ML20247D985
| ML20247D985 | |
| Person / Time | |
|---|---|
| Site: | Point Beach  |
| Issue date: | 07/20/1989 |
| From: | Fay C WISCONSIN ELECTRIC POWER CO. |
| To: | NRC OFFICE OF INFORMATION RESOURCES MANAGEMENT (IRM) |
| References | |
| CON-NRC-89-085, CON-NRC-89-85, RTR-NUREG-1334 GL-89-08, GL-89-8, IEB-87-001, IEB-87-1, VPNPD-89-399, NUDOCS 8907260027 | |
| Download: ML20247D985 (14) | |
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. WISCONSIN Electnc powca couesivr
< 231 W. MICHIGAN, P.O. BOX 2048, MILV'AUKEE, WI 53201 (414)221 2345 VPNPD-89-399
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July 20,.1989' I
U. S. NUCLEAR REGULATORY COMMISSION
. Document Control Desk Mail Station'Pl-137 Washington, D. C.
20555 Gentlemen:-
DOCKETS 50-266 NND 50-301 RESPONSE TO GENERIC LETTER 89-08 EROSION / CORROSION-INDUCED PIPE WALL THINNING POINT BEACH NUCLEAR PLANT, UNITS 1 AND 2 On May 22, 1989, we received NRC Generic Letter 89-08 dated May 2, 1989, regarding the safe operation of reactors when erosion / corrosion significantly degrades piping and components of high-energy carbon steel piping systems.
The problem is discussed in NUREG-1334, " Erosion / Corrosion-Induced-Pipe Wall Thinning in U. S. Nuclear Power-Plants", which is attached to the Generic Letter.
Generic Letter 89-08 requires that licensees formalize procedures and controls to provide assurances that'a program consisting of systematic measures to ensure that erosion / corrosion does not lead to degradation of single-and two-phase high-energy carbon steel systems has been, or will be,. implemented.
In Generic Letter 89-08, the NRC stipulates that the response r
l will indicate whether or not. licensees have: implemented, or intend to implement, a'long-term erosion / corrosion monitoring program.
Point Beach Nuclear Plant has. implemented such a program, as was explained in the September 10, 1987, response to IE Bulletin 87-01.
A brief description of the program is provided in the attachment to this letter and is organized under the inspection criteria as specified in Section 7.1 of NUREG-1334, which were used to evaluate the on-site inspection of the test plant's erosion / corrosion monitoring programs and
. implementation.
As explained in the attachment, administrative controls which would provide long-term planning and basis documents for the Point Beach Nuclear Plant program are not yet in place.
hool 8907260027 090720 I
PDR ADOCK 05000266
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NRC Document Control Desk July 20, 1989 Page 2 l
Our program meets the intent of the NUMARC guidelines, which provide recommendations for utilities to follow to develop a i
single-phase erosion / corrosion monitoring program and are detailed in NUREG-13A4, Attachment A.
We responded affirmatively to NUMARC on January 13, 1988, saying that we had adopted the guidelines.
It is, therefore, our conclusion that measures we have in place at Point Beach Nuclear Plant, together with those additions and changes mentioned in the attachment, provide assurance that erosion / corrosion will not lead to degradation of single-and two-phase high-energy carbon steel systems.
Formal administrative controls and long-term plans are under development and will be in place by August 30, 1990.
If you have questions or require further information, please contact us.
I Very truly yours,
/l g@. "g C. W. Fay' Vice President Nuclear Power Attachment Copies to NRC Regional Administrator, Region III NRC Resident Inspector Subscribed and sworn to before me this 2: El day of L1 1989.
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Notary Public, State of Wisconsin My Commission expires 5-2c7 9o.
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4 Attachment NUREG-1344 ON-SITE INSPECTION CRITERIA APPLIED TO THE POINT BEACH NUCLEAR PLANT I.
Review of Licensee's Erosion / Corrosion Monitoring Program.
A.
The licensee has developed an erosion / corrosion monitoring program.
As reported in the the response to IE Bulletin 87-01, an erosion / corrosion inspection and maintenance program was initiated during the 1987 spring Unit 1 refueling /
maintenance outage.
The purpose of the inspection program is to detect and quantify significant service related degradation in piping systems and pre-existing conditions that would jeopardize the integrity of these systems in the future.
Representative areas of systems are inspected with ultrasonic and visual techniques to detect such degradation and conditions.
The underlying objective of the inspection program is to look at piping systems whose failure could result in significant hazards to personnel or equipment damage.
Of those systems, areas most susceptible to service re-lated failures are targeted for inspection.
The primary concern is to locate areas of severe erosion / corrosion (E/C) in carbon steel piping, for all water phases, prior to the occurrence of a leak or catastrophic rupture, and make repairs as required.
B.
The licensee's program has a well-defined criteria for:
1) selecting inspection points A qualitative approach is used to assign a degradation susceptibility factor to each component and fitting.
A comparison of the relative magnitudes of this factor is made for a given system or pipe section.
A qualitative decision can then be made as to where the most likely location is for degradation.
As the magnitude of this factor increases so does the likelihood that the location it describes will experience damage.
Thereby, a method exists for screening potential locations for inspection.
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Attachment' Page~2
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Using hoop. stress relationships and the work of
- 17. H. Keller:as reported in EPRI NP-3944, Point j
Beach Nuclear Plant (PBNP) personnel internally i
developed a computer program called the Badness i
Factor Program.
It does not. predict a degradation rate but does offer a qualitative ranking and does evaluate all fluid phases.-'The program generates a value, or Badness Factor (BF), for each component or fitting.
Systems considered for analysis and subsequent inspection are those >1.50" in diameter or i
operating at temperature >140 F.
Systems not satisfying these criteria are not evaluated because their failure would.not have significant consequences.. Those systems included are main steam, heating steam, steam generator blowdown, extraction steam, high-prensure-turbine exhaust steam, steam drains, main feedwater, auxiliary feedwater, feedwater heater and moisture separator reheater vents & drains, and condensate.
Approximately 4000 potential inspection points have
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been identified on each unit.
Hydrodynamic data for each point have been gathered and the BF evaluation performed.
Inspection points with the highest BFs in each system are sorted and tabulated to formulate inspection plans.
Systems showing increased susceptibility to degradation have more points chosen and those with lower susceptibility have fewer chosen. A small sample of inspection points are chosen arbitrarily to provide a control group to check the effectiveness of the BF Program.
Inspection points are also chosen by reviewing equipment history and industry experience.
2) determining inspection frequency If signs of thinning are present but the calculated useful remaining life (App. A) of the component is 1 to 3 years, it is placed back in service for one additional year.
Following this period of service, the component is reinspected and evaluated as before.
Other areas exhibiting thinning but with a useful remaining life of >3 years will be inspected at an interval equal to component life minus 2 years or every 10 years, whichever is less.
Attachment Page 3 1
3) defining the method of inspection i
Once insulation is removed and pipe surfaces cleaned, j
fittings destined for ultrasonic thickness evaluations j
are marked with grids.
Detailed gridding procedures are used to produced repeatable results.
Grid spacing and orientation are dependent on component size and configuration.
Depending on the type of fitting, component, or weld, l
either magnetic particle (MT), dye penetrant (PT),
visual (VT), ultrasonic weld (UTW), or ultrasonic thickness (UT) inspections are performed in accordance with the methods and techniques described in the ASME Boiler and Pressure Vessel Code,Section V.
Components and fittings being monitored for E/C are typically inspected using UT.
In some cases, limited scope VT supplement UT inspections.
Volumetric examinations of 100% of the fitting's grid i
volume are performed for UT inspections using straight beam A-scan techniques.
A 100% grid scan is used, rather than the grid-point technique recommended by NUMARC, to obtain the most accurate, conservative, and repeatable inspection data possible.
Grid-point inspections may not detect the area of minimum thickness because E/C can be a-localized phenomenon.
Welds are also identified for inspection in our program.
UT and either MT or PT techniques are used to perform the inspections.
4) making replacement / repair decisions Unless a detailed engineering evaluation can justify continued operation, pipe wall thinning, as indicated by NDE, is rejectable and must be repaired if wall thickness is less than the minimum allowed by USAS B31.1 - 1967 or if wall thickness, minus annual wear, is less than the minimum allowed by USAS B31.1 -
1967.
Flaws in piping components or welds are rejected and must be repaired if their characterization exceeds that allowed by ASME Sec. XI
- 1977 IWB-3000, unless the flaw is proved acceptable using other analytical techniques.
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Attachment Page 4 C.
The licensee's program meets the intent of NUMARC
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guidelines.
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As stated in our January 13, 1988, response to a NUMARC i
questionnaire, our program meets the intent of NUMARC j
guidelines.
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D.
The licensce's program includes:
i 1) high-energy single phase lines, including long-term inspection 1
2) two phase lines, including guidelines and computer codes 3) large moderate energy single phase piping systems.
As explained above, systems considered for analysis and subsequent inspection are those >1.5" in diameter or operating at temperatures >140 F.
Those systems in-cluded in the program are main steam, heating steam, steam generator blowdown, extraction steam, high-pressure turbine exhaust steam, steam drains, main feedwater, auxiliary feedwater, feedwater heater and moisture separator reheater vents & drains, and condensate.
Computer aided BF calculations are performed on each component or fitting, then sorted and tabulated to formulate inspection plans.
Detailed procedures are used to grid the fitting and NDE inspections are performed in accordance with the methods and technicues described in the ASME Sec. V Boiler And Pressure Vessel Code.
A long term plan is under development.
It will use about 10% of the potential inspection points to establish a base and will be modeled after the ASME Sec. XI primary system in-service inspection long-term plan, possibly using a 10-year inspection cycle.
E.
The licensee has established a plant specific history of pipe wall thinning, including failure analysis and damage mechanism.
Erosion has been a concern at PBNP for nearly 17 years.
Through careful and responsible maintenance efforts, no eroded pipe or com.ponent has resulted in a catastrophic failure.
However, minor through-wall leaks have occurred
Attachment Page 5 over the operating histories of both units.
The first reported case was in 1973, 3 years after initial operation.
Wet steam had eroded through a 0.437" thick carbon steel high-pressure turbine line.
This and several other failures in the industry prompted an extensive inspection program in 1982.
Ultrasonic thickness inspections were performed on all extraction steam lines.
The results indicated extensive thinning at tees and elbows.
Ultimately
-this led to the replacement.of the carbon steel j
extraction lines with ASTM-A-312 Type 304 stainless steel in 1984.
Since this material is resistant to E/C, extraction line wear was essentially eliminated.
1 Erosion of high-pressure turbine exhaust lines (crossunder piping) was also a problem.
Protection of this piping has been accomplished by annual internal visual inspections supplemented with internal ultrasonic thickness inspections and weld
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clad repairs.
Since E/C of these lines is severe, moisture removal equipment was installed in 1987 to raise steam quality in these lines and reduce the E/C damege.
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i With the feed lines rupture of Unit 2 at Surry in 1
December 1986, PBNP furthered its efforts to identify j
and repair areas of E/C in single-phase and two-phase i
systems.
The first single-phase inspections took l
place during the 1987 spring refueling / maintenance outage on Unit 1, and have continued every outage j
since.
We have compiled baseline single-phase and j
two-phase data for 359 components (Units 1 & 2 j
combined) with data for 95 follow-up examinations.
l These data are used to calculate component wear rate i
and predict useful remai. ting life (App. A).
Analyses l
are presently performed by hand.
However, an expert l
system is being developed to computerize the process.
More sophisticated numerical analyses will then be i
possible.
1 Failure analyses and evaluation of damage mechanisms have not been formally documented for the few cases of actual E/C that have been found at PBNP.
- Instead, characteristic indications were recognized by i
engineering personnel and appropriate corrective j
actions taken.
For example, E/C found in the steam i
trap drein system was resolved by substituting stainless steel for carbon steel, and damaged 1
8 Attachment Page 6 high-pressure turbine exhaust lines (crossunder lines) are repaired annually by weld cladding on the inside surface.
Failure analysis requirements will be considered for incorporation into the long term plan during its development.
F.
The licensee has a well-developed training program and personnel conducting NDE examinations have been properly certified.
Nondestructive examination techniques require knowledgeable personnel to perform the examinations and interpret the results.
To assure satisfactory perfor-mance and evaluation of NDE examinations, personnel are trained and qualified in accordance with the following documents, as required by company procedures:
" Personnel Qualification and Certification in Nondestructive Testing," American Society for Nondestructive Testing (ASNT).
Recommended f-practice No. SNT-TC-1A 1975 and 1980 Editions.
" Rules for Inservice Inspection of Nuclear Power Plant Components," American Society of Mechanical Engineers (ASME), Boiler and Pressure Vessel Code, Sec. XI, 1977 Edition with Addenda through summer 1979.
" Qualification of Inspection, Examination and Testing Personnel for Nuclear Power Plants,"
American National Standards Institute (ANSI),
N45.2.6 - 1973 Edition.
Before examinations are performed company procedures d
require the following personnel certification documentation:
-Current Wisconsin Electric Power Co.
certifications showing proper approval signatures
-Current eye examinations
-Current examinations showing achieved grades in General, Specific & Practical exams. (Level III's shall include Basic, Method, Specific & Practical exams.)
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Attachment I
Page 7 i
II.
Review of Licensee's Implementation of Erosion / Corrosion J
Monitoring Progrem.
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A.
Inspection procedures and guidelines 1) are properly reviewed and approved before their implementation.
Special processes, such as nondestructive examination must be well defined by procedure and adequately controlled to assure acceptable results.
Methods for the preparation of new procedures, and for making revisions to existing place to achieve this objective. procedures are in Review, approval, and implementation of procedures is controlled by our quality assurance program.
2) cover periodic monitoring of high-energy safety-related and non-safety-related carbon steel.
Nondestructive examination procedures are detailed and specific.
Development of individual procedures is guided by such documents as:
" Nondestructive Examination," ASME, Boiler and Pressure Vessel Code,Section V, Article 5, 19f/ edition with addenda through summer 1979.
-Wisconsin Electric Power Company's
" Nondestructive Examination Procedures Manual."
" Rules for Inservice Inspection of Nuclear Power Plant Components," American Society of Mechanical Engineers (ASME), Boiler and Pressure Vessel Code, Sec. XI, 1977 Edition with Addenda through summer 1979.
Procedures apply to both safety-related and non-safety-rei.ated systems.
Systems considered for analysis and inspection are >1.5" in diameter or are operating at temperatures >140 F and include such high-energy systems as main steam and main feedwater.
Monitoring periodicity will be stipulated by the long term plan which is under
9 Attachment Page 8 development.
It will use about 10% of the potential inspection points to establish a base and will be modeled after the ASME Sec. XI primary system in-service inspection long-term plan, possibly using a 10-year inspection cycle.
3) provide for qualification or certification of l
personnel and equipment For thickness examinations using an ultrasonic scope, responsible personnel are required to be certified in ultrasonics as a Level I, II, or III in accordance with the following documents as required by company procedures:
" Personnel Qualification and Certification in Nondestructive Testing," American Society for Nondestructive Testing (ASNT). Recommended practice No. SNT-TC-1A 1975 and 1980 Editions.
" Rules for Inservice Inspection of Nuclear Power Plant Components," American Society of Mechanical Engineers (ASME), Boiler and Pressure Vessel Code, Sec. XI, 1977 Edition with Addenda thrcugh summer 1979.
Instrument calibration must be checked periodically to ensure that the ultrasonic system is not changing.
Calibration exceeds the requirements of ASME Sec. V, Art. 5, Standard SE-113.
4) are consistent with commitments Responses to NRC reviews of post-Surry bulletins and information notices contained no specific commitments.
However, PBNP's response to INPO SOER 87-03 stated that we would develop a plan for continuing periodic in-service inspections of secondary piping systems, which would contain all the features described in the recommendations of the SOER.
PBNP personnel are also committed to the development of secondary in-service inspection procedures to detect and quantify significant service-related degradation aun pre-existing conditions in piping systems that could jeopardize the integrity of those systems in the future.
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-The underlying objective of the program is to look at piping components whose failure could result in significant personnel or equipment damage.
The primary concern is to locate areas of severe E/C in high-energy carbon steel piping prior to the occur-rence of a leak or catastrophic rupture.
In addition, certain welds are examined to locate areas of significant fatigue damage demonstrated by service related flaw extension or crack growth.
Management and staff at PBNP are confident that this program satisfies NRC requirements and meets the recommendations of the NUMARC working group on E/C.
They are also convinced that the program is performing its designed function and is protecting plant equipment and personnel from a catastrophic pipe rupture.
B.
The equipment used to perform NDE has been calibrated against known standards for types of metals and range
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of thickness to be measured.
As' required by ASME Section V, Article 5, calibration standard material and the specimen material shall be i
acoustically similar.
In addition, the examination sides of the standard shall be parallel and the thickness of the standard shall be known to f0.001".
C.
Pipe wall thickness is being measured in accordance with established instructions and results are being appropriately documented.
Pipe wall thickness measurements are made using written, approved procedures which detail personnel and equipment requirements, specify calibration techniques and proceduralize the examination.
Required documentation meets and exceeds the requirements of ASME Section V, Article 5 and includes component identification number, procedure & revision, examiner, SNT level., date, couplant & batch, surface condition, calibration block number, calibration data, instrument parameters &
settings, transducer parameters, limitations, thickness readings in hundreths of an inch, inclusions, examiner signature and review signature.
Attachment Page 10 D.
Qualified personnel are evaluating pipe wall measurements to determine the need for corrective action and the frequency of continued periodic monitoring.
Indication disposition reporte (IDRs) are initiated by inspectors when significant thinning or indications are found.
An IDR trigger value is set at half the measured distance between the ASTM standard for manufacturing tolerance (87.5% of nominal) and the minimum code allowable wall thickness.
The program engineer then evaluates the IDR to determine the need for corrective action by calculating useful remaining life (App. A).
If signs of thinning are evident but the useful remaining life of the component is 1 to 3 years, it is placed back in service for one additional year.
Following this period of service, the component will be reinspected and evaluated as before.
Other areas exhibiting thinning but with a useful remaining life of
>3 years will be inspected at an interval equal to component life minus 2 years or every 10 years, whichever is less.
E.
A schedule has been established to repair and continually monitor piping that has shown evidence of wall thinning.
Useful remaining life calculations (App. A) are performed for each thickness examination.
Pipe wall thinning is rejected and repaired if wall thickness is less than the minimum allcwed by USAS B31.1 or if wall thickness, minus annual wear, is less than the minimum allowed by USAS B31.1.
If signs of thinning are evident but the useful remaining life of the component is 1 to 3 years, it is placed back in service for one additional year.
Following this period of service, the component will be reinspected and evaluated as before. Other areas exhibiting thinning but with a useful remaining life of
>3 years will be inspected at an interval equal to component life minus 2 years or every 10 years, whichever is less.
F.
Administrative controls are in place and management support is evident.
Administrative controls are under development but not yet in place.
It is anticipated that they will consist of a long term plan and administrative procedures.
The l
long term plan will define the inspection program
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Attachment.
1 Page 11-objectives & philosophy, reference commitments, stipulate' personnel, equipment & procedural requirements, provide in-depth program detail including project scope, l
point ' selection, ::BF calculation, analysis requirements, l
acceptance-standards, and inspection frequency.
It will be modeled after;the ASME Sec. XI primary system ISI long term plan.
Administrative-procedures will be developed to implement and maintain the long term plan.
Plant and corporate management support of the secondary ISI program is evidenced by their commitments in response to INPO SOER 87-3 and by reviewing expenditures and budgets.
PBNP's response to SOER 87-3 stated that we would develop a plan for continuing periodic in-service.
3 inspections of secondary piping systems, which would 1
contain all of the features described in the i
recommendations of the SOER.
Program expenditures for 1987 were $712,000; 1988 expendit;res were $588,000; 1989 expenditures have been
$252,000 with another $169,000 budgeted; 1990 budgets include $357,000.
These facts demonstrate management support for the program.
G.
The licensee's' commitments in response to NRC Bulletin 87-01 are being met.
PBNP's response to NRC Bulletin 87-01 went into' great detail on the scope and extent of the secondary ISI program for ensuring that pipe wall thicknesses are not reduced below the minimum allowable thickness.
Included-were exam point selection, philosophy, systems considered, points of inspection, measurement frequency, examination
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techniques, and acceptance criteria.
The BF calculation was discussed with reference to the associated factors and results of to-date inspections were provided.
Refinements and revisions to the program were anticipated in the response to Bulletin 87-01 but no specific commitments were made.
It was simply understood that a program was needed to control this newly discovered phenomenon and steps were being taken to put it in place.
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Attachment Page 12 Appendix.A
- CALCULATED USEFUL-REMAINING LIFE'(L)
T
~T meas
- min g_
Rwear where:.
P X OD
( SAS B31.1)
T min 2(SE.+ Py) f i
T
-T R
nom meas wear -
Pwear T" " = larger of manufacturer's nominal or average thickness P
= wear period, 5 years.for baseline wear The calculated life (L) is simply the difference between availablewallthickness(T@'05a)rrage(R and allowable wall thickness (T{n)hickness-iscalculatedas8ffe)c.
, divided b The y
allowable wag t
ted by USAS-B31.1.
Wear rate is taken'as the difference between nominal wall. thickness (Tnom).and available wall thickness,
' divided by wear period (P The value used for nominal wallthicknessisthelard$f#o)fthemanufacturer'snominal thickness and average thickness.
For baseline inspections, a wear period of 5 years is used, even though the units have operated much longer, to compensate for uncertainties in the E/C mechanism.
True wear period values are used for follow-up inspection.
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