Api agenda item 653-144 External and Ultrasonic Thickness Measurement Inspection Schedule Revisions

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Agenda Item 653-144 4/14/03 Page of


External and Ultrasonic Thickness Measurement Inspection Schedule Revisions
HANDLED BY: Steve Braune

AEC Engineering

5540 Falmouth Street, Suite 300

Richmond, VA 23230

Phone: (804) 282-3811, Fax: (804) 282-3652

Email: slbraune@aec-va.com

PURPOSE: To revise External & UTM Inspection Interval Schedules
ORIGIN: For External Interval…Philips Petroleum Letter of 9/14/00
For UTM Interval… Phil Myers' previous comments

STATUS: Originated September 24, 2001

Fall 2001, MS&P to SCLB, but not balloted

Updated April 2002 for API-653 Third Edition

Spring 2002, MS&P to SCLB

Fall 2002, held on agenda, Braune absent from meeting

Spring 2003, revised per ballot, MS&P for re-SCLB
BUSINESS IMPACT: Tank inspection costs will be reduced.

Current rules require an excessive number of visual external inspections by an AI as an AST approach the end of its service life. The proposed changes for lengthening the external inspection intervals are based on the current or similar wording used in API-510 for pressure vessels which provides relaxed rules for vessels with less than four years of remaining service life.
The Standard already requires routine in-service inspections on a monthly basis. No changes are proposed for this type of inspection.
Current rules limit the ultrasonic thickness inspection schedule to a maximum of 15 years. In a previous discussions of this item, Phil Myers proposed that this be extended to a 20 year maximum. This would bring the internal and UTM inspection intervals in line with each other. Phil’s recommendation was initially handled as a Agenda Item 653-155, but was subsequently dropped and merged into this item.
Since most tanks that store refined petroleum products do not exhibit high internal shell corrosion rates, the remaining service life is often quite long. Therefore, when inspection schedules are based upon these low corrosion rates, it is technically correct to extend the time between shell thickness measurements. Conversely, there is no technical justification not to use longer UTM inspection intervals for these tanks.
By contrast, there are tanks in non-petroleum service that exhibit very high corrosion rates and non-uniform corrosion patterns. These tanks should not be candidates for an extended UTM inspection interval. In fact, we should seriously consider shortening the maximum inspection interval for such conditions; however, this is a matter possibly beyond the scope of this item. This issue could be addressed within this agenda item if the SGD so agrees. At this point, I recommend that we include a general cautionary note in the Standard about such cases.
In order to qualify for an extension to twenty years, the previously ballotted proposal required that several important points be addressed as noted below. These items were subsequently dropped as several balloters felt that were too complicated and restrictive. These items are included herein for historical reference only; however, they are woven into the fabric of this item is subtle ways.

  • The shell corrosion rates for the tank must have been calculated from actual thickness readings over a period of operation of at least ten years. At least two sets of UTM readings are required.

  • The corrosion rate should be low. A maximum corrosion rate of five mils per year is proposed. Since most refined petroleum product tanks do not exhibit shell corrosion rates above 1 or 2 mils per year, the selection of 5 mils per year seems appropriate. In addition, this limit is also consistent with API-510.

  • The general thickness loss due to corrosion must not exceed ten percent of the original nominal thickness.

The schedule for the UTM inspection interval is currently based upon one-half of the remaining service life of the shell. No changes are proposed for this criteria.
The results of the Spring 2002 SCLB are addressed below.
Bob Elliott’s Negative Comment:

1. As you know, there is a lot of confusion with inspectors on how to handle the ½ life when it is short (less than 5 years). While your last couple sentences in improve on what we had, I believe there will continue to be confusion. I think part of the problem is that says you can’t go beyond the ½-life – so if my life is 6 years, do I inspect at 3 year and then at 1. Years, etc. In, could you say something like, “except as extended by above” for the maximum life, or something like that?

Hopefully, this ballot will flush out some better word-smithing than I can offer.

Braune Response… I agree with Bob that the words are difficult; however, they are essentially same words that are in API-510. Difficult as they may be, I have been unable to craft them any better than what is now in API-510. I have reorganized the material slightly as a means to make it more understandable (I hope).

Bob Elliott’s Positive Comments:

1. Regarding your technical justification words about petroleum tanks and shell rates. I have found accelerated and non-uniform corrosion rates on the shells of resid tanks.

Braune Response… I agree with Bob on this, but my intent was only to make a general statement about petroleum ASTs vs. those in other industries. I have tried to clarify my broad statement into one about refined petroleum ASTs only.

2. Typo: Your should be

Braune Response… Agreed

3. (2nd bullet): I know the 5 MPY is the standard steel corrosion rate but how about 7 mils per year, to allow for variances in the process?

Braune Response… The 5 mpy limit was lifted directly from API-510 as a means to use a generally accepted rate as a break point between higher and lower corrosion rates. In light of other balloter’s comments, I have dropped this as a requirement for the 20 year interval.

4. I’d delete the last part of, the part beginning: “if the internal…” Isn’t it obvious that all the external inspection requirements would apply but you can just do it from the inside?

Braune Response… Agreed. Although the scope of this item did not deal with, Bob’s comment was accepted. Paragraph will be dropped and will be revised to indicate that the UTM inspection may be conducted from either inside or outside of the tank.
Larry Foster’s Negative Comment:
I support the concept of extending the UT inspection to 20 years, but this proposal puts too many restrictions on getting there. Just change b from 15 to 20 years. Aggressive corrosion rates will dictate shorter intervals if necessary.
Braune Response… Agreed.

Bruce Roberts’ Negative Comment:

I have two issues that need to be addressed in this item.

1)    External pitting, particularly pitting under insulation, must be properly inspected by removing the insulation especially on the bottom shell course, before allowing internal inspection to replace external inspection. I have seen tanks in low-temp service for just 5 years with numerous pits half way through a 1.75 inch Q&T bottom shell course. Internal inspection with or without UT would not have picked this up.

2)    Tanks in warm service (about 150ºF to 212ºF) rapidly corrode externally under insulation, especially in areas under all penetrations through the insulation, such as nozzles and clips. I’ve seen this on Exxon tanks in Baton Rouge. This item should not allow any extensions or alternates for this type of service, unless it is specifically addressed in the item.

External corrosion must not be treated lightly in 653.
Braune’s Response… I agree with all that Bruce has to say about corrosion under the insulation. I think that this important issue is beyond the scope of this item; however, I have included some additional material in as a means to highlight the problem. API-575 may be a more appropriate place for a more expansive treatment.
Mr. Shallis’s Negative Comments:

Unsure of where the original requirement for the ¼ corrosion rate requirement came from.

Braune Response… This was a basic requirement of the original TG that drafted API-653. Currently, the external inspection schedule is based upon ¼ the remaining service life, with a maximum of five years.

The assumption that most tanks in petroleum service have a low corrosion rate may need some additional consideration. Corrosion on these tanks in many cases can be increased based upon the process. For example, on tanks where the product is warm when the tank is being filled causes condensation and that can create vapor zone corrosion. If the tank is filled from a tanker ship, in most cases there are traces of salt water, which causes accelerated corrosion at the bottom of the tank in the area of highest stress.

Braune Response… I believe that these issues are generally understood and hopefully API-575 sheds some light on the subject. It was not the intent of this agenda item to discuss the valid issues highlighted by Mr. Shallis; however, additional wording has been added to highlight the issues.

The justification included a statement that most petroleum service tanks have low corrosion rate and tanks in non-petroleum service may be considered for an increase of inspections. There is no place in the proposed change that differentiates petroleum from non-petroleum service tanks.

Braune Response… Mr. Shallis correctly points out that the comments in the technical justification section are not explicitly reflected in the proposed revisions as differing between petroleum and non petroleum services. My comments in the technical justification section were include as background only.

If the change is approved, it should define and specify which petroleum products this would apply and it should also give consideration for the different process.

Braune Response… Since the Standard does not generally give tutorial info and background information (API-575 is the right spot for such issues), I am unable to incorporate his comments. The issue of corrosion rate and remaining service life calculations adequately address his comments to the extent possible in API-653.
Randy Kissell’s Affirmative Comments:

Shouldn’t be

Braune Response… Agreed

I suggest we not state units for RCA and N. Any consistent set of units could be used: e.g., if RCA is in mm, and N is in mm/yr, then RCA/N is in yr. Defining the variables without units makes metrication easier and is more general.

Braune Response… Agreed. The remaining service life of the tank has been added in Section 3 – Definitions in a non-dimensional format. The corresponding material has been sliced out of Section 6 – Inspections.

John Lieb’s Affirmative Comment:
I already submitted my ballot form for the other items and do not want to confuse matters by sending another ballot to include this item.  I am voting YES on this item.  My only affirmative comment is that perhaps the "must" in the third line of should be "shall".
Braune Response… Agreed

Doug Miller’s Affirmative Comments:

1) “” should be “” (in two locations)

Braune Response… Agreed

2) Proposed new wording for the third bulleted item is, “The general thickness loss due to corrosion must not exceed ten percent of the original nominal thickness.” It is not clear whether this is ten percent during this inspection interval or an accumulated corrosion at the end of the inspection period.

Braune Response… Agreed, but wording will be dropped and the concept incorporated elsewhere in this revision.
Rick Nichols Affirmative Comment:
Why not simply change the 15 years in (b) to 20 years instead of adding complicated exemptions?

Braune Response… Agreed
Marilyn Shore’s Affirmative Comment:
I believe I was off the committee during the time this document was metricated. The 10.2 used to be pounds per square foot. I question whether lbf/ft2 is the proper representation.
Braune Response… I believe that this comment was placed here incorrectly in the process of preparing the ballot summary.

Proposed Addition of Definitions
(NEW) 3.15 remaining corrosion allowance: the excess shell plate thickness, which is the difference between the measured shell thickness and the minimum required thickness.

(NEW) 3.16 remaining service life: the remaining corrosion allowance of the tank shell divided by the corrosion rate.
Editorial Note… renumber existing 3.15 and following as required.

Proposed Revisions to 6.3.2
6.3.2 External Inspection All tanks shall be given a visual external inspection by an authorized inspector. This inspection shall be called the external inspection and must be conducted at least every 5 years or RCA/4N years (where RCA is the difference between the measured shell thickness and the minimum required thickness in mils, and N is the shell corrosion rate in mils per year) whichever is less. Tanks may be in operation during this inspection. All tanks shall be given a visual external inspection by an authorized inspector on an interval not to exceed that shown below. Tanks may be in operation during this inspection.

  1. This external inspection shall be conducted at the lesser of five years or one-half the remaining service life of the tank shell.

  1. In cases where the remaining service life is determined to be four years or less, the external inspection interval may be the full remaining service life up to a maximum of two years. (SEE NOTE BELOW)

NOTE… Consider the following examples of application of (a) and (b). This note is for balloter’s information only and is not part of the proposed revisions

If remaining service life is 10 years… inspect in 5 years

If remaining service life is 8 years… inspect in 4 years

If remaining service life is 6 years… inspect in 3 years

If remaining service life is 4 years… inspect in 2 years

If remaining service life is 3 years… inspect in 2 years

If remaining service life is 2 years… inspect in 2 years

If remaining service life is 1 year… inspect in 1 year

If remaining service life is 1/2 year… inspect in 1/2 year

Proposed Revisions to 6.3.3



6.3.3 Ultrasonic Thickness Inspection External Ultrasonic thickness measurements of the shell can be used as a means of determining a rate of uniform general corrosion while the tank is in service, and can provide an indication of the integrity of the shell. The shell thickness measurements may be made from either the shell exterior or interior surfaces. The extent of such measurements shall be determined by the owner/operator (This deleted sentence moved to a revised When used, the ultrasonic thickness measurements shall be made at intervals not to exceed the following:

  1. When the corrosion rate is not known, the maximum interval shall be five years. Corrosion rates may be estimated from tanks in similar service based on thickness measurements taken at an interval not exceeding five years.

  2. When the corrosion rate is known, the maximum interval shall be the smaller of RCA/2N years (where RCA is the remaining corrosion allowance in mils and N is the shell corrosion rate in mils per year) or 15 years. When the corrosion rate is known, the maximum interval shall be the lesser of twenty years or one-half the remaining service life of the tank shell. The corrosion rates shall be based on thickness measurements taken for a service interval of at least five years. Alternatively, the corrosion rate may also be estimated from tanks in similar service.

  3. The above noted interval limits may not be appropriate for tanks that experience high corrosion rates (e.g. five mils per year or more) or non-uniform corrosion patterns. In such instances, the interval for inspection shall be adjusted as deemed necessary by the storage tank engineer. see next page Internal inspection of the tank shell, when the tank is out of service, can be substituted for a program of external ultrasonic thickness measurement if the internal inspection interval is equal to or less than the interval required in b or c. (NOTE… this material was moved into above)

A new is added that expands on finding areas of shell corrosion… The extent of ultrasonic thickness measurements shall be determined by the owner/operator. The owner/operator shall assure that thickness readings are made in critical locations in sufficient quantity to adequately establish the condition of the shell. Considerations shall be made for detecting the following possible corrosion problems, on either internal or external surfaces of the shell. Such provisions shall be included in the owner/operator’s inspection specification or guidelines. Below is a partial listing of such conditions.

  • corrosion at the base of the shell

  • corrosion of the shell behind insulation

  • corrosion of the appurtenances and attachments at insulation openings

  • erosion / corrosion due to agitators, inlets, flow obstructions etc.

  • corrosion in the vapor space

  • corrosion at the liquid-vapor interface

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