ML20112C219
| ML20112C219 | |
| Person / Time | |
|---|---|
| Site: | Crane  |
| Issue date: | 12/21/1984 |
| From: | Office of Nuclear Reactor Regulation |
| To: | NRC OFFICE OF THE SECRETARY (SECY) |
| Shared Package | |
| ML20112C223 | List: |
| References | |
| 841228-01, 841228-1, NUDOCS 8501110089 | |
| Download: ML20112C219 (4) | |
Text
F
.,.e p *? "4 UNITED STATES t
g%,
NUCLEAR REbULATORY COMMISSION
,f a
WASHING 10'., D.C. 20666 DISTRIBEION:
5 l
December 28, 1984
'DocketEliP S
of
. ?? Rdg RIngram DOCKET No.
50-289 MEMORANDUM FOR:
Docketing and Service Branch Office of the Secretary of the Commission FROM:
Office of Nuclear Reactor Regulation
SUBJECT:
TilREE MILE ISLAND NUCLEAR STATION, UNIT 1 One signed original of the FederalRegister Notice identified below is enclosed for your transmittal to the Office of the Federal Register for publication. Additional conformed copies ( G
) of tiie Notide are enclosed for your use.
C Notice of Receipt of Application for Construction Permit (s) and Operating License (s).
Notice of Receipt of Partial Application for Construction Permit (s) and Facility License (s): Time for Submission of Views on Antitrust Matters, h Notice of Consideration of Issuance of Amendment to Facility Operating License.
Notice of Receipt of Application for Facility License (s); Notice of Availability of Applicant's Environmental Report;and Notice of Consideration of Issuance of Facility License (s) and Notice of Opportunity for Hearing.
U Notice of Availability of NRC Draft / Final Environmental Statement.
Notice of Limited Work Authorization.
C Notice of Availability of Safety Evaluation Report.
Notice of issuance of Construction Permit (s),
h Notice of issuance of Facility Operating License (s) or Amendment (s).
O Order.
Exemption.
Notice of Granting of Relief.
O Other:
Division of Licensing, ORBf4 Office of Nuclear Reactor Regulation 8501110089 841221 PDR ADOCK 05000289
Enclosure:
As stated PDR om n > 0RB64,:D -
" " = >..RIn9G dCf om >.1. 2../3.) /.0. 4....
s GPU Nuclear Corporation 50-289, TMI-l Mr. R. J. Toole Jordan D. Cunningham, Esq.
O&M Director, Till-1 Fox, Farr and Cunningham GPU Nuclear Corporation 2320 North 2nd Stre::t P. O. Box 480 Harrisburg, Pennsylvania 17110 Middletown, Pennsylvania 17057 Ms. Louise Bradford tilia Board of Directors 1011 Green Street P.A.N.E.
Harrisburg, Pennsylvania 17102 P. O. Box 268 Middletown, Pennsylvania 17057 ft. Marjorie M. Aamodt R. D. #5 Coatesville, Pennsylvania 19320 Docketing and Service Section Earl B. Hoffman U. S. Nuclear Regulatory Comission Dauphin County Comissioner Washington, D. C.
20555 Dauphin County Courthouse Fmnt and Market Streets Chauncey Kepford Harrisburg, Pennsylvania 17101 Judith H. Johnsrud Envimnmental Coalition on Nuclear Power Ellyn R. Weiss 433 Orlando Avenue Harmon, Weiss & Jordan State College, Pennsylvania 16801 2001 S Street Suite 430 Judge Reginald L. Gotchy Washington, D.C.
20009 Atomic Safety & Licensing Appeal Board U.S. Nuclear Regulatory Commission Washington, DC 20555 Ivan H. Smith, Esq., Chairman Atomic Safety and Licensing Board U.S. Nuclear Regulatcry Comission Mr. Thomas,. E. !'urley, Regional Administrator Washington, D.C.
20555 U. S. fl. R. C., Region I G31 Park Avenue King of Prussia, Pennsylvania 19406 c.ary J. Edles, Chairman Atomic Safety & Licensing Appeal Board ANGRY /TMI PIRC U.S. Nuclear Regulatory Commission 1037 Maclay Street Washington, DC 20555 Harrisburg, Pennsylvania 17103 I
John Levin, Esq.
Fennsylvania Public Utilities Comission Box 3265 Harrisburg, Pennsylvania 17120
7
,GPU Nuclear Corporation Gen:ral Crunsel Federal Em:rgency Managem:nt Agency Mr. Thomas M. Gerusky, Director ATTN: Docket Clerk Bureau of Radiation Protection 1725 I Street, NW Pennsylvania Department of Washington, DC 20472 Environmental Resources Karin W. Carter, Esq.
5 Har is rg ennsylvania 17120 0
7 Harrisburg, Pennsylvania 17120 liarvin I. Lewis
-6504 Gradford Terrace Dr. James Lamb Philadelphia, Pennsylvania 19149 313 Woodhaven Road Chapel Hill., North Carolina 27514 G. F. Trowbridge, Esq.
Dauphin County Office Emergency Shaw, Pittman, Potts & Trowbridge Preparedness 1800 M Street, N.W.
Court House, Room 7 -
Washington, D. C.
20036 Front & Market Streets Harrisburg, Pennsylvania 17101 Richard J. McGoey Manager, PWR Licensing Christine'N.' Kohl, Esq.
GPU Nuclear Corporation Atomic. Safety & Licensing Appeal 100 Interpace Parkway Board Parsippany, New Jersey 07054 U.S. Nuclear Regulatory Comission Washington, D.C.
20555
- k. Virginia Southard, Chairman Mr. Robert B. Borsum Citizens for a Safe Environment Babcock & Wilcox 264 Walton Street Nuclear Power Generation Division Lemoyne, Pennsylvania 17043 Suite 220', 7910 Woodmont Avenue Bethesda, Maryland 20814 Dr. David Hetrick Professor of Nuclear Energy Mr. Gustave A. Linenberger, Jr.
l University of Arizona Atomic Safety and Licensing Board i
Tucson, Arizona 85721 U.S. Nuclear Regulatory Comission Washington, D.C.
20555 Mr. David D. Maxwell, Chairman Board of Supervisors Londonderry Township RFD#1 - Geyers Church R<dd Middletown, Pennsylvania 17057 Mr. C. W. Smyth THI-l Licensing Manager GPU Nuclear Corporation Regional Radiation Representative P. O. Box 480 EPA Reaion III Middletown, Pennsylvania 17057 Curtis Building (Sixth Floor) l 6th and Walnut Streets Philadelphia, Pennsylvania 19106 Mr. Richard Conte Governor's Office of State Planning Senior Resident Inspector (TMI-1) and Development U.S.N.R.C.
ATTN: Coordinator, Pennsylvania P. O. Box 311 State Clearinghouse Middletown, Pennsylvania 17057 P. O. Box 1323 Harrisburg, Pennsylvania 17120
v.
u.
GPU Nuclear Corporation..
Sheldon J. Wolfe, Esq., Chairman Atomic Safety & Licensing Board Washington, D.C. 20555 th. Jane Perkins City Government Center 10 North !!arket Square Harrisburg, Pennsylvania 17101 Jane Lee 183 Valley Road Etters, Pennsylvania 17319 Bruce Molholt Haverford College Haverford, Pennsylvania 19041 Norman Aamodt R. D. f5, Box 428 Coatesville, Pennsylvania 19320 Michael McBride, Esq.
LeBoeuf Lamb, Leiby & ficRae Suite 1100 1333 New Hampshire Avenue, N.W.
Washington, D.C.
20036
a n,
'o,,
UNITED $TATES NUCLEAR REGULATORY COMMISSION n
WASHINGTON, D. C. 20555
- s.,...../
METROPOLITAN EDISON COMPANY JER3EY CENTRAL POWER AND LIGHT COMPANY PENNSYLVANIA ELECTRIC COMPANY GPU NUCLEAR CORPORATION DOCKET NO. 50-289 THREE MILE-ISLAND NUCLEAR STATION, UNIT NO. 1 AMENDMENT TO FACILITY OPERATING LICENSE Amendment No. 103 License No. DPR-50 1.
The Nuclear Regulatory Commission (the Comission) has found that:
~
A. The application for amendment by GPU Nuclear Corporation, et al (the licensees) dated May 9,1983, complies with the standards and requirements of the Atomic Energy Act of 1954, as amended (the Act) and the Commission's rules and regulations set forth in 10 CFR Chapter I; B. The facility will operate in conformity with the application, the provisions of the Act, and the rules and regulations of the Comission; C. There is reasonable assurance (i) that the activities authorized by this amendment can be conducted without endangering the health and safety of the public, and (ii) that such activities will be conducted in compliance with the Comission's regulations; D. The issuance of this amendment will not be inimical to the comon defense and security or to the health and safety of the public; and E. The issuance of this amendment is'in accordance with 10 CFR Part 51 of the Comission's regulations and all applicable requirements have been satisfied.
DR-pg P
2.
Accordingly, Facility Operating License No. DPR-50 is hereby amended as indicated below and by changes to the Technical Specifications as indicated in the attachment to this license amendment.
A. Revise paragraph 2.c.(2) to read as follows:
Technical Specifications 4
The Technical Specifications contained in Appendix A, as revised through Amendment No.103, are hereby incorporated in the license. The GPU Nuclear Corporation shall operate the facility in accordance with the Technical Specifications.
B. Revise paragraph 2.c.(8) to read as follows:
Repaired Steam Generators In order to confirm the leak-tight integrity of the Reactor Coolant System, including the steam generators, operation of the facility j
shall be in accordance with the following:
- 1. Prior to initial criticality, GPU Nuclear Corporation shall submit to NRC the results of the steam generator hot test program and a summary of its management reviiw.
- 2. GPU Nuclear Corporation shall confirm the baseline primary-to-secondary leakage rate established during the steam generator hot test program.
If leakage exceeds the baseline leakage rate by more than 0.1 GPM, the facility shall be shut down and leak tested.
If any increased leakage above baseline is due to defects in the tube free span, the leaking tube (s) shall be removed from service. The baseline leakage shall be reestablished, provided that the leakage limit of Technical Specification 3.1.6.3 is not exceeded.
- 3. GPU Nuclear Corporation shall complete its post-critical test program at each power range (0-5%, 5%-50%, 50%-100%) in conformance with the program described iri Topical Report 008, Rev. 3, and shall have -
available the results of that test program and a summary of its management review, prior to ascension from each power range and prior l
to normal power operation.
- 4. GPU Nuclear Corporation shall conduct eddy-current examinations, consistent with the extended inservice inspection plan defined in Table 3.3-1 of NUREG-1019, either 90 calendar days after reaching full power, or 120 calendar days after exceeding 50% power operation, whichever comes first.
In the event of plant operation for an extended period at less than 50% power, GPU Nuclear Corporation shall provide an assessment at the end of 180 days of operation at power levels between 5% and 50%, such assessment to contain recommendations and supporting information as to the necessity of a special eddy-current testing (ECT) shutdown before the end of the refueling cycle.. (The NRC staff will evaluate that assessment and. determine the time of the next eddy-current examination, consistent with the other provisions of the license conditions.)
In the absence of such an.
assessment, a special ECT shutdown shall take place before an additional 30 days of operation at power above 5%.
l L
=
i
- ~ **
l
- 5. GPU Nuclear Corporation shall provide routine reporting of the long-term corrosion " lead tests" test results on a quarterly basis as well as more timely notification if adverse corrosion test results are discovered.
3.
This license amendment is afiective as of the date of its issuance.
R THE NUCLEAR REGUL TORY COMMISSION 6
o l
Johi F. Stolz,' Chief 0 rating Reactors Bra h #4 ivision of Licensing
Attachment:
Changes to the Technical Specifications Date of Issuance: December 21, 1984
ATTACHMENT TO T'ICENSE AMENDMENT NO.103 FACILITY OPERATING LICENSE NO. DPR-50 DOCKET NO. 50-289 Replace the following pages of the Appendix "A" Technical Specifications with the enclosed pages. The revised pages are identified by Amendment
- number and contain vertical lines indicating the areas of change. The corresponding overleaf pages are also provided to maintain document completeness.
Remove Insert 3-100 3-100 3-101 3-101 3-102 3-102 3-103 3-103 3-104 3-104 3-105a 3-105a 4-81 4-81 i
RADI0 ACTIVE CASEOUS PROCESS AND EFFLUENT MONITORING INSTRUMENTATION LIMITING CONDITION FOR OPERATION 3.21.2 The radioactive gaseous process and effluent monitoring instrumentation channels shown in Table 3.21-2 shall be OPERABLE with their Alarm / Trip setpoints set to ensure that the limits of Specification 3.22.2.1 are not exceeded.
The Alaru/ Trip setpoints, of these channels shall be determined in. accordance with the ODCM.
APPLICABILITY:
As shown in Table 3.21-2 ACTION:
a.
With a radioactive gaseous process or ef fluent monitoring instrumenta-tion channel alarm trip setpoint less conservative than required by the above, immediately suspend the release of radioactive effluents moni-tored by affected ch,annel or declare the channel inoperable.
1.
With less than the ministas number of radioactive gaseous process or _ effluent monitoring instrumentation channels operable, take the ACTION shown in Table 3.21-2.
BASES The radioactive gaseous effluent instrumentation is provided to monitor and control, as applicable, the releases of radioactive materials in gaseous effluents during actual or potential releases. The alarm / trip setpoints for these instruments shall be calculated in accordance with NRC approved methods in the ODCM to ensure that the alarm / trip will occur prior i
to exceeding the limits of 10 CIR Part 20.
The low range condenser offgas noble gas activity monitors also provide data for determination of steam generator primary to secondary leakage rate. Channel operability requirements are based on an ASLB Order dated October 31, 1984.
l l
l t
Amendment No. g,103 3-100 eg e
ye----,-
---,1--,+wrwe-,--v-ev.
-,n-..-.--
-, ~.
e e
.,-~vrer-
e
- + - + = = -
~
1 l{
TABLE 3.21-2 j
RADI0 ACTIVE GASEOUS PROCESS AND EFFLUENT MONITORING INSTRUMENTATION MINIMUM li CHANNELS I
INSTRUMENT OPERABLE APPLICABILITY ACTION 1.
Waste Gas Holdup System
.a b$
a.
Noble Gas Activity Monitor 1
25 (RM-A7) b.
Ef fluent System Flow Rate 1
26
~Hessuring Device (FT-46) l l
2.
Waste Gas Holdup System Explosive Cas Monitoring System hk
'a.
Hydrogen Monitor 1
30 b.
Orjgen Monitor 1
30
lE TABLE 3.21-2 (Continued) it RADIOACTIVE GASEOUS PROCESS AND EFFLUENT HONITORING INSTRUMENTATI0fl 3
MINIMUM o
CHANNELS INSTRUMENT OPERABLE APPLICABILITY ACTION 3.
Containment Purge Monitoring System O
a.
Noble Cas Activity Monitor 1
27 (RM-A9) b.
Iodine Sampler (RM-A9) 1 31 c.
Part iculate Sampler (RM-A9) 1 31 d.
Ef fluent System Flow Rate 1
26 Measuring Device (FR-148)
Y E
e.
Sampler Flow Rate Monitor 1
26 w
9 i
+
b
- ~.
l i
)
TABLE 3.21-2 (Continued) i II tg RAJI 0 ACTIVE GASEOUS PROCESS AND EFFLUENT MONITORING INSTRUMENTATION 1
MININUM r+
CHANNELS k
$E INSTRUNENT OPERABLE APPLICABILITY ACTION
,I 4.
Condenser Vent System I
Es a.
Low Rang 4 Noble Gas Activity Monitor (RN-ASLo and 2(j )
i 32 Suitable Equivalent)
Note 1: For one of the channels, an operable channel may be defined for purposes of this specification and 4.21.2 only as a suitable equivalent monitoring system capable of being placed in service within one hour. A suitable equivalent system shall include instrumentation with comparable 1-sensitivity and response time to the RM-ASLo monitoring channel. When the equivalent monitoring system is in service, indication will be continuously available to the operator, i
either through indication and alarm in the control room or through communication with a g
designated individual continuously observing local indication.
6 l
i i
t
}
l
O F
e TABLE 3.21-2 (Continued)
RADI0 ACTIVE GASEOUS PROCESS AND EFFLUENT MONITORING INSTRUf1ENTATION a
g MINIMUM CHANNELS y
INSTRUMENT OPERABLE APPLICABILITY ACTION 5.
Auxiliary and Fuel Handling a
E$
Building Ventilation System a.
Noble Gas Act ivity 1
27 Monitor (RM-A8) or (RM-A4 and RM-A6) b.
Iodine Sampler (RM-A8) or 1
31 (RM-A4 and RM-A6) c.
Particulate Saspler
[
(RM-A8) or (RM-A4 and RM-A6) 1 31 d.
Ef fluent System Flow I
26 e.
Sampler Flow Rate Monitor 1
26
TABLE 3.21-2 (Continued)
TABLE NOTATION d.
Prior to degas operations, a grab sample shall be taken and analyzed. If the hydrogen concentration is greater than 1%, nitrogen shall be added to reduce the hydrogen concentrations to less than 1%.
During the degas operation, a grab sample shall be taken and analyzed every 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. Following the initial makeup tank dis-charge, take and analyze a grab sample for hydrogen, if the hydrogen concentration is greater than 1.0%,
nitrogen shall be added to reduce the hydrogen con-centration to less than 1.0%.
t If the hydrogen monitor is operational, hydrogen monitor results may be used rather than grab sample analysis for hydrogen. Alternately, if the oxygen monitor is operational, oxygen monitor results may be used rather than grab sample analysis for oxygen.
2.
If the channel is not OPERABLE within seven days, a tele-phone call will be made by the Vice President of TMI-l (or his designate) to the Director of Region I Office of Inspection and Enforcement (or his designate) describing the reasons for the delay and the corrective actions being taken. A written report documenting reasons for the delay and corrective actions taken will be forwarded within 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> of the telephone notification.
ACTION 31 With the number of channels OPERABLE less than required by the Minimum Channels OPERABLE requirement, effluent releases via this pathway may continue for up to 28 days, provided, that within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> af ter the channel has been declared inoperable, samples are continuously collected with auxiliary sampling equipment.
l ACTION 32 With the number of channels OPERABLE less than required by the minimum channels OPERABLE requirements, effluent releases via l
this pathway may continue for up to 28 days, provided that one OPERABLE channel remains in service or is placed in service within one hour. After 28 days, or if one OPERABLE channel does not remain in service or is not placed in service within one hour, the provisions of 3.0.1 apply.
1 l
l Ancndnent No. 410's 3-105a
b.
The steam generator shall be determined OPERABLE after completing the corresponding actions (remov' l from a
service by plugging, or repair by the kinetic expansion
- process, of all tubes exceeding the repair linic and all l
tubes containing througsrall cracks) required by Tablu 4.19.2.
4.19.5 Renorts Following the completion of each inservice inspection of a.
steam generator tubes, the number of tubes repaired or removed from service in each steam generator shall be reported to the NRC within 15 days.
b.
The complete results of the steam generator tube inservice inspection shall be reported to the NRC within 3 nonths fol'.mwing complation of the inspection. This report shall include:
1.
Number and extent of tubes inspected.
, 2.
Location and percent of wall-ehirien==s penetration for each indication of an imperfection.
l 3.
Idene4*4-= tion of tubes rena'ifed or removed from service, c.
Rasults of stamm generator tube inspec-dons which fall into Category C-3 and require prompt nor4N "="4an of the NRC shall be reported pursuant to Spa-4#4-= tion 6.9.2 prior to resumption of plant operation. The written followup of this report shall provide a description of investigations conducted to determine cause of the tube degradation and corrective measures taken to prevent recurrence.
l Bases The Surv=471==e Requirements for inspection of the stamm generator tubes ensure that the structural integrity of this por-dan of the RCS will be==4ne=4nad.
~
4-81 Amendment Ho. 47, 33, 103
De program for inservice inspection of sesEs generator tubes is based on a modification of Regulatory Guide 1.83, Revision 1.
Inservice inspection of steam generator tubing is essential in order to maintain surv=411 =ce of the conditions of the tubes in the event that there is evidence of merh=n4 ' 1 damage or progressive
=
degradation due "to design, manufacturing errors, or inservice c=d i -4 = =.
Inservice inspection of steam generator tubing also provides a means of charactard-dag the nature and cause of any' tube degradation so that corrective measures can be -h na Unit is expected to be operated in a. manner st$ch that the secondary coolant will be maintained within those rh==4= cry 11=1ts found to result in negligible corrosion of the steam g=.narator tubes.
If the s---d=7 coolant chemistry is not main *=4=-d within these ehemistry limits, localized corrosion may likely result in stress corrosion cr=ekdag.
~
n e extent of steam generator tube leakage due to cracking would be limited by the secondary coolant activity Specification 3.1.6.3.
na excent of cr=awag during plant opera-J.on would be limited by the limitation of total steam generator tube laakage between
- the primary coolant system and the s'acondary coolant system (primary-to-secondary leakage = 1 spm).
L==k=ge in excess of this limit will require plant shutdown and an unscheduled insoection, during which the 1==H ag tubes will be located and repaired or removed from service.
Wastage-type defects are -14k=1.7 with proper chemistry treatment j
of the secondary coolant. However, even if a defect would develop l
in service, it will be found dt. ing scheduled inservice steam generator tube examinations. Plugging or repair will be recuired for
'l degradation equal to or in excess of 40% of the tube a d==1 vall *hirkness, unless higher limits are shown to be acceptable r
by analysis and are reviewed and approved by the NRC. Steam generator tube inspections of opera-dag plants have demonstrated the ca==M14ty to re.11 ably detect dese=d=*4 =_ that has penetrated 20% of the or4 4==~1 tube well eh4ab - =.
Where expahas in s4=41=e plants with similar water chemistry, as documented by USNRC Bulletins /Cira"T=en, 4=d4e=te critical areas to be inspected, at least 50% of the tubes inspected should be from these critical areas. First sample inspections sample size may be modified subject to NRC review and approval.
NUREG-1019 Supp. No. 1 E
SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION FACILITY OPERATING LICENSE NO. DPR-50 GPC NUCLEAR CORPORATION, ET AL THREE NILE ISLAND NUCLEAR STATION, UNIT 1 (TMI-1)
DOCKET NO. 50-289 STEAM GENERATOR TUBE REPAIR AND RETURN TO OPERATION d
1 ywm,--^-
-e-+
wr-y--,-w-
-e-yw q
e.--
---g
#w-r e,-
mrw-:sww-
-w-t w<w
-*-*ww w-w-r*-re------N--
---m
0 TABLE OF CONTENTS Page 1
INTR 000CTION.....................................................
I 3
EVALUATION OF REPAIR.............................................
2 3.1 Determination of Causative A5ent(s).........................
2 3.2 Examination and Repair of the Rem &inder of the RCS..........
2 3.3 OTSG Examinations to Determine Extent of De 4
OTS G Repa i r................................ gra da t io ns......
3.4 6
3.4.1 Requi rements of the Repai red Joint...................
6 3.4.2 Mechan.ical Tests to Qualify the Repair Process.......
6 3.5 Cl eanup.o f the Conta i nment..................................
14 3.6 Procedures to Prevent Re-Introduction of Containments.......
19 3.7 Post-Repair Testing and Operational Crack Arrest Considerations............................................
21 4
3.8 Occupational Dos e As s es sment................................
22 4
PLANT PERFORMANCE EVALUATION.....................................
23 i
4.3 Emergency Operating Procedures..............................
23
- 4. 3.1 Gu i d el i n e............................................
23 4.3.2 Procedures...........................................
25 5
CONCLUSIONS......................................................
27 5.1 S u mma ry...........................'..........................
.27 5.2 License Conditions..........................................
27 5.3 Items Requiring Additional Submitta1s.........
28 5.4 Co n cl u s i o n.................................................
28 4
l ATTACHMENTS L
1.
Evaluation of TMI-1 Steam Generator Tube / Tube Sheet Repair (FRC TER, non-proprietary version) 7.
BNL TER, Three Nile Island Unit 1 Steam Generator LEFM and Load Characterization (September 28,1983) 8.
Letter dated November 14, 1983 GPUNC (P. R. : Clark) to NRC (H. R. Denton),
Subject:
Commonwealth of Pennsylvania Comments on TMI-l Steam Generators t
__,___-..._..._.,_..._.~....,,_.._,...-.._.-_._,._sm.,...._
l 1.
INTRODUCTION On August 25, 1983, the Nuclear Regulatory Commission issued NUREG-1019, its Safety Evaluation dealing with the steam generator tube repair and return to operation of TMI-1. The staff concluded that the steam generator repair program was acceptable, tnat appropriate General Design Criteria (GDC) had been met, and that subject to resolution of open items identified in Section 5.3, there is reasonable assurance that the health and safety of the public will not be endangered by operation of TMI-1 with the repaired steam generators.
Since issuance of NUREG-1019, the licensee has provided additional information in Revision 3 to its Topical Report 008 and in its letter of September 30, 1983, which included Revision 2 of TDR-406 (SGTR Guidelines) as well as GPU comments on NUREG-1019. Updated versions of Emergency Procedures 1202-5 (OTSG Tube Leak / Rupture)) and Emergency Plan Implementing Procedure 1004.7 (Offsite/Onsite Oose Projections) have been made available to the staff.
In addition, by letter of October 25, 1983, the licensee submitted TDR-488, TMI-1 OTSG Hot Testing Results and Evaluation.
The purpose of this Supplement is to update NUREG-1019 by addressing the above information.
1
(
In the SER, we provided a description of the repair method which focused on the 22-inch kinetic expansions which are limiting in determining that j
tube pullout from the tubesheet cannot occur under design basis accident conditions as a consequence of severance of the tubes at the tube repair transition zone. By letter dated September 30, 1983, the licensee noted that our SER did not clearly indicate that tubes were repaired using both 22-inch and 17-inch kinetic expansions. We agree with the licensee's comments.
l
. The majority of tubes were repaired using a 17-inch expansion because the vast majority of defects were located near the top of the upper tubesheet.
The 17-inch expansions provided for repair of tubes with defects down to 11 inches from the top of the tubesheet while retaining the 6-inch qualification zone. Tubes with defects between 11 inches and 16 inches were repaired using 22-inch expansions. Because the 22-inch expansion, which is the limiting case, was already addressed, the information does not alter the conclusions in our SER.
3 EVALUATION OF REPAIR 3.1 Determination of Causative Agent (s) 1 In the SER, at the top of page 8, we stated that "The thiosulfate tanks have also been physically removed."
By letter dated September 30, 1983, the licensee pointed out that the lines which connect the thiosulfate tank to the reactor coolant system have been physically severed and sealed but the tank has not been removed. This information does not alter our conclusion in the SER.
l 3.2 Examination and Repair of the Remainder of the RCS i
In the SER on page 9, we stated that "all corrosion-affected sections in the l
waste gas system have been replaced."
By letter dated September 30, 1983, the licensee noted that only sections of the waste gas system with unacceptable I
corrosion have been replaced. Piping with minor corrosion indications will be placed on an augmented inspection list. We agree with the licensee, because l
sections of this low pressure system in which the corrosion indications were l
not significant need not be replaced.
l l
. The third paragraph on page 9 of the SER should now read:
"During a supplemental examination of systems which interface with the reactor coolant system, evidence of sulfur-induced corrosion was found in a waste gas system stainless steel line. The extent of corrosion was quantified and all sections with identified cracks have been replaced. One valve in the waste gas system exhibited an indication which could not be identified as a defect. This valve has been placed on the in-service inspection list for further monitoring.
In addition, the power operated relief valve (PORV) was removed for examination. Components of the PORV were found to exhibit pitting corrosion attributable to sulfur which could have reduced the valve's capability to function but did not affect its structural integrity. At a meeting on May 20, 1983, the licensee provided results of the pressurizer corrosion examination. Examination of the PORY block valve, the connecting piping, safety relief valves, and the remainder of the pressurizer revealed only shallow pitting on a non-seating surface of one of the two safety relief valves. Based on this examination, tiie PORV was rebuilt with uncorroded parts. Both safety relief valves were replaced for reasons other than corrosion.
The conclusion on page 13 of the SER should now read:
Conclusion The staff finds that the PORV was refurbished with uncorroded parts.
Additionally, the staff notes that, although some light pitting was found on one of the two safety valves, the pitting was on a nonseating surface and neither valve body had to be replaced because of corrosion. Also, affected portions of the waste gas system were replaced where necessary. The remainder of the reactor coolant system and interfacing systems which
4 were inspected, within the limitations of the inspection method employed, disclosed no defects attributable to sulfur-induced corrosion. Therefore, based on the above, the staff finds that GDC 1, 14, 15 and 31 have been met, and that reasonable assurance exists that the public health and safety is protected."
l 3.3 OTSG Examinations to Determine Extent of Degradation In the SER, we sumarized in Table 3.3-1 an extended post-repair eddy current inspection plan and imposed a license condition for monitoring and plant shutdown if primary to secondary leakage increased significantly. By Topical Report 008, Rev. 3 and letter dated September 30, 1983, the licensee indicated that the post-repair baseline eddy current inspection has been l
completed according to Table 3.3-1 in the SER. However, the number of tubes tested in each category vary slightly, because Table 3.3-1 is intended to i
provide approximate numbers. The results of the post repair inspection were consistent with the 100 percent inspection record in 1982.
1 Additionally, the licensee stated that primary to secondary leakage monitoring has been conducted'and that a leakage rate of 0.1 gpm above baseline is detectable. The infomation provided does not alter our conclusion that the 4
post-repair extended inservice inspection program is acceptable. However, the license conditions need to be' revised to reflect the above information and l
completion of the OTSG hot functional test program.
i l
The following should be added before the Conclusions in Section 3.3 of the i
SER:
"The post-repair baseline eddy curent inspection described in Table 3.3-1 was completed both in scope.and methodology. The results of the post-repair l
baseline eddy current inspections were found to be consistent with the l
100 percent inspection record of 1982. While some tubes were plugged as a preventive measure as a result of the baseline inspection, it is generally l
concluded that small arc length partial through-wall cracks existing in the l
tubing are not growing nor are new cracks occurring.
i.
-,. _ ~ _ _ _.. -, _., _ _, _ _,., _ _. _ _
. The 66 tubes left in service with less than 40% through-wall degradation, which is consistent with the Technical Specification plugging limit, were also re-examined as part of the post-repair baseline eddy surrent inspections. One tube was plugged based on a shift in the phase angle of the OD indication which was now interpreted as exceeding 40%, whereas previously it was evaluated at 35%.
Based on these results we find that the licensee has conducted the post-repair ECT baseline examinations in accordance with their proposed program. We agree with the licensee that with both the post-repair ECT baseline data and the 100 percent inspection record of 1982, there is now an adequate basis for evaluating any new or changed ECT indications found in subsequent inspections.
l Conclusions The proposed license conditions in the Conclusions portion of Section 3.3 should be revised to read as follows:
(1) the licensee shall conduct extended post-repair eddy current exami-l nations, essentially consistent with the inspection plan defined in Table 3.3-1, either 90 calendar days after reaching full power, or 120 calendar days after exceeding 50% power operation whichever comes first and (2) The licensee shall confirm the baseline primary-to-secondary leakage rate.
If leakage exceeds the baseline leakage rate by more than 0.1 gpm, the plant shall be shutdown and leak tested.
If any increased leakage above baseline is due to defects in the tube free span, the leaking tube (s) shall be removed from service. The baseline leakage shall be reestablished, provided that the present technical specification limit of 1.0 gpm is not exceeded."
L
. I 3.4 Once-Through Steam Generator Repair 3.4.1 Requirements of the Repaired Joint 1
3.4.1.b.
Thennal and Pressure Cycle Loading In the SER, we stated that 5 years of design basis themal cycling and transient testing has been completed to demonstrate that the repaired joint will maintain its load-carrying and leak-tight capabilities. By i
Rev. 3 of Topical Report 008 and letter dated September 30,1983, the licensee provided additional infomation pertaining to completion of 15 years of life-cycle testing. Evaluation of the 15-year life-cycle testing is included in Section 3.4.2 of this evaluation.
f 3.4.1.c.
Tube Preload In the SER, we stated that the tensile preload on tubes should not be altered so that the tubes would be under compression when cold. This assures that compressive loads during operation and vibrational characteristics of the tube will remain unchanged. By letter dated September 30, 1983, the licensee commented on our evaluation. Our evaluation of tube preload is' included in Section 3.4.2.d of this evaluation.
i i
3.4.2 Mechanical Tests to Qualify the Repair Process l
In the SER, we stated that 5 years of design basis thennal cycling and transient testing has been completed to demonstrate that the repaired joint will maintain its load-carrying and leak-tight capabilities, and that extended life-cycle qualification testing is in progress to confirm the continued acceptance of the repaired joint for time periods in excess of five years. By Rev. 3 of Topical Report 008 and letter dated September 30, 1983, the licensee provided additional information pertaining to completion of 15 years of life-cycle testing.
^.
The leakage rate on test blocks after 15-years of design basis thermal and load cycling varied between 3.1 x 10-5 and 6.8 x 10-5 lbm/hr/ tube as compared to a maximum value of 12.15 x 10-5 lbm/hr/ tube for the 5-year design basis cycling. Because the leakage rates at 15 years of design basis thennal and load cycling are comparable to those at 5 years, this information does not, alter the conclusion in our SER that the kinetically expanded joint is within the original licensing basis for the plant. The conclusion section needs to be changed and the proposed license condition deleted to reflect completion of 15 years of design basis thermal and load cycling, During OTSG operations actual primary to secondary leakage of the repaired joints w'ill be closely monitored to confirm the results of the 5-year and 15-year test program.
3.4.2.d Effects of the Kinetic Expansion on the Tubes In the SER, we stated that 1,025 pounds of compressive force is necessary to cause tube bowing. By letter dated September 30, 1983, the licensee indicated that tube bowing begins at approximately 800 lbs, but loads must reach 1,025 lbs before the lateral displacement of the tube exceeds the nominal space between tubes. This information does not alter the conclusions in our SER because our concern is relative to tube buckling I
which does not occur.
The second full paragraph on page 20 of the SER should be revised to read as follows:
J "The licensee has recently indicated that during the kinetic expansion process, an estimated 600 tubes lost pre-tension due to slight downward movement of as yet unexpanded tubes which had corrosion-caused full circumferential cracks. For tubes which have lost pre-tension, this would
~
result in a maximum cold compressive load of 16 lbs. Although this deviates from the licensee's repair-goal, it is insignificant-compared to the 800 lbs necessary to cause initiation of tube bowing and 1,025 lbs necessary before the lateral displacement of the tube would result in
e 1 contact with adjacent tubes. Therefore, there is reasonable assurance that the repaired tubes are not in significant compression while cold and will not buckle during heatup when maximum compressive stresses exist in the tubing."
In the SER, we stated that cracks which are below the threshold of detectability by eddy current testing will not mechanically propagate to failure and that through-wall defects which miy develop can be readily detected by primary-to-secondary leakage before the crack reaches a critical size for propagation. This statement was based on the assumption that, as fabricated, all OTSG tubes are under pre-tension. By Rev. 3 of Topical Report 008, the licensee provided new information on some tubes which had lost pre-tension prior to being repaired. The staff and our consultant (Attachment 7) have evaluated the new infonnation and determined that the loss of pre-tension will not significantly alter the vibrational characteristics of the tubes nor reduce the capability to detect through-wall cracks by primary-to-secondary leakage because the change in total tube tension is small. Therefore, this information does not alter the conclusion in our SER.
I In the SER, we also stated that 1.0 ksi in was used for the thresholci stress j
intensity factor (AKth). By letter dated September 30, 1983, the licensee
,I i
indicated that the 1.0 ksi in had been incorrectly stated in the SER and that 5
i 4.0 ksi in and not 1.0 ksi in was used for the threshold stress intensity I
l factor. The licensee stated that 4.0 ksi in stress intensity threshold factor is based on empirical data for Alloy-600 and thus is directly applicable.
We agree with the licensee that an empirical stress intensity factor of I
l 4.0 ksi in for A11oy-600 is applicable. Therefore, this infonnation does not alter the conclusions in our SER.
l
^
\\
l L
-9 Except for the first paragraph on page 21 of the SER, the remainder of Section 3.4.2.d should be deleted and replaced with the following:
"The effect of high cycle flow-induced vibration loading on the repaired steam generator tubes has been evaluated by the licensee. The steady cxial and high cycle bending loads define the tube loading. A linear-elastic fracture mechanics (LEFM) Code "BIGIF" developed by the Electric Power Research Institute has been used to determine when a crack of a given initial size can be expected to propagate through-wall. We find that this code is applicable because in a high-cycle flow-induced vibration loading condition experienced by the tubes in the OTSG's, the stresses are significantly below the 0.2% proof stress and well within the elastic limit of Alloy-600 tubing. Therefore, we agree with the licensee's use of the linear elastic fracture mechanics (LEFM) Code "BIGIF" developed by the EPRI to determine when a crack of a given initial size can be expected to propagate through-all. A key parameter in this analysis is the stress intensity factor which quantifies the interaction of crack size, shape, boundary geometry and stress field. The stress intensity factor calculation includes the loading due to internal pressure, and axial and bending loads which would tend to open up a crack during flow-induced vibration (FIV).
During steady-state operation, the steam generator shell to t abe tempera-ture difference could cause an axial tension of up to 500 lbs on a single tube.
In the analysis, the load cycle imposed on the tubes included mechanical and themal factors. Low cycle, long duration loads were combined with high cycle flow-induced vibration loading. The vibrational load amplitude l
-m
-m,,
.-w.p--
-g 7,
y
-n-y--
- - -,,,,.- n
. was selected to be the maximum tube displacement seen under steady-state loading. The maximum tension excursion, represented by the 100*F/ hour cooldown, which results in an axial load of 1107 lbs, was combined with high cycle loading.
A modified Paris equation was incorporated in the Code "BIGIF" with the feature that if the stress intensity factor range did not exceed threshold, I
no growth would occur.
In the analysis, 4.0 ksi in, a value based on empirical data for Alloy-600, was used for the threshold stress intensity factor (AKth), the value below which a crack will not propagate. The I
result of this analysis indicates that ECT is capable of detecting crack sizes which are smaller than those that can propagate by mechanical cyclic stress. Therefore, cracks which are large enough to propagate to failure I
can be detected and removed from service (Attachment No. 7).
The licensee performed additional calculations to determine the maximum crack size that would remain stable under loads experienced during a main steam line break (MSLB) accident. Results of the calculations indicate that cracks which would remain stable during a MSLB accident can be detected by ECT.
(See Topical Report 008, Figure IX-2).
Leakage rates for various tube axial loadings, including tubes which lost pre-tension prior to' repair, and crack are length were determined by the licensee (See Topical Report 008, Rev. 3 Figure IX-5 and IX-6).
Results show that leakage rates for predicted tube axial loadings will be detectable so that cracks below a size which can grow circumferentially during operaticr.s will be detected before reaching the critical size for propagation. The staff and our consultants (Attachment No. 7) have evaluated the information provided and concur with the licensee's l
conclusions.
In TDR-488, the licensee provided data which demonstrate that primary to secondary leakage during the steam generator hot test was approximately 1.0 GPH during steady state conditions, and increased l
l
to a maximum of approximately 2.6 GPH during the third cooldown~ transient when tube tension was maximized.
If a throughwall crack of sufficient length to propagate due to flow induced vibration existed, a minimum leakage rate of 23 GPH is predicted for the most limiting tube. Leakage rates for nonlimiting tubes are predicted at up to 80 GPH. Therefore, because of the low primary to secondary leakage rates during steady state and transient conditions, we find that there is reasonable assurance that the OTSG's do not contain critical size defects which could jeopardize the tube integrity when subjected to postulated accident design basis tube loadings.
In Attachment No. 7 to this supplement, our consultant indicated that the effect on crack propagation of residual stress fields in the formed tubes and the effect during heatup of tube bowing on vibrational charac teristics should be further addressed by the licensee. As discussed below, the staff finds that additional discussion of the topics by the licensee is not required.
In Section V.C.l.c of the Topical Report 008, Rev. 3, the licensee stated th'at a transition length between 0.125 and 0.25 inch would be a goal, with a minimum acceptable transition length of 0.1 inch for the kinetically expanded tubes. This transition length is significantly longer than the original as-fabricated transition length of 0.0625-inch stated in Reference 17 of the Topical Report. The increase in transition length will cause a corresponding decrease in strain in the transition zone.
Therefore, we find that the residual stresses in the transition zone of the kinetically expanded tubes would be lower than in the as-fabricated condition. Consequently, we conclude the transition zones should not be more susceptible to failure than the original as-fabricated transition zones.
12-Tube bowing is only of concern during plant heatup because the OTSG tubes which are relatively thin reach temperatures in therwal equilibrium with the coolant more rapidly than the OTSG shell and thus expand pro-portionally more rapidly than the shell during heatup. By letter dated September 30, 1983, the licensee indicated that tubes which have ex-perienced a loss of pre-tension may exhibit bowing deflections during heatup which may allow them to touch adjacent tubes. During heatup, stress in bowed tubes will remain compressive and, therefore, the loading will not accelerate crack propagation. Since there is little or no flow during heatup, little or no flow-induced vibration exists.
Consequently, the excitation force is miminal during heatup, and the flow-induced vibration of these tubes should remain below the levels exhibited by nominal tubes at full power.
Based on the above evaluation the staff finds:
1.
Cracks which are large enough, i.e., critical size, to propagate due to flow-induced vibration are readily detectable by ECT; 2.
Cracks which are below the threshold of ECT detectability will not propagate under combined cyclic, flow-induced and thermal loadings; 3.
The maximum crack size which will remain stable during a MSLB has been determined; 4.
Through-wall defects which may propagate during operation can be detected well below the threshold size that could fail during a MSLB.
e e--
- - ~
,me,-
,-..,,+s,.-
-w
,e m- -...,
,-n--,yw,%*
e, ry,
,,e, w
-c w-y
+y
e--
--e--
r, w-----
g e--
. Therefore, reasonable assurance exists that the potential for rapidly propagating failure of steam generator tubes due to flow-induced vibration is minimized."
Conclusion No.1 of Section 3.4.2 should now read:
"The kinetic joint meets the qualification requirements in terms of load-carrying capability, tube preload and residual stresses. Leakage of the laboratory test blocks, while somewhat exceeding the licensee's qualification goal, is well within the plant Technical Specifications limit of 1.0 gpm and is acceptable. Nitrogen pressure testing of the repaired 0TSG has shown fewer leaking tubes than was anticipated based on the laboratory test blocks. Continued structural and leak-tight integri-ty of the expanded joint has been verified by completion of a 15-year life cycle test program. Primary-to-secondary leakage of the repaired joints will be closely monitored to confirm the results of the test program. Thus, the structural requirements for the joint are satisfied for operating, transient, and design basis accident conditions; leakage is well within Technical Specification limits; and thermal / pressure cycle capability has been demonstrated for operation.
In the event that relaxation of the repaired joints occurs due to some unanticipated mechanism, joint leakage will increase. Excessive. joint leakage would require shutdown and repairs to maintain primary-to-secondary leakage limits of the Technical Specifications. Therefore, the kinetically expanded joint is within the original licensing basis for the plant."
The last paragraph of Section 3.4.2 regarding the proposed license condition on submittal of the extended life cycle program results is deleted, since completion of the 15-year life cycle test program satisfies that proposed condition.
. 3.5 Cleanup of the Contaminant In the SER, we stated that all piping will be flushed to remove soluble sulfur contaminants, that the administrative limit for sulfur in the coolant is _0.1 ppm, and that the licensee proposed to remove sulfur contamination on the RCS pressure beundary components by an alkaline peroxide treatment.
By letter dated September 30, 1983, the licensee stated that all piping larger than 1 inch in diameter has been flushed to remove soluble sulfur contaminants. The SER referred to an administrative limit of 0.1 ppm for sulfur in the coolant. The limit is for sulfate ion rather than sulfur.
In Topical Report 008, Rev. 3, the licensee indicated that the alka-line peroxide treatment for the desulfurization of RCS surfaces has been carried out. The actual treatment conditions, the measurements and the results obtained throughout the desulfurization operation were also described. Based on our review of this information, we find that our previous conclusions on this topic remain unchanged.
1 This section should now read:
"All RCS tanks, components and piping larger than 1 inch diameter, which had contained sulfur impurities, have been flushed to remove f
soluble sulfur contaminants. Due to the small volume of fluid j
in pipes with less than a 1-inch diameter compared with the total l
volume or the reactor coolant system, flushing of these small lines l
1s not warranted. Based on Topical Report, 008. Rev. 3, sulfate concen-trations (50j) remaining in the coolant have been reduced to less than 0.1 ppm.
In this concentration range, sulfate ion does not have a significant corrosive effect.
If the sulfur is present as i
l
. thiosulfate ion, S 0, testing conducted by the staff consultant 23 (NUREG-1019, Attachment 2) has shown that the threshold concentra-tion for the initiation of SCC in aerated borated water is about 0.075 ppm for sensitized 304 stainless steel and about 1 ppm for sensitized Inconel 600. No thiosulfate was detected in the coolant.
The staff consultant (NUREG-1019, Attachment 2) has also demon-strated that the initiation and propagation of SCC in these alloys at temperatures below 150*C is suppressed by the addition of LiOH, which has been used in many reactors for pH control without negative effects. A L1/S ratio of 10 in the solution is sufficient to achieve this suppression. The staff consultant further states (NUREG-1019, Attachment 2) that thiosulfate ion affects SCC by electromigration into the propagating crack; partial neutralization of boric acid by LiOH provides competing borate anions which exclude thiosulfate anions from the crack.
The licensee proposes to maintain the lithium concentration in the RCS at 1 to 2 ppm, which provides an adequate excess of lithium over the maximum administrative 1y allowed sulfate concentration of 0.1 ppm. The staff finds that this action is consistent with the staff consultant's reconnendation with which the staff is in agree-ment (NUREG-1019, Attachments 2-4) and, therefore, is acceptable.
t l
l After the removal of dissolved sulfur from the RCS, a concern remained that sulfur trapped in the oxide corrosion film on reactor surfaces might be converted by some sequence of operr. ting condi-tions in the future to more corrosive and active species. The staff consultant (NUREG-1019, Attachment 4) indicates that metallic sulfides (MS) can react with oxygen to form thiosulfate:
2 MS + H O + 20 - 2 M0 + S 0 " + 2H+
2 2
23 l
l i
e
{ After the flushing operation, approximate surface sulfur con-centrations on steam generator tube and other RCS surfaces were dVailable for estimating the potential of regenerating thiosulfate from sulfide. Estimates of surface sulfur concentrations, based mainly on swipe tests, ranged over more than an order of magni-2 tude, with the larger values as high as 10mg sulfur /cm,
if,))
of this sulfur dissolved in the coolant volume, the sulfur con-centration would amount to a few ppm.
In a state of intermediate l
valence, this concentration of sulfur would have the potential to reinitiate the corrosion mechanism.
The licensee has carried out an extensive secies of stress cor-rosion tests on sections of sulfur-contaminated steam generator tubes from TMI-l under conditions simulating those that resulted in the original failures of these tubes. Even in the absence of added LiOH, no initiation of SCC and no propagation of existing cracks were observed. These negative results, however, did not provide adequate assurance that some untested combination of exposure conditions would not liberate aggressive sulfur species.
To reduce the likelihood of corrosion problems from the sulfur remaining on the RCS pressure boundary component and piping surfaces, the licensee has desulfurized these surfaces by oxida-l-
tion with a dilute solution of hydrogen peroxide (H 0 ).
The 22 l
approximate treatment conditions are-sumarized in the following table.
l l
_1800 to 2300 ppm l
pH (ambient temperature) 8.0 to 8.5 H0 concentration 15 to 25 ppm 22 l
Temperature 130 1 5'F l
Cover Gas N2 Lithium ion concentration 1.8 to 2.2 ppm i
Duration of Treatment 400 hours0.00463 days <br />0.111 hours <br />6.613757e-4 weeks <br />1.522e-4 months <br /> i
i
_,. ~...
..-...m
2 17-l The pH of the system was maintained within the desired range by j
the addition of ammonium hydroxide. The concentration of H 0 "
22 was kept at 15 to 25 ppm by the injection of concentrated H 0 22 l
into the RCS using positive displacement pumps. The extent of cleanup was assessed by analyzing for sulfate in the reactor coolant.
l After treatment for 400 hours0.00463 days <br />0.111 hours <br />6.613757e-4 weeks <br />1.522e-4 months <br />, the sulfate concentration reached a plateau at 0.4 ppm, corresponding to the removal of approximately 0.33 lbs of sulfate from the RCS surfaces. This observation, com-l bined with the test data that 50 to 80% of the surface sulfur on TMI-l steam generator tubes was removed by the peroxide treatment.
provides the first reliable indication of the extent of sulfur contamination of the RCS surfaces. The amount of surface sulfur was within the broad range indicated by swipe tests on tube specimens from the TMI-1 steam generators. As in the licensee's laboratory tests, the sulfate concentration initially increased, then levelled _.off at a constant value, indicating that all of the surface sulfur accessible to the reagent had been removed.
The dissolved sulfate, ammonia, lithium and other ionic impuri-ties were reroved from the coolant by ion-exchange resin in the letdown purification sy; tem. The small quantity of sulfur removed from the reactor surfaces by the peroxide treatment
{
indicates (i) that the extent of the original contamination was low, and (2) that the amount remaining on the surfaces after desulfurization is very low. According to the licensee's tests, the' dissolution of the remaining sulfur would be slow, and _if it all dissolved instantaneously would produce a sulfate concen-f tration of only 0.1 to 0.4 ppm in the coolant. However, during the anticipated slow dissolution process, sulfur released to the
(
---v,--
---+.-.
,.w-e.--a
..-,n.
,,,,,,~,n,,., - - -
,~,,,-~n,w
,,w.--
,p-,,,,,m
.-a-
-. vm, e,,.w-
.,~~----e.
.-e-
-en.-
n-
. coolant is continuously removed by the letdown systen purification ion-exchangers and the actual concentrations of sulfur should remain at less than 0.1 ppm. The staff, therefore, finds that-there is reasonable assurance that the peroxide treatment has effectively reduced the sulfur contamination of the reactor surfaces to an acceptable extent. The potential for sulfur-assisted corrosion during subsequent reactor operation is further diminished by the measures described in the Safety Evaluation for monitoring the sulfate concentration and adding lithium to the coolant.
Subsequent to the desulfurization treatment, the licensee carried out a pre-critical steam generator hot functional test program, the results of which were reported in TDR-488, TMI-1 Hot Testing Results and evaluation. This program included a series of rapid cooldown tests of the steam generators from 530*F to 350*F. Axial stress on the steam generator tubes is at a maximum during cooldown. Therefore, through-wall circumferential cracks which may exist can be predicted to open
[
wider and increase in leakage rate. The condenser exhaust was monitored for Krypton-85, which had been added to the primary coolant j
as a leak indicator using two calibrated independent analyzers l
and grab samples analyzed off-site. The primary-to-secondary leak rate was well below the Technical Specification limit during all phases of the pre-critical steam generator hot functional test.
The rapid cooldown did not result in significant additional leakage, I
as indicated by Krypton-85 analyses and by analyses of the steam l.
generator water for boron and other primary coolant constituents.
We independently verified the licensee's analytical results, the j
method of calculation and the degree of agreement among the different measurement methods. We find that the licensee's leak l
detection methods will detect primary to secondary leakage at levels significantly below the shutdown limit of 0.1 GPM above l
background.
These results provide added assurance that the repaired tubes are leak-tight and the contaminant has been reduced to concentrations below which corrosion should not re-initiate."
\\
~ _.,. __
3.6 Procedures to Prevent Re-Introduction of Contaminants By letter dated September 30, 1983, the licensee brought several items to our attention.
In the SER, we stated that all RCS piping was flushed to remove the soluble sulfur. By letter dated September 30, 1983, the licensee indicated that only the RCS piping larger than one inch in diameter was flushed. Because the surface area of piping smaller than one inch in diameter is an insignificant fraction of the total surface area of the RCS, we agree with the licensee that the flushing of piping of one-inch and larger diameter is acceptable.
In the SER, we stated that the coolant will be sampled daily for sulfur analysis and continuously monitored for pH and conductivity. By letter dated September 30, 1983, the licensee informed us that the coolant was analyzed daily for sulfate rather than sulfur, and that the pH and conductivity were monitored five times a week rather than continuously.
The purpose of daily sulfate analysis is for early detection of sulfur contamination = of the primary coolant, therefore, in this case both sulfate and sulfur analyses would yield the same conclusions. The fre-quency for pH and conductivity monitoring had been incorrectly stated to be continuous in the SER.
In our opinion, monitoring of pH and j
conductivity 5 times per week is sufficient to provide information on the chemistry conditions of the primary coolant system. We agree with the licensee that the analysis for sulfate instead of si'1 fur is acceptable, and the frequency for monitoring the pH and conductivity is adequate.
i In Table 3.6-1 of the SER, we stated that the new limit for chloride was 6 0.15 ppm and for sodium f 1.0 ppm. By Rev. 3 of Topical 008, the licensee reduced their limits for chloride and sodium to ( 0.1 ppm.
. Additionally, a typographical error existed in the lithium limits which should read: old limit 0.2 to 2.0 ppm, new limit 1.0 to 2.0 ppm. We find that the proposed reductions in impurity limits for chloride and sodium are on the conservative side and, therefore, are acceptable.
In the SER, we stated that the RCS will be treated with an alkaline peroxide. By Topical Report 008, Rev. 3, the licensee informed us that the RCS has been treated with a lithium containing hydrogen peroxide solution of pH between 8.0 and 8.5.
This meets the commitment made by the licensee.
Based on the above, we find that there is no significant change from our previous evaluation and, therefore, the conclusion remains unchanged.
To reflect these acceptable changes, Section 3.6 should now read:
"The following measures have been implemented to prevent reintroduction of contaminants to the RCS.
1.
The sodium thiosulfate tank has been drained and the piping connecting it to the RCS has been physically severed.
2.
All RCS piping larger than 1 inch in diameter,-tanks, valves, the reactor vessel and other components which had contacted thiosulfate solutions were flushed to remove soluble sulfur compounds to a concentration of less than 0.1 ppm sulfate in the coolant.
3.
Administrative controls have been instituted on all pathways by which foreign chemicals might be injected into the RCS to minimize the potential for reintroduction of contami-nants. These pathways include the Lithium Hydroxide Mix
. Tank, the Boric Acid Mix Tank, the Reactor Coolant Bleed Tanks, the Borated Water Storage Tank and the Sodium Hydre-xide Tank.
4.
New analytical procedures have been implemented to detect the ingress of deleterious chemicals. The coolant will be sampled daily for sulfate analysis while pH and conductivity will be monitored five times per week.
5.
New limits have been placed on primary water chemistry to prevent the development of an aggressive coolant environ-ment. These changes are sumarized in Table 3.6-1.
6.
The RCS has been treated with an alkaline f.eroxide to remove a large fraction of the sulfur occluded in the oxide corrosion film on RCS surfaces. The tightly bound remaining sulfur will not be subject to sudden release to the coolant in corrosive concentrations.
The staff concludes that the above listed measures provide reason-able assurance that sulfur-containing contaminants will not be re-introduced to the RCS."
3.7 Post-Repair Testino And Operational Crack Arrest Considerations In Rev. 3 of Topical Report 008, the licensee provided the results of the reactor coolant system peroxide chemical cleaning program to remove residual sulfur. The results demonstrate that the cleaning was conducted as comitted to by the licensee. This confirms our conclusions in the SER.
In the SER, we stated that a hot functional test of the OTSG will be conducted by the licensee prior to normal pre-critical hot functional tests.
~
. The OTSG hot functional test program was to take approximately thirty days and include extensive leak testing and transients which will maximize stresses on the tubing.
By letter dated October 25, 1983, the licensee provided TDR-488 which contains information on the OTSG pre-critical (non-nuclear) hot func-tional testing. Primary-to-secondary leakage was monitored during the entire test period, using Krypton-85 monitoring as discussed in Section 3.5 of this supplement. Based on the OTSG leakage results, the licensee has established a baseline leakage rate of 1.0 GPH which is 1/60 of the Technical Specification limit. This low rate of primary-to-secondary leakage provides additional confinnation that the kinetic expansion procedure is an effective repair method. During subsequent operations, if leakage increases by 0.1 GPM (6.0 GPH) above background the plant will be shut down, the OTSG's examined and repaired as necessary. Reactor coolant system analysis showed sulfate concentra-tions between 20 ppb and 76 ppb, which provides additional confirmation that the principal. sources of sulfur have been removed. The low base-line primary-to-secondary leakage and low reactor coolant sulfate concentrations confinn our conclusions in the SER.
3.8 Occupational Dose Assessment In the SER, we discussed the occupational dose received during various portions of the tube repair program as well as that required to complete the program. Topical Report 008 Revision 3 presented revised figures for the completed program.
i I
=
The total exposure for the OTSG project was 1233 person-rems. Of this total, 579 person-rems were due to kinetic expansion alone. The balance of 654 person-rems was expended for other portions of the program such as preparatory work, tube plugging, end milling, cleanup, and testing. The licensee plugged 347 tubes prior to kinetic expansion. An additional 886 tubes were plugged as part of the OTSG program. Tube plugging and stabilization accounted for over half of the non-kinetic e'xpansion exposure. The balance of this exposure was due to RCS inspection, eddy current testing, end milling, cleanup, and' testing. The total exposure for the OTSG program of 1233 person-rems is comparable to exposures from steam generator repairs at other facilities and is acceptable.
The licensee's dose reduction techniques used during the OTSG repair are described in the SER. Our conclusions regarding occupational dose control remain unchanged.
4 Plant Perfonmance Evaluations 4.3 Emergency Operating Procedures 4.3.1 Guidelines In the SER, the staff identified the need for analytical justification of the modifications to steam generator tube rupture (SGTR) guidelines (TDR 406).
In the updated version of TDR 406, additional referenced documentation and clarifying discussion have been provided by the licensee to support the guidelines and address our requirement. This information has identified instrumentation used by the operator in implementing the SGTR procedure, methods of dose measurement to be used, and has addressed the timeliness of the dose measurement technique. We find that the measurement technique and equipment used are consistent with the licensing basis of the plant and therefore are acceptable.
The additional infomation also provided analytical detemination of cooldowr.
times so that some quantification of margin to the licensing basis dose criterion (500 mrem-whole body) can be estimated. The licensee has calculated 1
that the plant can be brought to decay heat removal (DHR) system cut-in conditions (300*F) using two steam generators in about 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> (limited by a 100'F per hour cooldown rate), versus the 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br /> assumed in SER estimates.
From these calculations we have concluded that the licensing basis SGTR event is not compromised by implementing TDR 406.
Ongoing generic work on guidelines (i.e., AT0G) and SGTR generic task actions will pursue resolution of issues applicable to B&W plants, including TMI, and may require future modifications to TDR 406.
In the interim, we find TDR 406 acceptable for implementation at TMI-1.
In the longer term, however, consistent with our ATOG SER requirement, we will require the licensee to provide the NRC with the additional systems analyses necessary for the staff to conclude that the emergency procedure guidelines for dealing with i
SGTR events at TMI-1 are fully justified.
In particular, these analyses should address the tradeoffs associated with (1) the higher doses that may result from steaming of the faulted generator in order to have better accident management, and (2) the lower doses that may result from isolating the faulted generator with the consequent potential increases in risk due to reduced management capability. Periodic steaming should also be addressed. This requirement must be satisfied on a schedule consistent with ATOG (we expect the first ATOG submittal in mid-1984).
In its review of the staff's SER, the Commonwealth of Pennsylvania comented on the SGTR procedures (see the staff's Final Determination of No Significant Hazards Consideration, Section 3.2, Comment 3) with regard to procedural flexibility necessary to assure releases of radioactivity as low as reasonably achievable. The resolution of that matter between the Comonwealth and licensee is reported in the licensee's letter to NRC dated November 14, 1983 (Attachment 8). The staff believes that for the interim, the flexibility available to the licensee's Emergency Director through the provisions of the Emergency Plan is acceptable. However, we will require that the TMI-1 SGTR guidelines and procedures be revised prior to restart to define alternative actions that can be employed to minimize offsite releases consistent with overall safety.
. 4.3.2 Procedures 7.
SG Isolation Steaming Criteria NUREG-1019 stated that the licensee will be required to incorporate the steam generator (SG) isolation criterion change from dose to dose rate into EP 1202-5.
In the licensee's September 30, 1983 letter, the licensee stated "The Control Copy of the approved and formally issued 1202-5 has dose rate rather than dose isolation criteria." The staff confirmed that Revision 22 of EP 1202-5 has incorporated this SG isolation criterion and finds this response to be acceptable.
8.
Pressure Control of Isolated GSs NUREG-1019 stated "However, neither Section I nor Section II instruct the operator to steam an isolated SG to keep SG pressure below 1000 psig. The licensee states that instructions for controlling pressure in an isolated SG are planned for inclusion in EP 1202-5. We require confirmation that this change has been made."
In the letter of September 30, 1983, the licensee states that the subject of the above discussion is feeding an isolated 0TSG for pressure control rather than steaming; however, it is both.
Revision 18 of EP 1202-5 had neither feeding nor steaming criteria for pressure control of an isolated SG. The licensee states in his September 30, 1983 letter that, "TDR 406, Rev. 2 no longer recommends feeding an isolated OTSG for pressure control...." The staff has confirmed that this change has been made to TDR 406 and that Revision 22 of EP 1202-5 does not contain feeding criteria for an isolated SG.
- _ =
l.
The staff review of Revision 22 of EP 1202-5 also confirms that criteria for steaming an isolated SG is contained in the procedure. The staff finds that these actions by the licensee to establish procedural instructions for controlling pressure in an isolated SG are consistent with TDR 406 and are acceptable.
t 9.
SG Shell to Tube Differential Teaperature Limit f
The staff stated in NUREG-1019 that TDR 406 requires that cooldown is to be stopped if the SG tube to shell delta T reaches 100*F, and the SG with the high delta T is to be steamed only to remove decay heat. NUREG-1019 stated that l
because EP 1202-5 did not address the 100*F criterion, the licensee will be required to clarify procedural actions for delta Ts in excess of 100*F.
The licensee responded in his September 30, 1983 letter that "The Delta T j
Limit in the procedure is 70*F.
If this limit is approached the guidance in 1202-5 does require that the cooldown rate be reduced or secured so as not to exceed 70*F."
The.70*F criterion is contained in 1202-5 and is more conservative than the 100*F criterion.
l The staff finds this guidance, acceptable for SG shell to tube differential temperature limit control.
l The concluding paragraph of Section 4.3.2 should therefore be revised to read as follows:
Based on our review of EP 1202-5 and referenced procedures, we conclude that the technical requirements of TDR 406 Revision 2 are implemented by EP 1202-5.
l i
i I
-.-,-_m.__~_m-,
,..-...---,-.-~-._.~--,,--~..,,...-_.,..s
.o..
_,- - ~~~ - -, -, -.
e i
~.
5.0 Conclusions 5.1 Summary i
.r In the SER, under conclusion (3), we stated that the structural and leak tight integrity of the expanded joint has been demonstrated for a period of five years. As discussed in Section 3.4.2 above, the licensee has presented information showing, and we have now concluded, that the integrity of the expanded joint has been verified by completion of a 15-year life cycle program.
5.2 License Conditions As discussed in Section 3.3 above, minor changes should be made in license conditions 3 and 4.
In addition, license condition 5 should be deleted as discussed in Section 3.4.2 above. These license conditions should now read as follows:
3.
The licensee shall conduct eddy-current examinations, consistent with the inspection plan defined in Table 3.3-1, either 90 calendar days after reaching full power, or 120 calendar days after exceeding 50% power operation which'ever comes first.
4.
The licensee shall confirm the baseline primary-to-secondary leakage rate established during the steam generator hot test program.
If leakage exceeds i
the baseline leakage rate by more than 0.1 GPM, the plant shall be shut down and leak tested.
If any increased leakage above baseline is due to defects in the tube free span, the leaking tube (s) shall be removed from service.
The baseline leakage shall be re-established, provided that the present Technical Specification limit of 1.0 GPM is not exceeded (SE Section 3.3).
i 5.
Deleted
. 5.3 Items Requiring Additional Submittals In the SER, we identified certain matters which required additional licensee submittals to confirm or update existing submittals. As discussed above, additional submittals have been received which acceptably resolve the identified matters. Therefore, this section is deleted.
5.4 Conclusion In the SER, we concluded among other things that, subject to resolution of the open items, there is reasonable assurance that the health and safety of the public will not be endangered by operation of TMI-1 with the repaired steam generators. Since the open items have been resolved in this Supplement, the reservation regarding open items is deleted.
t l
i 1
4 k