ML20236Y022

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Safety Evaluation Clarifying Determination of Acceptability of Test Duration for Performance of Integrated Leak Rate Test at Plant
ML20236Y022
Person / Time
Site: Oconee, 05000000
Issue date: 07/08/1987
From:
NRC
To:
Shared Package
ML20195F761 List:
References
FOIA-87-714 NUDOCS 8712110035
Download: ML20236Y022 (3)
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Text

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Enclosure CLARIFICATION OF TEST DURATION WEN PERFORMING AN INTEGRATED LEAK RATE TEST OC0 NEE NUCLEAR STATION. UNITS 1. 2. AND 3 I

(TIA 86 33-FM)

BACKGROUND By Reference 1. Region !! requested clarification of paragraph 7.6 of Reference

2. as to who makes the determination of the acceptability of an ILRT test dur-ation shorter than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. The issue was raised during an insoection at the j Oconee Nuclear Plant. Unit 1 when the NRC inspector observed that the effective  !

period of test was approximately nine hours (Reference 3). An ILRT duration of less than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> is acceptable only when the test procedures and the method of calculation used are that specified in the 8N-TOP-1 (Reference 4). Using the data obtained at Oconee during the effective period of the test. i.e.. nine hours, together with the method of calculations of 8N-70P-1 would not satisfy requirements of the 10 CFR 50. Appendix J. III.A.3(a) (Reference 5). The staff of Region 11 discussed this matter with the utility during the inspection as well as during the subsequent telephone conference and identified the failure to record a consistent asss trend of independent data observations at hourly or i more frequent intervals for 24 consecut0ve hours as an apparent violation. The licensee contended that a reduced test durstion should be allowed on the basis of paragraph 7.6 of Reference 2 which states in part that "If it can be demon- l strated to the satisfaction of those responsible for the acceptance of the containment structure that the leakage rate can be accurately determined during a shorter test period, agreed-upon shorter period may be used."

Region !! believes that unless the method of calculation of leak rates is that contained in SN-TOP-1 the minimum test period must be 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> and that the reference to "...those responsible..." in paragraph 7.6 of ANS! N45.4 requires that NRC must review and accept any deviation of the 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> test duration be-fore it is implemented.

O!5CUS$10N The major guidelines for testing containments a:4 their penetrations are con-tained in the 10 CFR 50. Appendix J. AN5! N45.4., and the Topical Report 8H-709-1. Code of Federal Regulation 10 CFR 50, Appendix J. refers to ANSI M45.4 which specifies 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> ILRT duration unlars it is otherwise agreed upon. As stated before. ANSI N45.4-1972 specifies a 24-hour ILRT duration un-less the leak rate can be accurately determined during a shorter test period.

The term ' accurately determined" is not defined.

Bechtel Topical Report SN 70P-1 allows test duretion to be as short as six hours and the leak rate should be based on total time calculations over the i last five hours of test or last twenty sets of data points whichever provides  ;

the most data. The SN-TOP-1 provides, however that the contairs.ent should be allowed to stabilire at test pressure for four hours prior to the test.

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2 There are two questions to be answered regarding the subject issue, namely:

a. Is test duration shorter than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> sufficiently reliable, and
b. What parties are ..."those responsible" which can agree to a shorter test duration in accordance to paragraph 7.6 of ANSI N45.4.

Reliability of the leakage rate calculation depends on the amount of infor-mation gathered during the test. It is obvious that the data collected at the same intervals during a shorter period of time than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, will be less reliable than that which has been calculated during a full 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> test.

Furthemore, due to a large scatter of the test po' nts the "best fitted" curve is more reliable when it is drawn through the data points dich are somad over a longer period of time.

Pest esperience indicates that there are often situations when due to instrumentation malfunctioning or some environmental change. such as pressure or temperature, stabilization of the containment is disturbed. This is re-flected in the test information and eventually in the results of the test by altering the slope of the best fit or spikes and valley on the corresponding plot.

It is recognized that the ultimate responsibility for the safest operation of the plant and, therefore, leak-tightness of the containment rests upon the owner. Since the owner represents one party. however, the intent of paragraph 7.6 of the ANSI standard must be interpreted that the agreement regarding duration of the test must involve parties other than the owner's representative.

Otherwise, it would be an agreement reached between tuo individuals of the same party which would be meaningless. Consequently, it is logical to interpret the intent of the ANSI N45.4 standard that the parties agreeing on duration of the test should be the owner and a representative of a regulatory organization such as the NRC.

CONCLUSION The staff agrees with the Region !! interpretation of the howlation and of the Sta ndard. Since the ANS! N45.4-1972 Standard is referenced < n the 10 CFR 50 Appendix J, its provisions are the governing documents. A test duration of 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> is clearly stated in the ANSI Standard. Also, se agree that any change in the duration of the test is analogous to a change in Technical Specifications.

It must be reviewed and approved by the NRC prior to implementation.

Principal Contributor: R. Lipinski

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REFERENCES -

1. Memorandum to Gary M. Holahan, from Albert F. Gibson, dated July 11, 1986.
2. ANSI N45.4, " Leakage-Rate Testing of Containment Structures for Nuclear Reactors," 1972.
3. NRC Inspection Report No. 50-269/86-13, dated June 26, 1986.

4 Topical Report BN-TOP-1, " Testing Criteria for Integrated Leakage Rate Testino of Primary Containment Structures for Nuclear Power Plants,"

, Bechtel Corporation, November 1,1972.

l S. 10 CFR 50 Appendix J. "Primar L'ater-Cooled Power Reactors," y Reactor U. 5. Containment Government Printing Office Leakage Testing for Washington, ,

1986. l i

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Enclosure 3 DEC 151983 Dute Power Cespany Alth: Mr. H. 8. Tucker. Vice President hucle4r Production Department 4?? South Church Street Cha rlot te. kC 2824?

Gerit Ieacn:

SUBJEC1: ItIPORT Wo. 50.??0/83 35 1h t s re f ers to the rout ta, safety inspection conducted by Mr. [. H. BrooLS of this of fice on November 17 - 19. 1983 of activities authorized by NRC License ko. OPR-47 for the Oconee f acility and to the discussion of our findings held with inspett1on.

Mr. G. Davenport, Performance fest Engineer, at the conclusion of the Areas caamined enclosed inspectton ouring reportthe. inspection anc our findings are discussed in the Within these areas. the inspection consisted of selective eassinations of procedures and representat tre records, interviens with pe r s onne l , a nd ob s e rv a t i on s t>y t he i ns pec t o r.

Within the scope of this inspection, no violattons or deviations were disclosed.

In acrerdance De placed in with 10 (FR 2.190(a), a copy of this letter and 'he enclosure will the kRC's Put:lic Document Roon unless you not1(y this, of fice, by telephone, within ten days of the date of this letter and sub.ait written applica-tion letter.

the to withhold information contained therein within thirty days of the date of Such application rust be consistent with the requirements of

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S hou inert w i lt o y ou.

h you nne e nj ouesttons :oncerning this letter, we will be glad to discuss Sincerel ,

Hugh C. Dance, Chief Project Branch 2 Olvision of Project and Resident Prograers

[nclosure:

Inspect ion Report No. 50-270/83-35 cc */ encl.

J,[ Snittn, Station Manager eu / enc): (See pase )

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1. Persons Contacted Liceasee Employees J. E. Smith. N nager T. Ntthews. Licensing Technical Specialist
1. Barr Pe-formas4e Test Engineer

'G. Davenoort. Performave Test Engiacer NRC Resident Inspector D. falcaner

' At ten (M esit interview

2. Ea11 Interview The inspection scope and findings were summarized on Novescer 19. 1983, with those persons indicated in paragraph ! above. The licensec acknowledged the inspector's findings and agreed to investigate and correct the cause of leakage from the containsect tato the low pressure service water service systen 45 discussed in paragraph 5.

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Licensee Attic.n on Previous Enforcement Ntter<.

hot instteted.

4. 'Jnresolved ltem Laresolved itees were not identified during this inspection.
5. Surveillance - Conta twnt lategrated Leakage Rate Test (61719)

During the period et hovesoer 17-19. 1983 the inspector witnessed perf orm-ance of the containment integrated leakage rate test (CILRT) for Oconee huclear Plant Unit 2. The inspector reviewed the licensee's Reactor Building Integra ted Leak Rate Test Procedure PT/2/A/0150/03A dated October 10. 1983, and approved November 2. 1983. Yalve lineups and system venting and draining prior to the CILWT were performed in accordance with Reactor Building Integrated Leak Rate int Penetration Venting and Draining Procedure TT/2/A/0375/07. Er.:losures 13.3 and 13.4 of Prc,cedure TT/2/A/0375/07 provided those steps accessary to assure restoration cf the contairr=nt to the post-test condit tun. The inspector reviewea the results of 1,olation valve (Type C) leakage rate tests perf ormed October 22. 1983, th rough Novesoer 16, 1983, as documented in Procedure PT/2/A/0150/06.

Instrurenta tion psed during the CILRT was calibrated witnin sia snont hs preceding the CILRT in accordaeice with Duke Power Company Standards and Testing Facility Reference Menval. Through the use of these testing

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methods, traceability is maintained to the hattonal $sreau of Standards, lastrumenta t ton thcluded digital multtester, temperature detectors Kaye ramp scanner, dew potat hygrometers, dew point detectors and pressure 94v9es.

Contalement pressurtretton was inittsted at 1640 hours0.019 days <br />0.456 hours <br />0.00271 weeks <br />6.2402e-4 months <br /> on hovember 17, 1983, and stopped at 0G25 hours on hovember 18,1983, when contalarznt pressure of approstaately 30,5 pstg mas achieved. The liceesee's Technical Spectit-cations permit the Citti to be conducted at a reduced pressure of not less than 29.5 psig. During the initial phase of the ClLRT calculations indt-cated negative containment leakage, i.e,, leakage into the containment. It was subsequently determined that nitrogen supply to the core flood tar.Ls had not been properly isolated and vented outside containment. Accordingly, the nitrogen source was isolated and verted thus, etteinating nitrogen inleak-a ge. Containment penet ra tion valve lineup mas not af fected by these changes.

At apprus tsJtely 0600 W;urs on hovember 18, 1963, pressure was indicated at lA-!!0 on the local instrweent panel in the Unit 2 leak rate test room. it was suspected that air from the instrument air header was pressurtring the IA 110 sample line and the talet side of isolation valve ?!A 90 at' contain-mer,t penetration 41. A flange was installed on the discharge side of valve I A ll80 and IA-110 mas opened to vent the itne to isolation valve 21A-90.

Accordingly, any possible source of back pressure to the ins'rument air line containment isolation valve !!A-90 was removed and the leakage path via i

60atainment penetration 41 was subject to test pressure dif ferential.

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At 0930 hours0.0108 days <br />0.258 hours <br />0.00154 weeks <br />3.53865e-4 months <br /> on .evenber 18 -1983, maintenance personnel cut into a cross-over pipe on the I = pressure setytce water syste. near valve 2LPS-167 Air stcrted disc ha r9.a g tras the separated crossover pipe. Investigation upstream and 6own : ream of valve ZLPS-167 resulted in the following findings and actions:

(Reference Drawings PO 115b, PO-l?48-?)

4. 'Jressure gauge ?bG 190 reading 27 pstg.
b. valve 2tP5k 15 vertfice closed.
c. (cm pressure sertice water line was then vented at pressure gauge  !

2BG 190 and valve ?LP5W-145.

d. Manual isolation valves to penetrations 33, 34 and 35 were closed.

(2LP5W-Bl.?LP5W-82,?tP5W-83) j

e. Mar.ual valves to Rf A 31-10. RI A 31-11 and Rf A !? were closed.  ;

(2LP5W-?43.?tP5W-?4?,?LP5W-241.)

f. DO valves f rom penetrations 33, .74 and 35 were manually tightened closed. (?LP5W 24, ?LP5W-18, ?LP5W-21).

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g. Manual valves 2LP5W 776 and 2LP5W 777 in RIA instruments lines were l closed.

At 1400 hours0.0162 days <br />0.389 hours <br />0.00231 weeks <br />5.327e-4 months <br /> on November 18. 1983 It was reported that air was no longer discharging from the separated crossover pipe near valve 2LPS 167 which was ,

then closed. j l

The Itcensee's position in this matter is that the low pressure service j water to the reactor butiding cooling units via containment penetrations 33, 1 34 and 35 constitutes a closed loop inside containment and is not required {

to be vented and drained for a CILRT and the valve adjustments did not at ter any alignments required for venting and draining systees during the CILRT. Oconee Unit 2 Technical Specifications confirm the licensee's pot,1-i tion.

At_192fLhours on November 18. 1883 and data set 83, containment stabiliza g g,-g,,

tion was considered to have been achieved. At 0}4lt hours on November 19, 1983, the test was concluded with the following test results based on the h" r' I' ' '

atsolute test methA and mass point analysis:

Calculated leakage rate 0.1165 wt.1 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Upper 955 confidence level 0.1209 wt.% 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Manimum allowable leakage rate (Lt.) 0.176 wt.% 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> 755 of adzimun allowable leakage rate (0.75 Lt.) 0.132 wt.% 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> 3 i

The acceptance criteria for CILRT requires that the._ypper_. bound _.Q_tjle

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l 1eJkage rate calculated et 951 confidence leveT-~plus any required local leakage rate additions, shall be less than 755 of maximm allowable leakage rate.

During the exit inte. view the licensee agreed to investigate and correct the i cause of leakage from the containment into the low pressure service water systee. By telephone conversation with Region !! on November 28, 1983, the licensee advised that after depressurization of the containment the cause of the leakage was identified. Water from an open vent valve in containment was found to be spraying on the Reactor BuiNing Cooling Unit-B (penetration 34). The source of water to the LP5W systee is a cooling water lake (Lake Keowee ) located at higher elevation than the containment. During plant operation the LPSW water systee operates at approximately 90 psig thereby, providing a water seal. Oconee Technical Specifications Section 3.3.5, Reactor Building Cooling System, requires that when the reactor is critical, the reactor building cooling units and associated ESF valves shall be l operable. Accordingly, a water seal to containment lines via penetrations l 33, 34 and 35 mst always be in effect.

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i UNITED STATES j

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! c NUCLEAR REGULATORY COMMISSION REGIONil

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APR 0 6 581 1

Duke Power Company ATTN: W. O. Parker, Jr.

Vice President, Steam Production P. O. Box 2178 Charlotte, NC 28242 Gentlemen:

Subject:

Report Nos. 50-269/81-04, 50-270/81-04 and 50-287/81-04 This refers to the routine safety inspection conducted by F. Jape of this office on February 2 - March 10, 1981, of activities authorized by HRC C. eating License Ncs. OPR-38, OpR-47, and DPR-55 for the Ocones facility. Our preliminary findings were discussed with J. Ed Smith at the conclusion of the inspection.

A eas examined during the inspection and our findings are discussed in the enclosed inspection report. Within these areas, the inspection consisted of selective examinations of procedures and representative records, interviews with personnel, and observations by the inspectors.

During this inspection it was found that certain activities under your license appear to violate NRC requirements. These items and references to pertinent requirements are listed in the Notice of Violation enclosed herewith as Appendix A. With regard to item C, a reply is not requested for this item since this item was previously identified in our letter of January 20, 1981 as Appendix B, item B. Response is requested for that enforcement action. Elements to be included in your response are delineated in Appendix A.

t!e have exam'ned actions you have taken with regard to previously reported unresolved items. The status of these items is discussed in the enclosed report.

In accordance with Section 2.790 of the NRC " Rules of Practice," Part 2, Title 10, Code of Federal Regulations, a copy of this letter and the enclosed inspec-tion report will be placed in the NRC Public Document Room. If this report contains any information that you believe to be proprietary, it is necessary that you make a written application within 20 days to this office to withhold such information from public disclosure. Any such application must include the basis for claiming that the information is proprietary and the proprietary information should be contained in a separate part of the document. If we do not hear from you in this regard within the specified period, the report will be placed in the Public Document Room.

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4 Dske Power Company 2 ApA 0 6 %

- Should you have any questioris concerning this letter, we will be glad to discuss i them with you. l l

Sincerely, 1

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. C.yp, Actinp"iregor Otvision df Resident and i Reactor Project Inspection l

Enclosures-

1. Appendix A, Notice of Violation i
2. Inspection Report Nos. 50-269/81-04,  !

50-270/81-04. and 50-287/81-04 cc w/enci: q J. E. Smith, Station Manager q l

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APPENDIX A NOTICE OF VIOLATION Duke Power Company Docket Nos. 50-269 & 50-287 Oconee 1 and 3 License Nos. OPk-38 & DPR-55 As a result of the irnpection conducted on February 2 - March 10.1981, and in accordance with the interim Enforcement Policy, 45 FR 66754 (October 7 lHO),

t he : o llowini; v iolat ions were identi fied.

A IU Cf 4 5012(a)( 7) requires events of this type to be reported to the IAC 0;:e r a t i o n ., Center as soon as possib1'e and in all cases within one hear i, r the occurr.ence.

Curtrat) *e the above, on February 2, 1981, at 1455 hours0.0168 days <br />0.404 hours <br />0.00241 weeks <br />5.536275e-4 months <br /> Otenee lin i t I tripped f ru 6 5'. f u l l power and the event was not reported to the fikC Operat %ns Center.

T1.1 , i:, a be.erity Level VI Violation (Supplement 1.F.), applicable.t<, Unit 1.

B lechnical Specification 6.4.la requires adherence to pr'acedures for normal operation ar.c shutdown of systems and components involving nuclear saf et/. L

'ortrar r to the above, on February 23, 1981 1-LP-42 was opened w i t hw t

.m olt '. iv,g the required removal and restoration procedure which re:,ulted in a Int vi system status that caused an uncontrolled decrease in the

.ae> suit:er level 71s ' > a Severity Level V Violation (Supplement 1.E. ) applicable to Unit 1 ie ; nitai Specification 6.4.1 requires the station be operated and

,3 U i n ; '. ' in accordance with approved procedures.

L unti a ry : , ne above. on Feoruary 6, 1981. five sealec waoden c e n t ,, : r er. i which C C r, t a : n e:: radioactive waste were neither tagged or labeled as t er,Li'm!

by sta tion ; r,:edsre HP/0/B/1000/09.

This t- 2 5e er;ty tevel V Violation (Supplement I.E ) applicable tv Uni  :

ie.ncica! 5,ect!i:ation 3.1.2.4 restricts the secondary sice of a steam l yenerator te a r..aximum of 237 psig whenever tne vessel shell is at or below 110 F.

( ntary to tne abcve, on February 26, 1981, the Unit 3 8 steam generator was at 550 psig while the vessel temperature was at 70" F.

Ihl5 is ; $everity Level V Violation (Supplement 1.E.) applicable to Unit 3.

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l O Report Nos. 50-269,'.11-04, 50-27 V81-04 and 50-287/81-04 Licensee: Duke Power Company 422 South Church Street Charlotto, NC 28242 Facility Name: Oconee Docket Nos. 50-269, 50-270 and 50-287 License Nos. OPR-38, OPR-47 and OPR-55 Inspection at Ocones site near Seneca, South Carolina Inspectors: M m le, 3/45/r/

O(te 5fgned F. Jape, 5 ter or Resident }s 9

kL 3/45/r/

Date Jigned W. Orders,pesident Inspgorg (2&AW D. Myers, ident Inspector A.,

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Approved by: .

A W te 5tgned b/h/ ~ '

r9 ant /Jaction Chief, Division of Resident v and Reactor Project Inspection

SUMMARY

Inspection on February 2,1980 through March 10,1981.

Areas Inspected This routine in:pection involved 485 resident inspector-hours on site in the areas of plant operations, surveillance testing, maintenance observation, station modifications, emergency power tests, steam generator overprsssurization, reactor trip, radiological survey, integrated leak rate test, licensee corrective actions, steam generator tube plugging, and followup on unresolved items.

Results Of ths 12 areas inspected, no violations or deviations were identified in 7 l areas; 6 violations were found in 5 areas (Violation - Failure to report reactor i

trip, paragraph 11.b; Violation - Failure to follow procedure resulting in load shed, paragraph 9; Violation - Failure to label radioactive waste, paragraph 13:

Violation - Overpressurization of steam generator, paragraph 10; Violation -

Failure to survey and post a contaminated area, paragraph 13; Violation - Failure to follow procedures resulting in uncontrolled RCS level decrease, paragraph 12).

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DETAILS

( I l 1. Persons Contacted Licensee Employees q

'J. E. Smith, Station Manager "J. M. Davis, Superintendent of Maintenance "J. N. pope, Superintendent of Operations

  • T. B. Owen, Superintendent of Technical Services
  • R. T. Bond, Licensing and Projects Engineer

'T. Cribbs, Licensing Engineer l

Other licensee employees contacted included 17 operations personnel, 8 technicians,15 operators, 6 mechanics, 9 security force members, and 5 office personnel.

  • Attended exit interview
2. Exit Interview The inspection scope and findings were summarized on March 6,1981, with I those persons indicated in Paragraph 1 above. The Violations described in paragraphs 9,10,11,12 and 13 were discussed with licensee management who acknowledged them. Other inspection findings were acknowledged .without signi ficant comment.
3. ulcensee Action on Previous Inspection Findings (Closed) Unresolved Item (287/80-25-03) Review of licensee and vender supplied certification / data and review of the associated analysis reveals that RpS transmitters located inside the reactor building are not subjected to environments which surpass their qualifications. Licensee analysis also indicates initial reactor building temperature does not significantly affect post LOCA building pressure. Details follow in paragraph 19.

(Closed) Unresolved Item (269/80-30-01) The inspector discussed with the licensee the practice of storing aluminum . ladders within the reactor containment building. The chemical reaction of aluminum with boric acid is exothermic and results in byproduct generation of hydrogen. The safoty implications associated with hydrogen production inside containment prompted tha licensee to initiate the practice of removing all aluminum ladders from reactor buildings at the conclusion of each outage.

4 Unresolved Items Unresolved items were not ihntified during this inspection.

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5. plant operations i The inspector reviesed ple-t operations throughout the report period, to verify conformance with regulatory requirements, technical specifications and administrative controls. Control room logs, shift supervisors logs, shift turnover records and equipment removal anci mstoration records for the three units were continually perused. Interviews were conducted with plant operations, maintenance, chemistry, health physics, and performance personnel en day and might shifts.

Activities within the control rooms were monitored during all shifts and at shift changes. Actions and activities observed were c:.nducted as prescribed 1.' applicable Station Directives. The complement of licensed personnel on each shift met or escoeded the minieue required by T5 6.1.1.3. Operators l l

wen msponsive to plant annunciator alarws and appeamd cognizant of plant conditions.

plant tours were taker *.hroughout the reporting period on a continual basis.

The areas toured include but am not limited to the following:

1 Turt:1ae Su11 ding Auxiliary Building units 1, 2, and 3 Electrical Equipment Rooms Units 1. Z, and 3 Cable Spewding Rooms Station Yard Zone withis the protected area i I

Units 1 and 3 Sanctor Su11 dings l

During the plant tours, engeing activities, housekeeping, security, equipment status and radiation castrol practices were observed.

Dconee Unit 1 operated at approminately 895 FP from February 1 through 6, at ;

which time the unit was shut down to repair a staan generator tube leak.

Details of the t@e plugging efforts are in paragraph 17.

Following completion of the tee plugging effort. Inteesystem LOCA per-formance tasting revealed that Core Flood valve CF-12 leaked. Details of the repair of CF-12 are in paragraph 7. Following CF-12 repair. Unit I started up Man:h 3, and is, at the close of this report, at full power.

Dconee Unit 2 operated throughout the reporting period at apprestaately 735 FP en three Reactor Coolant Pumps (RCP); RCP 2B1 was removed from service on

.lanuary 31, 1981, due to a high bearing temperature. No other significant operational problems evolved aside from a Asactor Trip which occurred on February 11. Details of the trip are in paragraph 11.

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i Oconee Unit 3 remained in a refueling outage throughout the reporting period. An Integrated Leak Rate Test was successfully performed on the Reactor Building; details follow in paragraph 14. '

6. Surveillance Testing ,

l The surveillance tests detailed below were analyzed and witnessed by the l

inspector to ascertain procedural and perfomance adequacy.

The completed test procedures examined were analyzed for, embodiment of the necessary test prerequisites, preparations, instructions, acceptance criteria and suf ficiency of technical content.

I The selected tests witnessed were examined to ascertain that current written approved ;rocedures were available and in use, that test equipment in use was celibrated, that test prerequisites were met, system restoration completed and test results were adequate. l The selected procedures perused attested conformance with applicable Technical Specifications, they appeared to have received the required administrative review and tney apparently wet a performed within the sur-veillance frequency prescribed. .

Procedure Title Unit P1/0/A/0150/CSA Reactor Building Personnel Lock Leak Rate Test 1 PT/1/A/150/15D Intersystem LOCA Leak Test 1 HPI System Leakage 1 PT/0/A/150/23 PT/0/A/201/04 P.O.R.V. Operability Test 1 LPI System Performance Test 3 l PT/3/A/203/06 3 PT/3/A/600/11 Emergency Feedwater Performance Test 1

IP/1/A/305/3A RPS CH-A On-Line Test  !

2 IP/2/A/305/3C RPS CH-C On-Line Test RPS CH-D On-Line Test 3 I IP/3/A/305/3D 1 )

IP/0/A/310/12A HIP and RB Isolation CH#1 On-Line Test IP/1/A/310/13C RB Isolation and Cooling CH#6 On-Line Test 1 PT/0/A/600/18 Emergency Feed <ater Train Operability Test 1 The inspector employed one or mere of the following acceptance criteria for j evaluating the above items 10 CFR ANSI N 18.7 Oconee Technical Specifications Oconee Station Directive l Duke Administrative Policy Manual ,

l Within the areas inspected, no violations or deviations were identified, i

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7. Corrective Maintenance Observations Maintenance activities were observed and reviewed throughout the inspection period to verify that activities were accomplished using approved procedures and the work was done by qualified personnel. Where appropriate, limiting conditions for operation were examined to ensure that while the equipment was removed from service the appropriate requirements of the technical specifications were satisfied. The following were used as acceptance criteria:

-- Station Directives 3.3.1, 3.3.2, 3.3.5, 3.3.11 and 3.3.15.

-- Administrative Policy Manual, Sections 3.3 and 4.7.

Maintenance activities observed were as follows:

a Repair of CF-12, Unit 1 In response to the February 23, 1980, NRC generic letter regarding intersystem LOCA, DPC has established a program for leak testing core flood valves and low pressure injection check valves. On February 22, 1981, during performance of the check valves leak test, PT/1/A/150/150, CF-12 was determined to be leaking excessively. Five other check i valves, CF-11, -13, -14, LP-47 and -48 were determined to be accept- j able Repair and subsequent retesting of CF-12 were observed by the inspector. The job required draining the primary system to a level so '

the valve could be disassembled. A temporary sight gicss was installed to ensure accuracy of the RC level during the job and to avoid spilling RC water onto the workman. The work was done as authorized by Work Request 12335, and using procedure MP/0/A/1200/58. l The valve hinge and. disc were removed for future examination to determine the failure cause. New components were installed and the valve retested satisf actorily on March 2,1981.

The event report is scheduled to be submitted on March 6,1981, pursuant to Technical Specification 6.6.2.1(a)9.

b. RC Pump Closure Stud Examination Information Notice 80-27. Degradation of Reactor Coolant Pump Studs, and NSAC/INPO Notepad item prompted as examination of closure studs.

This work was completed for Unit 1 ch February 11, 1981 and for Unit 3 on February 4, 1981. The inspection for Unit 2 is scheduled for the March maintenance outage.

I The inspection of Unit 1 RCP studs indicated no significant corrosion.

Some corrosion was observed on all four Unit 3 RCP studs.

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.To determir.e the extent of the Unit 3 problem the exposed section of the studs were cleaned and measurements taken. The inspector witnesses this activity.

-- Review of Abip.. data revealed one stud on 3A1 pump did not meet minimum acceptance diameter. Procedures were developed to replace this stud.

The job was completed successfully err February 10,1981.

This maintenance activity was authorized by Work Request 51502.

TM/3/A/4000/86 and TM/3/1/4000/87. The inspector visited the job site and interviewed workmen periodically to verify adherence with pro-cedures and radiological controls.

Within the area inspectad, no violations were identified.

This event is reportable pursuant to Technical Specification 6.6.2.la(3) and has been assigned LER number R0-287/81-2 by the licensen.

c. Snubber Inspections - Unit 3 Technical Specification 4.18 requires a periodic visual inspection and functional testing of snubbers. This was performed on inaccessible and accessible snubbers during the fif th refueling outage on Unit 3. The records and results of this maintenance activity were examined by the inspector. No problems were reported.

The inspector also independently conducted a visual inspection of selected snubbers on the pressurizer relief lines, reactor coolant pumps, low pressure injection lines and steam lines. All were found acceptable and in agreement with the craftsman's data. A re-inspection of selected snubbers was done by both the licensee's personnel and the inspector following completion of maintenance work within the reactor building. No problems were identified.

Eleven snubbers wars removed for bench testing. All passed the i ree.uired functional tests. Three of these snubbers were examined by I the inspector to ensure they were properly installed. No problems were identified.

B. Nuclear Station Modifications The inspector reviewed changes to selected station safety-related systems to ensure that modifications were reviewed and approved in accordance with 10 .

CFR 50.59; that changes were controlled by established approved procedures and satisfactorily tested; that operating procedures and affected system diagrams were properly updated. The Duke Power Administrative policy Manual .

l Section 4.4 defines the basic requirements concerning administration of Nuclear Station Modifications (NSM). Of the two major NSM's reviewed, no violations were identified, f

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The NSM's tsviewed in detail ware:

a. NSM 1487 Reactor Cavity Seal Ring l The NRC expressed concern, in a generic letter, dated July IB,1979, to all licensees, over the storage location of the reactor cavity annulus seal ring. The concern was the- potential for the seal rirg to become a destructive missile in the event of a loss-of-coolant accident inside tha reactor cavity.

1 To resolve this concern, DPC has preparsd modifiu tion 1487 to remove the seal ring and store it in i location where it will not become a missile has ard. The work was to be comp 1sted during the scheduled refueling outages.

Followup on this item has been completed. Work has been satisfactorily completed on all three units as follows:

Unit 1 February 1980 Refueling Outage Unit 2 March 1980 Refueling Outage {

i Unit 3 December 1980 Refueling Outage l The inspector verified completion of this modification and had no questient er comments.  !

b. NSM 819C Fire Hose Stations insids U-3 RB Amendment 61 to Unit 3 Operating License DPR-55, required a number of fire protection modifications. Various completion dates were specified in the amendment. One of these items pertained to hose stations within the reactor building.

The inspector reviewed this item and found six fire hose stations in talled within the Unit 3 reactor building, The work was required to be completed prior to startup for cycle 6 operation. The valves for ]

these hose stations have been included in OP/3/A1104/10, Low Pressure i Service Water.

The inspector verified completion of this modification and a future inspection will verify compliance with fire codes.

9. Emergency Power Testing On Friday, January 30, 1981 Emergency Power Switching Logic (EPSL) Standby Breaker Closure Periodic Test Procedure, PT/3/A/610/1li, was being perfomed on Unit 3. In the process of returning breakers 3B2T-5 and 3B1T-2 to normal, following completion of the test, an inadvertent lead shed and Keowee Emergency actuation was initiated. It was discovered that six sets of links were left open contrary to steps in the procedure which require their closure. Review of the completed procedure revealed that the steps )

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1 requiring the closure of the links had been double verified, though the links rsmained open.

l The purpose of PT/3/A/610/1H, EPSL Standby Breaker Closure Test, is to verify that the circuitry utilized to transfer the unit auxiliaries from the startup source to the standby bus operate properly. Proper operation is i

verified by observing statalarms, computer points, and measuring the actual i times of several time delay relays. The initial preparation for the test involves placing jumpers and lifting links to allow the undervoltage transfer circuitry to perform its designed function without initiating an actual loadshed and Keowse Emargency Start. Additionally, fuse; are removed '

and installed per the procedure on the standby bus feeder breakers as required to prevent their tripping during the test. Auxiliaries were being c supplied through transformer CT-3 at the start of the test.

The cause of this particular incident was due to two separate errors. After '

the test acceptance criteria had been met and equipment was being returned l to noma 1, a performance Technician read the steps while the !&E technicians performed the work. After step 12.63 was complete, the Performance Technician read step 12.64. Both !&E technicians interpreted the step to require only the remoni of the variac. They did not close the sliding links (nat are also required by the step. One of the technicians signed the step as being complete and the performance technician perfomed the required double verification. He assumed that as the !&E Technician removed the variac leads and tightened the link screws, that he was also closing the sliding links. The links were, in fact, left open for the remainder of the test. Steps 12.65 through 12.68 were subsequently completed successfully.

The Performance Technician and an operator went to the breaker blockhouse to complete the last two steps of the procedure. Step 12.69 specified the closure of breaker 3B2T-5, which is accomplished locally at the breaker.

Several unsuccessful attempts were made to close this breaker. Further attempts were then made using the remote switch located in the Unit 3 ,

Control Room. At this point, the second error was committed. The per-formance Technician instructed the operator to reinsert the control fuses into breaker 381T-1 as required by Step 12.70. (An investigation into the failure of breaker 3B2T-5 to close in properly was not conducted prior to taking this action.) As an attempt was made to reinsert the fuses, breaker 3B1T-1 immediately tripped causing a load shed and Keowee Emergency Start.

Power for unit auxiliaries was then being supplied through Transformer CT-4 by both Keowee units.

Two Performance Technicians began investigating the cause of the load shed and Keowee Emergency Start. A Shift Technical Advisor (STA) and performance Technician noticed that Statalarm 3SA15-14, volt monitor logic undervoltage, was still lit indicating a low voltage on the startup source. This alam was recieved several times during the test. Perfomance Technicians then went into the cable room to verify proper closure of the links specified in Steps 12.63 and 12.64. At this point is was discovered that the six links listed in Step 12.64 had not been closed. Once the links were closed Statalarm 35A15-14 cleared, indicating the low voltage condition had been 4

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8 rectified. Breaker 382T-E was successfully closed and the fuses were ,

reinstalled in breaker 381T-1. The power for the unit auxiliaries was then transferred from CT-5 to CT-3, which is the normal shutdown supply.

Technical Specification 6.4.1 requires that the station be operated and maintained in accordance with current written approved procedures.

The Ir.cident detailed herein depicts two failures with the requirement to follow procedures. This is a violation and applies to Unit 3 (287/81-04-03).

10. Overpressurization of Secondary Side of Steam Generator - Unit 3 Technical Specification 3.1.2.4 allows a maximum pressure of 237 psig on the secondary side of a steam generator whenever the vessel shell is below

, 110'F. This limitation provides protection against nonductile failure of

- the secondary side of the steam generator.

During shift turnover, on Febru:try 26, the on coming crew observed a pressure of 500 psig on B steam generator, while the vessel temperature was at 70*F. Corrective actions were initiated immediately and the pressure was reduced to with the TS limit within 3 minutes.

At tne time of the event, the plant was preparing for startup followir.g an extended refueling outage. Earlier in the day, at 3:20 p.m. the secondary system was changed from condensate recirculation to feedwater recirculation. -

The condensate and feedwater valve checklist was completed per procedure.

This procedure calls for the startup control valve block valve to be open.

It is suspected that the startup control valves leaked allowing the steam generator to overfill and overpressuriZe the system.

i The steam generator was in a wet layup condition at the time the change was Nde to feedwater recirculation. In wet lay up, the steam generator high level alarm is actuated, thereby removing this audible trouble indicator from the operator. The main steam pressure indicator does not have an audible annunciator at this pressurt range.

A technical analysis of the overfill event on the steam generator and the main steam header' has been performed by the licensee's Mechanical and Nuclear Division. A visual survey of hangers on the system from the stop i valves to the steam generator has been conducted. No damage was reported.

Hanger spring settings are within specification.

Exceeding the technical specification pressure temperature limitation is a l )

violation of TS 3.1.2.4 and applies to Unit 3 (287/81-04-01).

11. Reactor 1 rips - Safety System Challenges l

The inspector reviewed data from recent reactor trips and safety system challenges to ascertain plant response, availability of data regarding the

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events and compliance with regulations, technical specifications and license l

conditions.

N events mytowed are discussed below.

On 2/11/81, at 9:23 p.m. Oconee 2 tripped from 45% Full Power (F.P. ). l

s. i The unit had been running on two RCP's (reactor coolant pumps) and was attempting to start a third RCP when the reactor trip occurred.

Starting the third pump apparently decreased voltage Onto2/12/81, one of the at two 0:33 operating RCP's and a RCP/ flux trip was initiated The a.m. during $he trip recovery, Oconee 2 tripped from 4% F.P.

reactor tripped or. high RCS pressure which resulted from increasing j reactor power at too high a rate for this low power level. Details of J

these two events follow: l On 2/11/81, Oconee 2 had been operating for approximately nine days on three ACP pumps at 735 F.P. High bearing temperatures caused by a low oil level had required taking 281 RCP out of service.

While perfr wing PT/0/A/150/19 (Electrical Penetration Leakage Test), a leak was uiscovered within the 2A1 RCP electrical penetration. An investigation of this leak was required to verify building" integrity and 2A1 RCP was taken out of service to allow safe inspection and testing of this penetration. N RCP/ flus reactor trip occurred when 2A1 RCP was restarted. N alars typer indicates that the trip occurred immediately after restarting the pump. The RCP/ flux trip is i initiated by a RCP power monitor. N power monitor is a watt trans-ducer which monitors current and voltage being used by the RCP. It outputs a voltage signal which is proportional to power drawn by the RCP. N output signal is fed to a pump monitor logic module which can initiate a trip signal to all four RPS (Reactor Protective System) channels if RCP power drops by 295 for caore than 200 ms.

This logic circuitry will generate a RPS trip signal if any of the following conditions esist:

(1) one RCP per loop at 54% F.P. or greater, (2) zero RCP's in one loop, or (3) one RCP at greater than 05 F.P.

At the time of the trip, r,witchyard voltage was low due to systes demand. The lowered switchyard voltage apparently contributed to a voltage drop in the puwer supplied to RCP 282 mMn 2A1 was restarted. I This power drop was sufficient in magnitude and deration to initiate l the 282 power montter RCP/ flus trip signal.

k asajor pmblems resulted from the trip, thus a trip recovery ensued.

Af ter reaching criticality, a control room trainee was withdrawing control rods manually to begin power escalation. He pulled rods at

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. ; ff g_ . Q about one OPM,(decada per minute) on the intermediate range. He stopped at 10" amps and recorded critical data per the reactor start up procedure. When he started withdrawing rods. again, he continued with a withdrawal rate of about one DPM (two decades on the inter- ,

mediate range represents 0% to 100% F.P.). When the point of sensible I

heat.was reached, the rate of heat increase cnd resultant swell was too fast for the pressurizer to correct and the reactor tripped on high RCS pressure. The heatup rate did not exceed TS limit and the maximum RCS pressure during the transient was 2294 psig.

In both trip indicents, the Reactor Protection System properly tripped the reactor upon detection of the applicable signals mentioned previcusly and support systems appeared to function properly. The inspector will follow the licensee's ongoing in-station analysis of the j two reactor trips. (

b. Oconee Unit I telpped from 85% full power on February 2,1981, at 2:55 1 p.m. The initiating event was a turbine trip caused by loss of excita- I tien to the generator field. At the time of the trip, control operators were adjusting the Volt Amperes Reactive (VAR) on Unit 1 generator. Subsequent investigation discovered a faulty potentiometer in the voltage adjustment regulating control switch. This caused the VAR's to decrease to the point where the generator excitation was lost.

The reactor trip was an anticipatory trip due to the turbine trip. The unit response was nomal, requiring no manual or unusual operator action to recover.

Item (7) of 10 CFR 50.72(a) requires that events of this type be reported to the NRC Operations Center as soon as possible and in all cases within one hour of the occurrence. A review of the record revealed that the licensee did not report the event to the NRC Operations Center as required. The resident inspector and Region 11 j personnel were aware of the event. 1 The failure to report the event within the hour to the NRC Operations Center is considered to be a violation of 10 CFR 50.72(a)(7) and applies to Unit 1(269/81-04-01).

12. Loss of System Status on Unit 1 j At 1:30 p.m. on February 24, a rapid decrease in pressurizer level was noted when the "B" LPI pump was started to initiate decay heat removal. The pump was immediately secured. The unit was in a shutdown condition and a cool- i down for maintenance work on the RCS was in progress. Subsequent investi- l gation revealed that Lp-42, LPI recirculation isclation valve to the Berated  !

Water Storage Tank (BWST), a nomally shut valve, was open. This caused I flow from the discharge of the "B" LPI pump to be diverted from the RCS to the BWST thus decreasing the pressurizer level. It was later discovered  ;

that the Control Room Operator on the previous shift had requested auxiliary '

operators to open LP-42 when he intended to have HP-42 opened to increase 1 l

' 11 letdown from the primary. HP-42 was then opened and LP-42 shut and a normal cooldown commenced. All of the primary coolant diverted from the RCS was accounted for.

Inspectors reviewed procedures 0P/1/V1102/10, Contro111'ng Procedure for Unit Shutdown, OP/1/A/1104/02, t.PI System and Operation and OP/1/A/1104/04, HPI $ystem Operation and determined that the process of increasing RCS letdown flow by bypassing the letdown orifice by opening HP-42 or LP-42 was not addressed in these procedures.

7tomoval and Restoration of Station Equipment, Procedure OP/0/A/1102/06, providet the methods used to remove from service or change from procedure designated status, station equipment not covered by other operating procedures.

Inspectors found no evidence that a Removal and Restoration Procedure had been initiated for either valve on February 23. This is a f ailure to follow proceduN OP/0/A/1102/06 and constitutes a violu. ion of Station Technical Specification 6.1.4a that resulted in a loss of systes status as required by 10 CFR 50 appendix B Criteria XIV, Inspection, Tests and Operating Status.

This is a violation and applies to Unit 1 (269/81-04-02).

13. Radiological Survey The inspector, on a continual basis, conducts radiation surveys of selected portions of the auxiliary and turbine buildings. The results of two such surveys are detailed below.
a. On Febraary 9,1981, at approximately 2:30 p.s.. while performing a routine plant tour and radiation survey, the inspector detected that a 4 i

janitor's sink located in the Auxiliary Building Room 357 was contami-nated to the point of reading approximately 20 er/hr on contact. The sink nor the room were posted as being contaminated. The inspector f amediately notified a Health Physics Wpres2ntative who subsequently took corrective action. 3 10 CFR 20.201 requires that radiological surveys be performed as necessary for the licensee to comply with regulatory requiremen*.5. 10 CFR 20.203 further requires each radiation area be conspicuously pested and that any additional applicable information appropriate in aiding fredividuals in einimizing exposure to radiation or radioactive materials be provided.

Contrary to the requirements of 10 CFR 20.201 the licensee did not adequately survey the aus111ary building, room 357, in order to l properly post the area for the purpose of personnel safety pursuant to 10 CHL 20.203. This is a violation and applies to Unit 3 (287/81 l 02).

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b. On or about February 6,1981, during a routine plant tour and radiation survey, the inspector det' acted five sealed wooden boxes containing radioactive waste, which were reading between 3 and 10 mr on contact.

The boxes were neither labeled or roped off.

Licensee procedure HP/0/B/1000/09, procedure for Removal of Items From RCZ's or RCA's, requires in part that the items be surveyed and appro-priately tagged or labeled. ,

Contrary to the reuqirements of the' applicable procedure and Technical l Specification 6.4 which requires the use of such procedure, the five i wooden containers were not labeled or tagged.

This is a violation and applies to Unit 1(269/81-04-0'). s In out letter of January 20, 1981, which transmitted Inspection Report 50-269/80-31, 50-270/80-27 and 50-287/80-24, a violation of similar nature was identified in Appendix B, item B.

14. primary Containment Integrated Leak Rate Test The inspector reviewed surveillance activities to determine that the primary containment integrated leak rate test (ILRT) was performed in accordance '

with appropraite sections of Technical Specification 4.4; pT/0/A/150/3, ,

Reactor Building Integrated Leak Rate Test Procedure; Appendix J to 10 CFR ,,

l 50, and ANSI N45.4 The inspection was a coordinated effort involving

Resident Inspectors and Region II specialists. Selected sampling of the licensee's activities which were inspected included (1) review of PT/0/A/150/3 to verify that the procedure was approved and conformed to .

Technical Specifications; (2) observation of test performance to determine that test prerequisites were completed, special equipment installed and calibrated,.approprista data were recorded and analyzed; and (3) preliminary evaluation of leakage rate test results to verify that leak rate limits were met. Pertinent aspects of the test are discussed in the following para-graphs.

am General Observations .

The inspectors witnessed or reviewed portions of the test preparation, containment pressurization, temperature stabilization and data '

processing in the period February 13-18, 1981. The following items were inspected:

(1) The test was conducted in accordance with an approved procedure I maintained at the test control center. Changes to the procedurt were decaented and approved as required.

(2) Selected test prerequisites were verified. ,

(3) plant systems required to maintain test control were in operation.

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l (4) Calibration and use of special instrumentation was verified. l (5) Venting and draining of specific systems were verified.

j (6) Data required for performance of the ILRT calculations were recorded at 5' minute intervals.

(7) Problems encountered during the test were described in the test event log. -

(8) Pressurized gas sources were reveiwed for proper isolation and venting to preclude in-leakage or interference of out-leakage through containment isolation valves.

b. system venting and Draining During the review of the revised test procedure pT/0/A/150/3, the inspector found that the instructions included action step sign-offs or double verification of each system drained. The problems with pipe cap removal on vent and drain lines (see IE Rpt. 50-269/80-06, 50-270/80-16) were adequately addressed by the incorporation of sign-offs to verify each cap removed. The inspector verified the adequacy of selected system line-ups by use of system diagrams followed by a visual inspection of valve positions and tags on system inside the Reactor Building. Of the fif teen penetration line-ups insp. '.ted, all line-up and vent caps were as specified.
c. Testing Problems A brief chronology of significant events and problems encountered during the course of testing are listed and discussed below:

2/14/81 2130 Containment pressurization commenced.

2/15/81 2200 Building pressure 31 psig, the stabilization period comenced.

2/16/81 0245 Run for the ILRT calculations commenced.

2/16/81 1330 ILRT terminated. Ltm=0.1085 VT%/ day ,

2/16/81 1600 Supplemental verification test with imposed leak rate of 7.107 SCFM commenced.

2/16/81 2300 Supplemental test complete. The verification leak rate was 0.2258 VT%/ day. The lowest acceptable value is 0.2405 WT%/ day. Results were unsatisf actory.

2/16/81 2325 The second verification test was started using

'7 14 a differenct flow instrument for the imposed leak.

1120 Second verification secured. Leakage did 2/17/81 not fall into the acceptance limits of the ILRT. It was suspected actual building laakage had decreased. A second ILRT data run was commenced.

2/17/81 1300 MRC Region II was informed of the testing problems.

2/17/81 2300 The second 10 hour1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br /> ILRT data run was terminated. Lta=0.0625 WTK/ day. Comparison of the LTM for the two ILRT indicated a significant change in leakage therefore a third verification test was performed to dispel doubts as to the adequacy of test instrumentati n 2/18/81 0020 The 5 hour5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> vertFcation test commenced.

2/18/81 0520 The verification test was terminated. The resultr, were considered satisfactory by the licensee.

2/18/81 2030 The Reactor Building was depressurized and inspected.

The second IUti was required as a result of a large decrease in the building leakage rate that invalidated the subsequent verification test. This was attributed the seating of the large butterfly type valves in the Reactor Building Purge Systes and an insufficient stab 11tation priod at the test pressure.

The flow meters used to esasure the rate of the imposed leak for the verification test became suspect when the results of the test were unsatisfactory. When the turbine vane ficaneter (SM1051C) and a retometer instrument (SU7004-39848) wsre both corinected to the same flow source a conflict in measured output resulted. The. retome ter indicated a rate of ISCFA lower than the turbine flowmeter for the 75CFM source. The licensee opted to use the rotometer for further testing based on the dependability of that instrument and substantiate that decision by having both flow instruments calibrated.

Final analysis of the leak rate data, utilizing the results of the calibration data of the flowmeters used in verification testing, will be performed by the licensee and will be reported The in the test report to inspectors pre-the Office of Nuclear Reactor Regulation (NRR).

liminary review indicated that the calculated leakage rate was less than the 0.75 LT allowable.

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Of the areas inspected, no violations were noted.

35. IEB 80 Valcor Solenoids The corrective actions required by IEB 80-23 as addressed in NRC inspection I report 50-269/80-38, 50-270/80-35 and 50-287/80-32 for deficiencies in Valcor solenoids in the Emergency Feedwater System was completed February 27. for Units 1, 2 and 3. Inspectors verified by direct observa-tion that the sueject fuses that would prevent a failed solenoid from tripping the entire bus are installed. Inspector review of the instrument modification package NSM 17.10 revealed that the fuses were schematically located as per negotiations completed on Occember 5,1980, with the licensee ,

and IE:HQ. Opers. tors continue to verify daily the continuity of power to )

the control solenoids from the control room. Licensee long term plans specify replacement of Valcor solenoids with another design that would meet )

current environmental qualifications.

This completes the corrective actions required by this bulletin.

16. Licensee Corrective Actions l Reactor Building Spray (RBS) Pump Impeller Locking Devices The licensee has performed the corrective repairs to the Unit 1 RBS Pumps specified i letter report to the NRC dated January 29, 1981. The condition of loose impeller locking devices was previously addressed in IEC 79-19 and IE Inspection Report 50-287/80-02. The licensee and the pump vendor completed design details of the improved locking assembly and the licensee l installed the modified device on the Unit 3 RBS Pumps during the current 1 refueling outage.

Unit 1 RBS pumps were inspected during an outage begun on February 8, for  ;

OTSG tube repairs. Inspection revealed that the 1A RMP Fump locking device '

renuired less than the 'pecified torque to loosen the capscrew for removal aithough it was not fond loose. The IB Pump was found satisfactory. The deficient locking devites were modified at that time.

As documented in the letter report, the Unit 2 RBS pumps will be inspected on the next outage of greater than two weeks.

Reactor Building Electrical Penetration Degradation Additional surveillance requirements and penetration pressurization specified as corrective action in R0-270/81-02 for a degraded Unit 2 electrical penetration has been verified through direct observation by Resident Inspectors. ]

l Corrective action is the result of the February 11, discovery that penetra-l tion EMV-2 failed to hold the 60 sig overpressure of SF6 gas used as a 4 dielectric _ Inspectors witnessed licensee leak testing of the subject l penetration to determine which or both of the possible barriers had failed.

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The test indicated that the Reactor Building side of the penetration leaked and the outer barrier was intact - no sign of leakage from the soap bubble test performed.

The licensee has initiated a program of purging the penetration daily to prevent arcing and monitoring radiation levels in the proximity of the penetration to alert shift personnel of possible out leakage from the Reactor Building. Inspectors have verified these measures by review of logs of daily inspections and presence of operating radiation monitoring equip-ment at the penetration.

Repair of the interior bushing was not possible due to activity levels inside the containment during reactor operation. The licensee performed a safety evaluatfon as required by 10 CFR 50.59 and determined that operatior, with only a single containment barrier was not an unreviewed safety ques-tion. Inspectors will continue to periodically monitor the penetration until it is repaired or replaced during the next available outage.

17. Steam Generator Tube Plugging On December 26, 1980, reactor coolant sample results on Oconee Unit 1 indicated an apparent tube leak of approximately 0.12 gpm. A combination of power reductions and continual leak calculations allowed power operation to continue through February 6,1981, when the unit was shut down to repair the tube leak.

Historically at Oconee, failed steam generator tubes have been located by filling the steam generator shell above the upper tube sheet, pressurizing the shell, and searching for water leaking from the failed tubes through the primary side lower manway. Failed tubes may also be located by pressurizing the drained shell, with a gas, filling the primary side of the generator to approximately two inches above the upper tube sheet, and searching for bubbles coming from the failed tubes with a TV camera. This second technique was originally employed by Babcock and Wilcox' and the Crystal River Plant but has subsequently proven ef fective on small leaks both at Arkansas Nuclear One and during this outage at Oconee.

The failed steam generator tube, 78-2 in generator A, was easily located and subsequently plugged. Due to the tube's location, one row away from the lane, it was also stabilized. .

Steam generator tube stabilization is a process in which a rod is affixed inside the feiled tube to prevent the tube from being expelled from the generator 11. the event of a double ended circumferential shear of a section of the tube.

The administrative and technical mechanics of the tube plugging effort were monitored throughout the evolution with no areas of concern.

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18. RB Sump Level Instrumentation - Units 1, 2 and 3 i

Water leakage inside the reactor building is collected in the normal sump and the emergency sump. The RB normal sump has a range of 0 to 30 inches, with a Statalarm at 15 inches and a computer alarm at 22 inches. Level is indicated and recorded in the control room and is recorded by the plant computer every five minut6s. ,

The emergency surrp nas a range of 0 to 10 feet with a computer alarm at 4 i feet, j The surveillance procedures for these instruments and the data from the most recent calibrations and tests were reviewed. The procedures were satis-factory for calibration and functional testing and the data and test results met the acceptance criteria. ,

Technical Specification 4.1.1 requires calibration of the cmergency sump at a refueling frequency. The normal sump instrumentation is not included in the Technical Specification, but is also done on a tsfueling frequency. j The test procedures and dates last performed are as follows DATE Procedure Unit 1 Unit 2 Unit 3 1 IP/0/A/203/IE T/473I5 11/12/80 12/19/80 l IP/0/B/233/3 7/8/80 11/12/80 12/19/80 l IP/0/A/203/IE RB Emergency Sump Level Instrument Calibration  ;

IP/0/9/233/3 RB Normal Sump Level Instrument Calibration  !

Within the areas inspected, no violations were found. 4 19 Reactor Building Air Temperature 4 l

On September 5,1960, Unit 3 was shutdown to repair a Reactor Protection I System (RPS) pressure transmitter. An attempt to repair the RPS pressure transmitter during reactor operation could not be complettd due N an '

ambient temperature of 130'F in the reactor building where the transmitter ,

1 is located. ,

Questions were raised concerning the operative temperature limit for the RPS transmitters and the ramifications of an elevated containment temperature on containment pressure following a LOCA.

A review of vendor supplied ecuipment specifications on the RPS transmitters

  • reveals an operative temperature bandwidth of -20'F to 160'F which effectively alleviates immediate concern over equipment environmental qualification.

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18 Moreovsr, Inspection and Enforcement Bulletin IEB-79-018, September 30, 1980 and Order For Modification of Licenses concerning Environmental Qualif t-cation of Safety-Related Electrical Equipment, October 24, 1980, further address the area of concern.

The licensee performed a computer analysis to determine the effect reactor building air temperature has on post LOCA building pressure. Examinations of the analyses reveals that the original containment pressure analysis for the design basis LOCA event assumed a nominal value of 110*F for the initial AB temperature and is reported in FSAR Section 14.2.2.3.5. The analysis was subsequently revised and reported in FSAR Supplement 13. Current analysis indicates the peak accident pressure appears not to be significantly influenced by initial RB air temperature. Any sr.all sensitivity appears conservative with respect to the maximum RB pressure when the actual temperature is higher than the assumed temperature. This behavior is apparently cum to the fact that the higher initial temperature dictates a lower mass of containment air and hence results in a slightly lower peak accident pressure.

Based on the above analysis and ongoing station modifications designed to 1 lower reactor building operating temperatures, immediate concerns are alleviated.

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