be in another group, please sign up as so. Fro example, if you are an end user, but your job function is a consultant to the field techs, then I think you could sign up as a consultant.
4. If you do not vote on the first ballot you will not be able to vote on any further revisions or re-ballots of this particular version.
5. If you vote negative you must provide the committee with a perceived technical inaccuracy or omission or address points dealing with perceived ambiguity or lack of clarity.

The negative must be accompanied by a written comment with a technical explanation and justification statement. A suggested revision or an action that serves to resolve the negative should also be included. Without these the committee does not have to consider the negative.

As you can see it is rather complicated, but the first thing is to be sure you are member of the STG 35 group before the ballot comes out. Please let me know if I can help with any of these issues above.

DISCUSSION OF CTW MEETING – Draft Version #1e – July 2008

The import issues that come out this meeting from my perspective are:

There are several definitions the need to be corrected/changed.

Section #4 has some changes in wording that was worked on by the committee.

Section #5 addresses pipeline coatings and has not been completely revised. A representative from a rock shield company as well as myself have provide comments that have not been totally or correctly inserted at the time of this revision, but is being worked on.

Section # 6 has several issues, but here are the two big ones as far as I am concerned:

6.2.12. The two fundamental polarization criteria in this section have been proven empirically to reduce
the average corrosion rate of steel to less than 25 μm/y (1 mil/y) in soils and natural waters in the field
at ambient temperatures.3,4,5 Situations may exist in which a single criterion for evaluating the
effectiveness of CP may not be satisfactory for all conditions. A single criterion for evaluating the
effectiveness of CP may not be satisfactory for all locations along a structure.

The problem with this section is how does one apply this to a pipeline? How does one prove an average corrosion rate of less than 1 mil per year or less? Of course you can by installing coupons that measure the corrosion rate, but how does that really relate to a pipeline that travels through all kinds of terrains and situations with various coating conditions, etc? Coupons are great tools, but do not provide all the answers to these questions. We will continue to have external corrosion as long as we have coatings and other shielding effects along with interference (AC and DC).

This statement is used in the ISO document and perhaps some others, but the 25 µm/y (1 mil/y) is not a reasonable value for determining corrosion control on external surfaces of pipelines and most other structures. It may be a good definition for some purposes, but is not practical for pipelines.

6.2.3.1.1 A negative (cathodic) voltage of at least 850 mV as measured with respect to a
saturated copper/copper sulfate reference electrode. This potential may be either a direct
measurement of the polarized potential, or a current applied potential corrected for voltage
(IR) drops other than those across the structure/electrolyte boundary.

This criterion would no longer allow the owner to consider IR drop, but force you to only use a polarized potential, because the current applied “ON” potential must now be “corrected” for IR drops. How else can you correct it without using an instant off? The language does not leave much for consideration and use of other methods to prove what you are doing works. Of course, I am still waiting on an answer for the questions I have asked about why we do not have external corrosion on pipelines that use non-shielding coatings such as FBE and an “ON” -850 mV even with out considering IR drop. Most of us know why but this does not “fit” what we are being told must be done to protect our pipelines. Those of you who have this evidence must be putting it together to show the committee and prove the point that we do not need to have more stringent criterion. We need to continue to use the tools we have and better train our corrosion control employees how to recognize the problems that may need more work or investigation and apply the necessary control methods as needed.

Each section and part must be read and examined for accuracy. Remember the document presents procedures and practices for achieving effective control of external corrosion on buried or submerged metallic piping systems. In all NACE SPO’s the Forward says “This standard represents minimum requirements…”. The purposed version is far beyond minimum requirements. If passed as is it will represent the maximum requirements!

Please comment so we can all learn and work together to develop the best possible document that is practical and economical for companies around the world to use for effective external corrosion control on pipelines!

Response to Ed Ondak and Roy Bash Comments

I first want to thank these two gentlemen for providing comments to the SP0169.com blog site. I encourage others to provide comments to help us all learn and grow in knowledge of the proper ways to control external corrosion on pipelines.

I do agree with Ed’s assessment of the section 3.2. We do not to write the SP0169 around regulations or regulators from what ever country or entity that may be regulating that industry. All NACE Standard should only be written to provide the industry with the most economically effective ways to prevent corrosion.

I do not agree with all of Ed’s assessment of the remainder of the document, but this is not the first time Ed and I have disagreed! Thanks, Ed.

Roy’s comments are also very good. I do agree with most of it; except for the comments on FBE not have a problem if CP is not available. With few exceptions, if the coating system’s adhesion is good, there cannot be corrosion, because the pipe is isolated from the electrolyte.

I have seen corrosion occur on an FBE coated pipe with no CP. This was not a case of interference problems, etc. Without CP the pipe can corrode at holidays just like any other coating system.

I agree with his comments of the water penetrating and being basically pure water, but there are other conditions that exist that allow corrosion to develop. When contaminants (various salts) remain on the pipe surface before the pipe is coated, the “pure water” that penetrates combines with the salts to form a conductive path for the CP current to provide protection to the pipe surface. Without CP this area would corrode by local cell action or by being anodic to other areas where disbondments and water penetration has occurred.

If Roy’s assumption is correct, the electrochemical reactions taking place would not cause the high pH values recorded under blistered and disbonded FBE. The high pH indicates the electrochemical process is the same as that taking place on bare steel areas exposed to the same electrolyte when adequate CP is available. Therefore the current is being allowed to protect the pipe surface it these areas of disbondment because the FBE is a non-shielding pipeline coating to CP current when disbondments occur and water penetrates between the coating and the pipe surface.

Cathodic protection can be effective if it can get to the pipe surface and is not shielded by coatings or other materials, etc. As long as the coating is adhered, the CP does not need to be effective, because there is no electrolyte to cause corrosion.

There have been many papers written on this topic that explain the processes of shielding by certain types of coating systems. FBE does not have this problem even when protected by using only the -850 mV criterion (without IR drop consideration). We must start understanding this process and putting 2 and 2 together to understand when we do not need to add more CP! We need to educate our engineers and others about shielding and the proper selection of coatings that will not shield CP current if and when disbondments occur.

DO NOT FORGET TO VOTE ON THE SP0169 REVISION. If you have not joined the STG 35 group, you may not be able to vote! If you do not vote the first time, you will not get the chance to vote on other revisions that may take place after the first ballot. I am not sure when it will be voted, but my guess is sometime this year or early 2009.

Roy Bash Comments

Solid film back pipeline coatings such as coal tar have the property to keep the pipeline perfectly dry. This is the reason that steel never corrodes under these coatings. Dry steel at normal operating temperatures never corrodes. These coatings are supplemented with cathodic protection for protecting the bare steel at places where the coating is not intact. The steel under the intact coating does not receive any cathodic protection current and it does not need any to prevent it from corroding.

Hydroscopic pipeline coatings such as FBE allow water molecules to pass through them, by the process of osmosis, to the pipe surface. This water is pure and pure water is non-corrosive to steel; hence no corrosion, cathodic protection or no cathodic protection.

From basic theory, the hydrogen ion consists of a single hydrogen atom minus its single valence electron embedded in a single water molecule. It is designated in electrochemistry text books as (H+.1H2O) or (H3O+).

When cathodic protection is applied, the FBE coating allows hydrogen ions to pass through it, by the process of electro-endo-osmosis, to the pipe surface. At the pipe surface the ion accepts one electron from the pipe and forms one atom of hydrogen which leaves one molecule of water at the pipe surface. Again, this water is pure and non-corrosive to steel, hence again no corrosion.

The water underneath a hydroscopic coating resulting through the process of osmosis is always pure and non-corrosive to steel. This is the reason that no significant corrosion is ever found under these coatings even in the water with hydrogen bubbles that are often observed under these coatings on cathodically protected pipelines when they are excavated and inspected. Just beware of the overly stringent -0.850v, CSE instant off cp criterion. History has proven the adequacy of the much less stringent -0.850v, CSE CP criterion measured with the CP applied (IR drop ignored) on steel pipelines with FBE coatings, and it reduces considerably the risk of forming the water bubbles compared to the overly stringent -0.850v, CSE instant off CP criterion which has the potential to completely disbond FBE coatings on buried or submerged pipelines over a period of time.

Respectfully submitted,
L.A.(Roy) Bash, P.E.

Ed Ondak Comments

Richard,

I have not had the time to digest the document in its entirety. A quick glance, looked pretty good to me. One area that concerns me is 3.2. We should not reference regulatory requirements as a basis for the need for external corrosion. This document will be referenced world wide and some areas do not have regulatory requirements. No one, whether it be a company or an individual, should rely on and do a corrosion control program because a regulatory body says so. That is what brought about the regulations that we are faced with today.


A good corrosion program should be based on the science as we know it today, prudent operation by a company or an individual, considering public safety and the value of the assets that are being protected.


Remember, if we don't protect our assets, we may not have any assets to protect.


Edward Ondak, P.E.

Update on SP0169 and CTW

The NACE International TCC Managing committee has asked us to be sure that everyone knows this is not a NACE sponsored blog. So notice that we have that now posted on the site. Remember also that we are asking for all comments about the proposed revision to NACE SP0169 document to help everyone keep up with the thoughts and comments of others. I am asking anyone who has good data to prove your point (no matter which position you support) to send that to the blog or make an appearance before the committee and present your findings.

The time is approaching for the NACE CORROSION TECHNOLOGY WEEK (CTW) in Salt Lake City this September 14 thorough 18. Please be advised that there will be another all day session concerning the revision discussions around the SP0169-2007 document.

The meeting is set for Wednesday September 17, 2008 from 8:00 am to 5:00 pm in the Sheraton City Centre Hotel. It will be held in the Seasons North room. Hopefully we can have another great meeting with many of you making constructive comments and suggestions to the TG 360 group.

I have not seen the new revision since the CORROSION 2008 meeting, but I do understand they have been working on the document. Hopefully, this information will be posted on the NACE website before CTW so we can digest it and give constructive information to the committee.

If you can not make the meeting, please pass along any information to the committee or to the SP0169.com blog site. I am planning to be there. Hopefully, there will be good attendance.

If there is a way to provide me any more information on FBE coated pipelines and the internal line inspection (ILI) or ECDA results along with CP data this would be very good information to either confirm or deny the theory that we have proposed as to why we do not need to consider IR drop at all test sites as many propose. Again, we question the need for having to consider IR drop (with a few exceptions) when most FBE coated pipelines were only protected using a -850 mV or more negative "ON" potential criterion at least up until 1992 - 96 time frame when RP0169 was changed to say you "must consider IR drop". We did not and still do not see external corrosion on theses pipelines with exceptions mentioned below. Please read the various postings below for more information if you have not.

We do not propose that FBE is the perfect coating system, simply that it does not shield CP currents when you have adequate CP (-850 mV "ON" or more negative or 100 mV of polarization) even if disbondments occur. Why could not this theory be applied to all pipelines that have non-shielding coatings or in areas where the coating is missing (holidays and damage)? Many in the industry are beginning to better understand the relationship between shielding and non-shielding pipeline coatings in relationship to cathodic protection, because disbonded and CP shielding coatings are where we are still seeing external corrosion on most pipelines, not lack of CP.

I have some more questions about IR drops:

1. Does not a large IR drop mean we have an excess of current in that area?
2. If so, where is the current going?
3. Is it not going to the structure where it is not shielded?
4. If current is being picked up by the structure, is not protection occurring? When using conventional current theory, we say where current enters the metal we have protection, so if it is entering the structure metal, how can we have corrosion? I do understand the idea that there may be some very limited sites on the metal that have microscopic areas that are more negative than that shown by the potentials of the reference cell, but again, if there is large "I" in the IR drop there is large current to over come these cells. When the "R" is large, the corrosion rate is less any way. This is where we must better train our technicians the proper techniques to identify and deal with these situations, not force everyone to use only one method to determine protection.
5. It is strange to me, we can protect an uncoated structure at much positive potentials "ON" than a -850 mV "ON". Why do we need more negative potentials to protect a coated pipe?
6. Does IR drop cause corrosion? (NO)
7. Does IR drop protect the pipe? (NO)
8. Is the IR drop in our potential measurement really an "error" or just part of the "ON" potential? (Of course it is only a part of the "ON" potential which is the correct potential for that location of the reference cell placement.)
9. When taking a polarized potential (Instant OFF) measurement over a structure, what does that potential represent? The entire surface of the structure? The top of the structure (assuming we have the reference cell directly over the pipe)? What about the bottom? What about under shielding disbonded coating? What about the sides of the pipe? What about two feet away?

We can go on and on, but I think you get the point. What we do in the field is not an exact science. We must better train those taking these potentials on how to identify problems area that require further testing, not restrict them to a couple of difficult, time consuming and costly criterion that do not solve many of the external corrosion problems in the pipeline (and other) industry today.

Thanks for all the support and interest in this Blog site. Our goal at Polyguard is only to provide a format for information to be distributed in a way that one does not feel intimidated or lacks the presentation skills of others. We really do want information from everyone! We need arguments that define all sides to this argument. This is the way we challenge each other better to know and understand what is the best way to protect our structures from external corrosion. This make us better neighbors, protects the environment, our companies assets and the helps to conserve our resources.

Richard Norsworthy
richnors@flash.net

Response to Mark and Ernie

Response to Mark and Ernie,

Mark and Ernie, thank you very much for your comments. These are the discussions that we will all learn from.

I would like to clarify a couple of points about my comments to be sure everyone is aware of what I think are some very critical points.

Mark Mateer says - “The reason FBE seems so effective is that is doesn't create any shielding problems that plague other coatings, not because it works better with any particular criterion.”

This is one of the points that I do not think everyone has understood. I am not saying FBE performance has anything to do with the criteria selected. Too the contrary, my point is that no matter which of the three criteria are used, we rarely (if ever) see external corrosion on FBE coated pipelines with the exceptions noted in the earlier presentation. The point is that most companies used an “ON” -850 mV (without considering IR drop) for the first 30+ years of FBE and some still use this criterion because it works for them. If considering IR drop is so important, why would we not have external corrosion on these pipelines? Toby Fore’s paper “First Generation of Fusion Bonded Epoxy Coatings Performance After 30 Years of Service – A Case Study” (CORROSION 2006 –Paper 06045) points this out very well. Even though the potentials at the sites studied were more negative than -850 mV “ON” versus copper/copper sulfate electrode, the point is that the criterion used was an “ON” -850 mV without IR drop consideration and there are no external corrosion problems!

There have been many cases of FBE disbondment, but because of the non-shielding property, the “ON” -850 mV (without IR drop considered) is adequate protection. If the “ON” -850 mV is adequate for the areas of non-shielding, disbonded, FBE coated pipelines it will be sufficient for any structure that has a non-shielding coating that allows the CP current to be effective or a bare structure with no shielding. Coatings that do shield CP current in disbonded areas, do not allow CP to be effective so corrosion can and many times does develop when water penetrates.

Mark Mateer says - “From a past PRCi study, we know that 850 IR considered works about 95% of the time when used correctly. In contrast, 850 polarized is about 98% effective and the 100 mV shift criteria is 100% effective.”

I have not seen a complete copy of this document, but I think there are many issues with this report. I do agree with the statement that the -850 mV criterion is more effective than -850 mV “ON” criterion, but only because you are applying more current, so you may force some current under disbonded coating. We must also include the problems that we create because of all the current we are now using. As Johnny, pointed out, the problems with interference are enough to make us stop and consider what other potential problems we are creating. Corrosion problems from interference happen much faster than those from inadequate CP. Of course, we also have to consider the potential damage from more coating disbondment problems and possible hydrogen embrittlement, etc. (Especially as we move toward higher strength steel pipelines). More energy consumption and increased cost of surveys and equipment must also be considered. Ondak and Rizzo mention this in their paper at CORROSION 2008 – “ELECTROCHEMICAL ANALYSIS OF PIPELINE CP CRITERIA” – Paper 08068.

I would not say that the 100 mV criterion is 100% effective, especially for pipelines that have disbonded and shielding pipeline coating, or in other areas of shielding, etc. Bob Gummow addresses many of the problems with this criterion in his paper “Technical Consideration on the Use of the 100 mV Cathodic Polarization Criterion” Paper 07035 from CORROSION 2007. Though I do not agree with all Bob has to say or has written, I know he has a very vast knowledge of CP criteria, etc. and I have learned many things from him.

How many times do we find that we do not have 100 mV of polarization when we have an “ON” -850 mV? Not many from my experience. When protecting bare pipe using the 100 mV of polarization do we see corrosion once the pipe is polarized? If we provide enough current to meet the 100 mV of polarization on an uncoated pipe, we rarely have external corrosion unless there is shielding or interference. Same as on coated pipelines with non-shielding coatings. How about that! But we must consider IR drop to have effective protection according to certain folks and NACE SP0169 - 2007.

Ernie Kleckha says - “A good impressed current cathodic protection system can throw some current under a disbonded coating or at least increase the pH.”

Areas where we have coatings that shield CP current in disbonded areas, we have the potential for corrosion. As Ernie mentioned in his comments, you can throw “some” current under disbonded, shielding, coatings, but this is very hard to determine and almost impossible to measure in an effective way. There is no way of knowing if adequate current will penetrate under these coatings from above ground surveys.

I have seen times when a coating that would normally shield CP, allowed enough CP current to increase the pH to a protective level under the disbonded coating. These areas did not have external corrosion, because the CP could be effective! Again, if a coating is non-shielding in that environment (for what ever reason) it will allow enough current to effectively protect these surfaces.

THE POINT IS THAT IF WE USE COATINGS THAT ALLOW CP CURRENT TO BE EFFECTIVE, WE DO NOT HAVE EXTERNAL CORROSION PROBLEMS WHEN WE USE AN “ON” -850 mV WITHOUT IR DROP CONSIDERATION CRITERION! [Exceptions as mentioned earlier] WHY DO WE CONTINUE TO USE COATINGS THAT SHIELD CP IF DISBONDMENTS OCCUR?

Ernie Kleckha says - “I think we should use the IR drop and not just “consider the IR drop.” We can use IR drop to find pickup points, discharge points, AC and DC interference, and many other potentials damaging conditions.”

I agree with Ernie! There are times when considering IR drop is useful. As I and others have said many times, TRAINING cathodic protection personnel when it is important to “consider” and use IR drop is where we should be spending our time, not forcing everyone to consider IR drop for all readings!

There is certainly much confusion in the industry about what to do with “IR” drop. Roy Bash covers many topics in his CORROSION 2008 paper “Pipe-to-Soil Potential Measurements, The Basic Science”. Again, I may not understand or agree with all Roy has to say, but I certainly learn from his discussions and do agree with much of it.

Conclusion

There have been many papers written about this subject, but few actually discuss the real reasons for corrosion that is found on the pipelines or test structures. I think we are missing what is right in front of us. If FBE coated pipelines do not have external corrosion problems when using the “ON” -850 mV criterion without consideration for IR drop (with the exceptions listed before), even though there are many cases of disbonded FBE, then why are we having such any issue with using this criterion? We have over forty years of proof!

The issue is not the criterion being used. It is the use of coatings that shield CP when there is a disbondment, interference from all the CP in the ground, high powered AC interference and such related issues. The GTI Report # GRI-00-0231 (in which Kevin Garrity was an author) even states “Disbonded coating does not affect the cathodic protection currents but does not (?) significantly affect the electrical currents outside of the disbonded region.” What this is saying is that under disbonded coating that shields you cannot effectively control the corrosion with CP. Just because you have corrosion, does not mean your CP is inadequate. Just because you meet or exceed an certain SP0169-2007 criterion does not mean you will not have corrosion.

We encourage more debate and comments on these topics.

Thanks for visiting SP0169.com!

Richard Norsworthy

Mark Mateer Comments

In response to Richrad's request for information about FBE and CP, I believe the correct explanation for the success of FBE with the 850 IR considered criteria does not relate to criteria at all. From a past PRCi study, we know that 850 IR considered works about 95% of the time when used correctly. In contrast, 850 polarized is about 98% effective and the 100 mV shift criteria is 100% effective. The reason FBE seems so effective is that is doesn't create any shielding problems that plague other coatings., not because it works better wtih any particular criteria.

I don't believe FBE wotks any better with 850 IR considered than any other criteria, it is just a good coating that works well under almost all conditions. 850 IR considered will work well if done properly. It does have more room for error, which is the point of contention.

Thanks

Mark Mateer

Ernie Klechka Comment

Richard,

I really liked you NACE presentation. Are the photographs available for inclusion in the CCCP class?

I do disagree with your comments that IR drop is not important. As you are aware we can use IR drop to find stray current on pipelines.

You also seem to imply that IR drop is a constant. You and I both know that IR drop will change in current pickup and discharge areas, near anode ground beds, and at areas with high current demand.

I agree that much of the problem centers around shielding. Coating that shield the pipeline cause erroneous conclusions concerning cathodic protection. Probably the area of shielding that causes the most concern is casings. However, shielding is not the only problem on pipelines.

Your slides show several poorly coated field welds. To me this points to poor field coating repair practices. Sure shrink sleeves can be poorly applied or subject to soil stresses that cause disbondment and shielding, but the cathodic protection system should not be allowed to be compromised because of a poor coating. A good impressed current cathodic protection system can through some current under a disbonded coating or at least increase the pH.

I think we should use the IR drop and not just “consider the IR drop.” We can use IR drop to find pickup points, discharge points, AC and DC interference, and many other potentials damaging conditions.



ERNEST W. KLECHKA P.E. ( ALASKA AND OHIO)

Another view point from an operator

I am a relatively new to the corrosion control industry. I have been exclusively dealing with corrosion control for the last 9 years. Before that I was involved in the construction phase of our industry. I have been following the developments in the debate to change the CP criteria with much interest.
I am responsible for corrosion control on a distibution system that has been around since 1934. Needless to say we have a lot of bare pipe as well as any coating that you can think of. Seeig as the regulatory bodies do not differentiate a pipeline in it's own corridore from a distribution line installed in close proximity to other utilities the -.85cse (instant)off criteria will impact us also.
For now let's lay aside the cost and hassle of complying with -.85cse off. Neither cost nor hassle should dictate our criteria no more that regulatory bodies desiring to make thier job easier. However, the current densities required to operate a system like ours at -.85cse off will cause adverse problems. First the interference we will create with water, sewer, and other infrastructure will corrosion problem not only on our system but also on the other utilities. Next, the high current densities wil cause disbondment on some of our older coatings and will create a whole new set of problems. We have not seen any corrosion on FBE coated pipe that cannot be attributed to other circumstances. If the science proved that we needed this new criteria I would gladly support the efforts. However, these efforts to change the criteria seem to be driven by market forces and not scientific reasons.

Johnny Martin
Willmut Gas Co.

ANOTHER REASON WE NEED TO FIGHT THE PROPOSED CRITERIA SECTION CHANGES

When we look at all the reasons proposed for the changes to the SP0169-2007 (RP0169) one consideration that must be involved in the discussion is the cost to implement the proposed criteria changes. Though some say cost should not be considered in providing the industry with a Standard Practice, it must be considered when companies are asked to spend a considerable amount of money, with little or no improvement to the integrity of their systems.

There are many other changes that are needed, but I believe there are few needed to the Section 6 that is the main topic of discussion. Some of those changes are discussed in the other Blog topics.

In this section I would like to discuss the cost of implementing and maintaining some of the proposed changes to the criteria section. When I have asked some of the experts about how do companies that use galvanic anodes that have no access (or even if they do) prove a polarized potential or 100 mV of polarization, they say the companies can install coupons to confirm these two criterion.

There are many inherent problems with coupons and their design. Some of the issues with coupons include, but are not limited to:

1. Where is the coupon placed in relationship to the structure? (How close what position around the pipe, etc.)
2. What size should the coupons be? (They always say it should represent the size of the largest holiday in the area. Now how are we going to know that? If the pipe is bare?)
3. What shape should the coupon be? (Round, square, rectangular, etc.)
4. Should the coupons be coated on one side?
5. What material should the coupon be made of?
6. Where should the reference cell be placed in relationship to the coupon? (Should it be in the tube above the coupon with native soil, special backfill, or no backfill? Should it just be placed on the ground above the soil?)
7. Should the reference be Copper/Copper Sulfate or zinc?
8. Should you wet the soil in the tube before the potentials are taken?
9. Where should the reference cell be placed in relationship to coupon?
10. There are many different types of commercial coupon test stations, what are the differences?
11. Does the potential reading really represent the potential of the pipe?

Once you figure out what type of coupon to use and where to place it (etc.), then you have to pay for it, install it and maintain it. The coupon test stations with stationary reference cells, must concern themselves with how long the reference cell will be accurate, etc.

Below is one example of the cost of using these coupons on a large gas distribution/pipeline system in the southern USA.

“Richard, it would cost (Company name with held) in excess of $100,000,000 to install coupon test station on magnesium protected distribution CP Zones and in excess of $5,500,000 for additional impressed current on our transmission systems. There would also be an increase in labor and transportation to monitor the -850 "off". These are conservative numbers!”

These numbers can easily be multiplied by each company that has galvanic protected pipelines and may be forced to use coupons to prove their protection level. These numbers do not reflect the cost of maintaining and replacing as needed.

Another large gas distribution/pipeline company in the central northern USA provides similar information and opposes such changes. They do not see any need for IR drop consideration from their many years of using an “ON” -850 mV criterion with no CP related failures reported.

The following is extracted from a power point presentation and a letter to the TG 360 committee:

• Does not support revisions to Section 6 that would eliminate the -850 mV “On” criteria or requirement that reading needs to be corrected for IR drop.
• CP (corrosion) problems that we have identified are not caused by lack of CP, but rather by stray current, interference, or third party damage.
• Proposed changes in SPO 169 would probably require large effort to install coupon test stations and increase in CP output
• It is possible that large expenditures could be made that would result in no improvement in system integrity. It would be more prudent to direct resources to known issues.

“We have operated our system successfully using the -850 mV “On” criteria for the past 37 years and are experiencing declining leak rates on steel pipe. We have not had a reportable incident caused by a corrosion leak on protected steel pipe in many years. Operating our corrosion control program under the current standards in combination with a leak survey program has been very effective in maintaining system integrity. The proposed changes to SPO 169 could cause a significant increase in our operating expense with little or no benefit.

If these changes are adopted into DOT code, we would need to install coupon test stations to validate the IR drop measurement. It could potentially cost millions of dollars to install these test stations and increase CP output, and result in little or no improvement in system integrity.”

These are just two examples of companies that have a real problem with the potential cost of the proposed changes that may require installation of coupon test stations to prove the criteria is being met.

Transmission pipeline companies that use mostly impressed current CP will be required to do polarized potential surveys which once again means additional cost and effort. There has not been a decision made on how often these companies may have to do such surveys to satisfy the regulatory requirements of each country, state or local government. If these surveys have to be performed annually, this presents a real economic challenge.

With NACE International wanting to project a GREEN image, why do we want to propose such a drastic change in the cost of performing a CP survey to satisfy a criterion that will require significant effort, energy usage (the amount energy used can be 2 to 3 times more to achieve a polarized -850 mV versus an -850 mV ON {without IR drop considered} and up to 5 times more than using a 100 mV polarization change), more vehicles and equipment to do these more complicated surveys, potential for more interference leaks caused from more CP being used, as well as potential damage from hydrogen and further disbondment of coatings. This will not project a GREEN image.

Politically NACE is now tied to ANSI and ISO so they have to follow certain guidelines when changing standards. One problem that some have on this committee is that the fear if we do not make these changes, it will say that NACE is not progressive in providing change to improve these documents. Since ISO, other organizations and some countries require more stringent criteria, they are of the belief NACE must follow because these organizations must know what they are doing and if we want to be the leader in corrosion control, we must change to be more stringent! I have no problem with change when it is needed and proven to be needed, but just to change because some else does makes no sense to me.

2 + 2 equals 4 in most parts of the world and it works. What if a certain group decides that it should be 7? Does everyone automatically without reservation change to seven because a few experts decide it is better because one of them wrote a paper about it or someone in a particular country is doing it?

NACE should be and I think is the leader in the corrosion community because we have consensus documents, not one formatted by some select committee that knows more than any one else or can afford to go to the meetings. I think progress also includes correcting mistakes made by former committees. For example, when we were forced to consider IR drop in the -850 mV criterion back in 1992 (I think), this was a mistake that has led some to believe that it is the same as the polarized potential so why not just have the one polarized -850 mV criterion. This was a compromised change in order to get the document out the door. Some will know what I am talking about. This was wrong then and is now. Change it back to “IR should be considered” when unusual circumstances require it.

The cost to the world wide industry will be tremendous with little or no improvement. There are certainly times when more stringent criterion is needed, but it should be forced on every situation, because it works in some unusual environment.

I challenge those who are in favor of the proposed changes to provide us with the significant documentation that proves the changes are needed so we can all review and comment. I also challenge those who believe as I do that we need to go back to a reasonable criterion that allows us to use the -850 mV ON with consideration for IR drop only when unusual circumstances require it to get your information together. The industry has over 50 years of data that can be used to prove much of what we are saying, but it is typically ignored in favor of some scientific papers that many times did not prove the point in most folk’s minds.

By the way, I am still waiting for someone to prove me wrong about the use of FBE coating and the fact that we do not have significant, if any, external corrosion problems even though most have used the -850 mV “ON” without consideration for IR drop (at least the first 30 + years of FBE usage). There have been disbondments, adhesion failures and blistering of FBE since the beginning, yet unlike most coatings there are not the shielding problems. So why do we not have external corrosion if we must have a polarized -850 mV? This is an important issue and the industry must use the data from the ILI pig data and ECDA data to prove this to the committee.

If you have not done so please read the other postings. Go to the Polyguard website at http://www.polyguardproducts.com and read articles about why we still have external corrosion on pipelines (because of coatings that shield CP when they fail) that are cathodically protected.

Please send comments and we will post them. We need everyone’s input to keep this problem in front of the cathodic protection industry around the world. Thanks for your help and please let me know if I can help you with pipeline coatings or CP questions, etc.

Richard Norsworthy
Polyguard Products, Inc.
richnors@flash.net

criteria and FBE

To All,

I am in the process of writing a paper for NACE 2009. The paper will be about the relationship of FBE and cathodic protection criteria. As I mentioned in my speech before the TG 360 group (changes to SP0169) the industry rarely sees external corrosion on FBE coated pipelines even though most of the pipelines have been protected by using the "ON" -850 mV criterion, especially for the first 30 + years that FBE has been used.

I need to find as many case histories as possible for showing that this is true. We can do this generically, but it will hold more weight if we can actually show the company, etc. Preferably, we will have case histories where we can show no or otherwise explained external corrosion on FBE coated pipelines over the period of time when the only criterion used was an "ON" -850 mV.

Since FBE allows CP to be effective should there be disbondment we do not normally see external corrosion on FBE coated pipelines. Most of the times we have seen external corrosion was in areas where the CP was shielded or there was an interference problem. In most cases, companies used only an "ON" -850 mV, yet we did not and do not see external corrosion on FBE coated pipelines.

So what I need are case histories that show (as much as possible):

1. What criterion (criteria) was (were) being used?
2. What potentials ranges were in the area inspected? (with or without IR drop consideration if possible to give this information)
3. Did ILI or ECDA show external corrosion? (PHOTOS where possible)
a. If so, was it under the FBE or other coatings?
b. If so, were there other reasons why the corrosion existed? (shielding, AC or DC interference, etc)
c. Were pH readings taken?
d. Was it evaluated to see if it occurred during times CP was not applied or effective? (if data is available, etc.)
e. Was it active or old corrosion?
4. Age of the system.
5. Thickness of the FBE.
6. Soil or environment in which the pipe is in service.
7. Service temperature of the product.
8. Type of girth weld coating used.
9. If you have examples of surveys (CIS, DCVG, ACVG) showing protected levels (especially with the polarized -850 mV), yet you still had external corrosion (caused from coatings that shielded, etc.) when the line was inspected, this is valuable information also to prove the point that nothing is 100%. Once again case histories and photos are valuable!
10. Any thing else that will help!

If any one would like to co-author the paper, you are more than welcome to work with me on this project. This information is critical to demonstrating why an "ON" -850 mV is an acceptable level of cathodic protection, even when not considering IR drop. Now is the time for all good women and men to step up give the industry something to help us solve this problem. We all know field data is more accurate and valuable than the lab and test data being quoted by some on the committee.

As we know if these folks get their way they will force us to all go to a polarized -850 mV or the 100 mV of polarization. Please help those of us who know from field experience what we are doing is working without having to consider IR drop except in very unusual areas and circumstances that can be given.

Since the PCRI report is quoted often in the defense of the polarized -850 mV criterion, I need a copy if anyone has one. If not let me know how to get a copy and I will buy it. From some of the data that has been shown, I do not think it show any definite conclusions.

This will also be posted on the SP0169.com blog site. If you have not visited it there are some good comments and information. We will be glad to add yours to it. It can be anonymous if you wish, but I would at least like to know who you are and I decide what goes on, etc. I also welcome comments and case histories from each side of this issue, because that is the way we all learn and make our industry better.

Thanks for your help and we must pull this information together to head off the proposed changes. We can make this a very good document if we work together with a united effort.

Richard Norsworthy
Polyguard Products, Inc.
214-912-9072

Comments from Tom Laundrie

I was reading the TG 211 Proposed Nace Technical Committee Report, "Report on the 100-mV Cathodic Polarization Criterion" Draft #3b. Some of the statements used in this document can be applied to the logic of leaving the -0.85 volt On Criterion in the SP0169 document. These quotes are taken out of the section on Advantages and Disadvantages for Pipeline Applications.

First I'd like to point out that it has been shown that all we really need to reduce corrosion to an acceptable level is 100 mV of polarization, and that in most cases the -0.85 Volt On Criterion is already conservative and has a "safety factor" built in to it.

Secondly, the document points out that the 100 mV criteria uses much less current and is much less likely to cause problems. This same logic can be applied to using the -.85 On Criterion as opposed to the -0.85 Volt Instant-Off Criterion.

Advantages and Disadvantages for Pipeline Applications



For pipelines, the 100-mV cathodic polarization criterion has advantages and disadvantages when compared to the -850 mVCSE criterion. As indicated in Figure 3, the current density to achieve 100 mV of cathodic polarization is typically less than to achieve the -850 mVCSE polarized potential criterion, especially in well-aerated and well-drained soils in which the native corrosion potential may be in the -200 to -400 mVCSE range. The 100-mV criterion therefore is normally more cost-effective because of the lower current requirements. The Dearing example21 demonstrated that if the -850 mVCSE criterion were to be restored on the section of pipeline under test, additional expenditures for more cathodic protection current would have had to be made, whereas to satisfy the 100-mV cathodic polarization criterion, the existing current output was sufficient and could probably have been reduced. Such a reduction in current would result in further savings in power costs and extended groundbed life. This makes the application of the 100-mV criterion to bare or poorly coated structures more appealing because the current demand on these structures is usually high. The reduction in current demand also reduces the influence of the cathodic protection system on foreign pipelines, reducing the likelihood of stray current interference.



Attempting to achieve a minimum of -850 mVCSE on a coated pipeline may result in highly negative polarized potentials that can create the risk of hydrogen embrittlement on susceptible structures, such as high-strength steels, some types of stainless steels, and prestressed concrete cylinder pipe (PCCP) as indicated in SP0169.1 Similarly, the standard cautions against the use of excessively negative polarized potentials to minimize coating damage, such as cathodic blistering and cathodic disbondment. The use of the 100-mV cathodic polarization criterion would typically minimize both these risks. On structures composed of amphoteric materials such as galvanized steel, aluminum, and lead, all of which are subject to corrosion at highly alkaline conditions, satisfying the 100-mV criterion would normally result in a lower pH than if a polarized potential criterion were utilized.


Third: They go on to point out the cost disadvantage of measuring the 100 mV Criterion and the errors that can occur and must be accounted for (sounds like "consideration").

Although there is sometimes an economic benefit to operating cathodic protection systems based on the 100-mV cathodic polarization criterion, some of this advantage is lost because the testing regimen is more complex. Because this criterion typically relies on measuring either a native corrosion potential before the system is energized or a decayed off potential after the system has operated for a period of time, this is an extra step compared to “on/off” potential surveys conducted for comparison to a polarized potential criterion. This additional step increases the survey costs and introduces the possibility of measurement errors.



Although it is not necessary to deenergize the system until all polarization has dissipated (only until a minimum of 100 mV of depolarization has been achieved), it is usual for the systems to be turned off for periods of time that may extend into weeks. Pawson22 indicated that in the majority of cases on bare pipelines, the pipeline potentials were still depolarizing after 100 days and that, for two particular bare pipelines, there was no correlation between the original native corrosion potential and the depolarized potentials.



During the depolarization time period, protection is being lost, and the risk of corrosion activity increases. Also, when the decay period is long, seasonal and weather effects can interfere with the depolarization, either accelerating or retarding the depolarization, thereby introducing error. For long periods of depolarization, potentials are typically recorded to ensure the accuracy of the data and verify that local soil conditions did not change significantly.



Fourth: The document points out the errors involved with using Coupons to represent the pipe potentials.



Coupons are often used in situations in which it is difficult to obtain accurate native corrosion potentials or depolarized potentials because of the presence of uninterruptible current sources. Nekoska35 has stated that a coupon potential “always decays to its corrosion potential.” However, the coupon depolarized potential does not necessarily represent the pipe depolarized potential nor the depolarized potential of a similar-sized holiday in similar soil conditions because depolarization at a pipe holiday is affected by the depolarization process at other pipe coating holidays. The coupon, therefore, could have different decay characteristics than a pipeline coating holiday.



Thanks,

Tom Laundrie
Sr. Materials Engineering Specialist
NACE Cathodic Protection Specialist

Tom Hamilton comments.

I was trained as a metallurgical engineer. My first exposure to corrosion was in a course taught by Henry Van Droffelaar and Jim Atkinson. The notes from that undergraduate corrosion course were published and distributed by NACE in book form, “Corrosion and its Control”. I continued post-graduate studies in corrosion with Dr. Atkinson.
My transmission pipeline career began at TransCanada PipeLines. While I was there, we sponsored the development of the first instrumentation to allow instant-off pipe to soil readings on our close interval surveys. In that era, we also hired the best consultants in our business, including Bob Gummow, Tom Barlo and John Dabkowski, to extend our knowledge of the CP arts.
I was an early believer in using instant off surveys to limit the unpleasant effects of IR drop on our P/S readings. This technique was the principal method we used in the ‘80’s to account for IR drops in our field measurements. At first I found it interesting (confusing) that previously in the lab, we had not used interrupted readings when we recorded data. It was explained to me that this was because in the lab we were typically using conductive electrolytes, placing the tip of our Luggin capillary very close to the specimen surface, and limiting the IR drop in our measurement circuit to virtually zero using electronics. That made sense.
I thought I had a pretty good understanding of CP criteria and pipe to soil measurements. At TransCanada we had hosted two sites for the PRCI research that Dr. Barlo had led. The 100mV criterion made sense to me. Current interruption made sense to me, as I had measured huge errors in measurements that I had made over the years on many miles of CIPS that I had done, and on thousands of miles of pipe that I had taken care of. I learned my fieldcraft from Robin Pawson. I knew well the errors that can corrupt a P/S reading due to poor survey technique. Unbalanced or otherwise poorly maintained half cells. Poor half cell contact that can overwhelm even meters with high input impedance. The price of selecting a very very high input impedance for your survey. Lots of things that take time effort and experience for new practitioners to learn. It sure helps to have good mentors around for guidance!

So how did I end up on this side of the fence in the present debate? Curiously, I initially threw in with the “850 On” crowd because of my libertarian political leanings. You see, a couple of years ago, I worked on the revision of RP 0502, a practice that I had worked with for some years. We techies were interested in making revisions to that document since it had proven itself to be overly conservative in places, and we knew we could improve on it by applying various lessons learned during the five years of implementation. We were going to add value to the RP based on the results of our surveys, and on the many excavations we had performed. Science was going to be advanced, and our Companies were going to receive value due to our changing of these overly conservative requirements.
I was shocked when our committee was shut down. It seems that science was not to advance that day. It was made very clear to us that if we made any movement in a non-conservative direction, that the credibility of NACE might be undermined, since the DOT might decide that they did not like our changes, and could simply refuse to acknowledge our revised version in their regulations!

The same phenomenon seems to be at work today, on yet another NACE committee. Both science and empirical data are being undermined by political process. You see, it is much easier for the DOT (or PHMSA) to “persuade” our committees to change our recommended practices than it is for them to field large numbers of qualified auditors. I am very aware of this phenomenon. I have compliance auditors reporting to me. We much prefer to audit hard numbers rather than trying to audit thoughts or whims. I know that. It is impossible to audit someone’s intentions. Or their motivations. It is only possible to audit their work output versus agreed-upon requirements. Their adherence to written policy and procedures.

I know that it is difficult to audit a Company’s “consideration” of IR drop. Difficult, but not impossible. And that gets my dander up. Why should our Recommended Practices be modified into something that they were not intended to be, just to satisfy the Regulators? Why are the legitimate technical positions and opinions of the founding members of this association being ignored and marginalized? Why do the critics not have to prove the inadequacy of the criterion before they throw it out?

It is assumed that we have a criterion problem. I’ve not seen that in my 29 years of practice. My embarrassing leaks have always been due to inadequate CP, not inadequate criteria. It’s the practice of engineering that has failed me, not the theory of engineering principles.

I for one will continue to throw my support behind the movement to restore the original 850 On criterion, as stated in the original version of RP 0169.

And by the way, the more I look into the science behind the 850 On criterion, the more I think we’d better pause and confirm once and for all its technical applicability. I’ve not seen anything yet that leads me to believe we’d better throw it out…So I’m also going to support the movement to more fully understand the science behind the 850 On criterion.

Perhaps you’ll join us?

These comments are provided by Tom Hamilton and are his comments and experiences, not those of his company.

NACE CORROSION 2008 - TG360 (SP0169) MEETING

I want thank everyone who participated in the TG 360 (SP0169) meetings last week at NACE CORROSION 2008. Hopefully we have helped the committee with making a better decision about what revisions are made to the SP0169 document.

For those that were not there or want a copy of my presentation to the committee, we will be posting that on the web very soon. It hit me Monday night (March 17) that we have in over 40 years thousands of miles of FBE coated pipelines over the world that have been in service. For the first 30 to 35 years the only criteria that was used to protect these pipelines was an "ON" -850 mV or more negative without much consideration (if any) for IR drop. Some still use this criteria today for these lines.

We have now run many ILI (smart pigs) thorough these pipe lines over last 20 years, yet find very little, if any, external corrosion on these pipelines. When external corrosion is located it is usually because of shielding from a foreign object (rocks, plastics, other metal in close proximity, high resistant soils, etc.), from other coatings (usually on girth welds or repairs) that have disbonded and shield the CP (such as solid film backed tapes, shrink sleeves, etc.) or from AC or DC interference. There are cases where inadequate CP (if any) was applied for a period of time and corrosion may have developed.

For those of you who have FBE coated pipelines, please look at this data and see what I am talking about. If we can prove this fact, this disproves the theory that we must always consider IR drop or use a Polarized -850 mV to protect our pipelines.
If these things are true would we not have extensive external corrosion on FBE coated pipelines? Especially where FBE coating failure and disbondments have occurred! From my experiences and discussions with many companies external corrosion is a very rare occurrence on FBE coated pipelines. This also proves the validity of using pipelines coatings when possible that have proven non-shielding (to CP) properties if disbondments occur(such as FBE or Polyguard RD-6).

There is nothing in this industry that is 100%. I am sure there are some rare instances where external corrosion has occurred that cannot be explained. In those cases none of the criteria would have likely worked.

Pipelines coated with coatings other than FBE still have external corrosion occurring, but again these are in areas of disbonded coating that is still shielding the CP. In these cases, increasing cathodic protection will have minimal affect in most cases.

The point here is that increasing the amount of CP or changing to a more stringent criteria will not give the end user much BANG for their BUCK. The scales are weighted in this argument on the side of leaving the criteria as it stands and using better tools (ILI and ECDA) and training for those responsible to actually be able to control the external corrosion problems without tying their hands to more stringent criteria. Using these tools to find areas of shielding (whether coatings or other) and correcting those areas by recoating with coatings that have proven non-shielding properties will help eliminate many of the ongoing external corrosion problems.

I will ask anyone who has data, reports and papers that can be posted on this site to please send those, but more importantly send this data to the committee. By the way this site accepts comments from all sides of this issue, not just opposition to these changes. We all learn from those who study this issue and who have written papers and made presentations in support of the proposed changes. There are times when considering IR drop and using a polarized -850mV criterion are needed and valid, but I do feel these are rare occurrences.

Richard Norsworthy

Commentary on SP0169

COMMENTARY ON SPO169 PROPOSED REVISION
BY
RICHARD NORSWORTHY

ABSTRACT

As important as cathodic protection criteria is to external corrosion control, it may not be the most important issue facing those concerned with proposed changes to SP0169-2002(7). The document clearly states the intent of the document is effective control of external corrosion. Many seem to ignore the intent of this document and concern themselves only with cathodic protection and related criteria. Changes are needed in this document, but most are not in criteria section.


As we struggle with the proper revision of this very controversial Standard Practice we must not lose site of the purpose of this NACE Standard. This standard practice presents procedures and practices for achieving effective control of external corrosion on buried or submerged metallic piping systems. Confusion remains over the intent of this Standard Practice.

As important as cathodic protection is to buried and submerged structures that are also coated, it is not the most important factor in controlling external corrosion. Some consider design along with electrical isolation to be the most important. Pipeline coatings actually protect more pipelines from external corrosion than cathodic protection and electrical isolation. Coatings are often thought of as the “first line of defense” in the war against corrosion.

Each protection method is important in controlling external corrosion on pipelines and related structures. Each has a particular role, but must be used in conjunction with the others to successfully protect these structures. Nearly all companies must deal with pipeline systems that are over tens years old. Most companies have operating pipelines over fifty years old, which means the electrical isolation, the cathodic protection system and the coating systems (if used) have out lived their design life.

DESIGN

In the design phase of a project, the proper use of all these factors must be considered to control external corrosion. Electrical isolation when properly used allows the cathodic protection to be effective and economical on that part of the structure it is intended to protect and not be consumed by foreign or un-intended metal structures.

COATINGS

If coatings are properly selected and applied to the pipeline before and during construction, the amount of cathodic protection needed is considerably less. This section of the SP0169 should be stronger to provide guidance for selecting pipeline coatings for new pipe, girth welds, rehabilitation and repair. Since corrosion under disbonded coating is a major cause of external corrosion, one must consider how effective the CP system will be if the coating adhesion were to fail. Will the CP system be effective in controlling external corrosion under disbonded coating if electrolyte penetrates? Most pipeline coatings shield cathodic protection when disbondments occur. Some coating systems are non-shielding and compatible with CP if a disbondment occurs therefore the corrosion rate is significantly reduced or eliminated. Ideally, these two systems work together so that if the coating disbonds allowing ground water to contact the pipe surface the CP system will continue to function. These are called non-shielding, CP friendly, CP compatible, fail safe or partially shielding pipeline coatings.

CATHODIC PROTECTION

CP systems are designed around the coated pipeline using all the related equations and past experiences. CP current is only effective where it has a path to the pipe. Pipeline coating systems must have electrical insulating or dielectric strength in order to divert the CP current to the areas of the pipe where the coating has holidays or damage that exposes the metal to the current. Disbonded, shielding coatings do not allow sufficient current to the pipe steel therefore external corrosion becomes a problem.

Non-shielding coatings, will allow enough CP current to significantly reduce or eliminate corrosion on the pipe metal if the coating disbonds and electrolyte penetrates. This requirement has lead to the distinction between coatings that shield the pipe from the CP system and those that are classified as permeable or CP-compatible.

SHIELDING VERSUS NON-SHIELDING PIPELINE COATINGS

There have been numerous articles written about CP shielding and the corrosion problems that develop. Many articles have also been written about the value of using pipeline coatings that are non-shielding. Only a few are referenced in this article. The relative tendency of pipeline girth weld coatings to shield cathodic protection (CP) current was studied in the laboratory. A key consideration should be "Will the coating shield CP if the bond fails? '' However, all coatings experience some disbondment and, therefore, the behavior of a disbonded coating is important in the overall performance of a coating system. Even with adequate cathodic protection (CP), corrosion can occur under most disbonded coatings. With adequate CP, fusion bonded epoxies (FBE) do not totally shield CP currents ; therefore corrosion is not a major problem. However, FBE maintains its insulation properties in the presences of moisture and cathodic protection current.

TODAY’S TECHNOLOGY

Internal line inspection tools (ILI) and External Corrosion Direct Assessment (ECDA) allows companies to see the condition of pipelines, no matter the age. In some cases, external corrosion is a significant issue. CP may not have been adequate, especially in the early days, because of a lack of knowledge, improper design and monitoring. Too many companies use CP as a “cure all” for external corrosion on coated pipelines, but find out they still have active external corrosion through ILI or ECDA. Today, inadequate CP is rarely the cause of external corrosion.

Stray currents from DC or AC sources cause corrosion problems. Shielding of the CP current by soils, rocks, and other non-conductive materials may be the reason for external corrosion. Even though the US Department of Transportation regulations call for use of ‘non-shielding coating’ most pipeline coating companies do not understand or test coatings for potential CP shielding problems. Slight water absorption only corrodes steel if the cathodic protection is not adequate, or if electrical shielding is present. The industry is beginning to recognize the importance of selecting pipeline coatings that allow CP to be effective, if there is disbondment.

EFFECTIVE EXTERNAL CORROSION CONTROL

As more and more companies begin to realize many of their external corrosion problems are not from lack of CP, but from other causes, they can more effectively spend their dollars and man power. There are great examples of this problem. A close internal survey found inadequate CP. The pipe is exposed, to find deteriorated pipeline coatings which have allowed pipe metal to be exposed to the electrolyte, but there is no external corrosion, because the CP could effectively protect the exposed metal even though it showed to be inadequate. Where criterion is achieved, external corrosion was located through ILI or ECDA. This corrosion is usually caused by disbonded, coatings that are shielding the CP therefore the CP was adequate. ILI on a newer pipeline coated with FBE show no corrosion except at the girth welds where a shielding coating was used. Adding more CP or changing criterion will not stop this corrosion! Field inspection to renew or repair badly deteriorated coatings is crucial in reducing pipeline corrosion.

DO WE NEED TO CHANGE THE CRITERIA?

Criteria as stated in SP0169-2007 are sufficient for controlling corrosion if CP current is allowed to be effective. Proper educate of corrosion control and pipeline integrity personnel to identify the actual cause of external corrosion is more critical than changing criteria.

Taking the pH under any disbonded coating is a very good indicator of CP effectiveness. An alkaline or high pH (9 to 13), on the pipe surface or under disbonded coating is an indication that CP current is effective and corrosion is reduced or eliminated. If less than a pH of 9, corrosion is possible. The lower the pH the more likely corrosion will be a problem.

Field data derived from pipe exposures with actual CP potentials taken at the time of the excavation will indicate if adequate protection is being achieved. These potentials along with pH readings (especially under disbonded coating) and proper evaluation of the coating will indicate if CP is adequate. ILI tools find possible points of external corrosion that must be properly evaluated before increasing CP. External corrosion is rarely present under coatings that are compatible with CP.

CONCLUSIONS

Adding more CP does not control all external corrosion problems. More CP may cause further disbondment exposing more pipe to possible corrosion because of the shielding affects of the coating. The industry is misappropriating many dollars on un-needed CP to meet a certain criterion, instead of rehabilitating pipeline coatings that shield CP, correcting other shielding situations, interference, shorted casings, metal shorts, or failed electrical isolation devices. Meeting CP criteria does not solve most external corrosion.

The role of effective pipeline coatings is often overlooked when evaluating external corrosion. When ILI tools or ECDA show no indications of external corrosion under disbonded or blistered coatings with electrolyte under the coating, these are non-shielding coatings. The pH of this water is usually 9 or above. Under shielding coatings corrosion is usually found and the pH is under 7. Therefore, the committee and industry should concentrate more effort on using non-shielding coatings and replacing shielding coatings that have disbonded to allow CP to be effective and effectively control external corrosion.

SP0169 - 2007
G. Mills, “The Role of The Pipe Coating as an Engineered Part of The Cathodic Protection System”; NACE CORROSION 88; Paper 237
T. Jack, F. King, M. Kolar, and R. Worthingham; “A Permeable Coating Model For Predicting the Environment at the Pipe Surface Under CP-Compatible Coatings”; NACE CORROSION 2004; Paper # 04158.
T. Jack, F. King, Y. Cheng, and R. Worthingham, “Permeable Coatings and CP Compatibility. Proc. IPC ’02 4th International Pipeline Conference, (ASME, New York, NY 2002), paper IPC2002-27267, pps. ,1889-1893.
G.R. Ruschau and Y.Chen, “Determining The CP Shielding Behavior of Pipeline Coatings in The Laboratory”; CORROSION 2006; Paper 06043
D.P. Moore, "Cathodic Shielding Can Be a Major Problem After a Coating Fails",
Materials Performance 39, 4 (2000): pg. 44
J. A. Beavers & N. G. Thompson, ""Corrosion Beneath Disbonded Pipeline Coatings",
Materials Performance April 1997, pg. 13
R. Norsworthy, “Select Effective Pipeline Coatings”; Hart’s Pipeline Digest, February 1997, pg 17
T. A. Pfaff, “FBE Serves a Broad Market”; Hart’s Pipeline Digest, October 1996, pg. 2
J. Alan Kehr, “Fusion Bonded Epoxy (FBE) – A Foundation for Pipeline Corrosion
Protection”; NACE Press, pg 471 vii Page 55
R. Norsworthy, “Proven Protection”, World Pipelines, October 2007, pg. 49
“Coatings Used in Conjunction with Cathodic Protection”; NACE Technical Committee Report; July 2000; pg. 4
D. Song, F. M. Song, D. W. Kirk, and D. E. Cormack; “Barrier Properties of Two Field Pipeline Coatings”; Materials Performance, April 2005, pg 26