Text

Ack Which Requested Temporary Waiver of Compliance from TS 3.0.3, Lco
	ML20078M647
Person / Time
Site:	Brunswick
Issue date:	04/22/1992
From:	Ebneter S; NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:	Watson R; CAROLINA POWER & LIGHT CO.
Shared Package
ML20078M603	List: ML20078M647; ML20078M696; ML20079R505; ML20079R685; ML20079R923;
References
	FOIA-94-167 NUDOCS 9502140208
	Download: ML20078M647 (4)
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NUCLEAR REGULATORY COMMISSION-7 7*

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ATLANTA, GEORGI A 30323 geR "" ~ 1992 i

Docket Nos. 50-325, 50-324 License Nos. DPR-71, DPR-62 Carolina Power and Light Company ATTN: Mr. R. A. Watson Senior Vice President Nuclear Generation P. O. Box 1551 Raleigh, NC 27602 Gentlemen:

SUBJECT:

TEMPORARY WAIVER OF r,0MPLIANCE FOR BRUNSWICK UNITS 1 AND 2 This letter acknowledges yocr letter dated April 21, 1992, requesting a 1

Temporary Waiver of Compliance from Technical Specification (TS) 3.0.3 1

" Limiting Conditions for Operations".

This TS requires that in the event a Limiting Condition for Operations cannot be satisfied, the unit (s) shall be 4

placed in at least Hot Shutdown within six hours and in Cold Shutdown within the following 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months .

Your letter requested an extension of the six-hour limit for the two units from 1020 to 1600 hours0.0185 days 0.444 hours 0.00265 weeks 6.088e-4 months on April 21, 1992, to allow an orderly and sequential shutdown of both units.

Shutdown of both units was required since you determined that the Diesel Generator Building does not meet minimum seismic requirements due to improperly installed and/or missing anchor bolts in concrete walls.

The technical issues and the extent of the waiver were discussed during a telephone call on April 21, 1992, among J. Nilhoan, ar.d L. Reyes of Region II; G. Lainas of NRR; and J. Spencer of CP&L. Specifically as discussed in your request, the Plant Nuclear Safety Committee would review and approve this request. Verbal approval of this temporary waiver was granted by Region II based on the determination that is considered safer to minimize the complexity of evolutions for the control room staff to place one unit at a time in a transient situation.

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In addition to the above, your letter requested that the 30-hour Cold Shutdown requirement for Unit 1 be extended from 1620 April 22,1992, to 0800 April 23, 1992 to allow for identification of drywell leakage sources. Since you located the source of drywell leakage promptly after achieving Hot Shutdown and Cold Shutdown for Unit I was attained at 10:30 a.m. on April 22, 1992, the requested waiver for the Unit 1 Cold Shutdown requirement is not necessary.

Sincerely at Regional Administrator cc:

(See page 2) 9502140208 940609 PDR FOIA s,, RICCIO94-167 PDR

APR 22 iss2 Carolina Power and Light Company 2

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cc:

R. B. Richey-Vice President Brunswick Nuclear Project P. O. Box 10429 Southport, NC 28461 J. W. Spencer Plant General Manager Brunswick Steam Electric Plant P. O. Box 10429 Southport, NC 28461 H. Ray Starling Manager - Legal Departmenr.

Carolina Power and Light Co.

P. O. Box 1551 Raleigh, NC 27602 Kelly Holden Board of Comissioners P.. O. Box 249-Bolivia, NC 28422 Chrys Baggett State Clearinghouse Budget and Management 116 West Jones Street i

Raleigh, NC 27603 Dayne H. Brown, Director Division of Radiation Protection N. C. Department of Environment, Health & Natural Resources P. O. Box 27687 Raleigh, NC 27611-7687 H. A. Cole Special Deputy Attorney General State of North Carolina P. O. Box 629 Raleigh, NC 27602 Rcbert P. Gruber Executive Director Public Staff - NCUC P. O. Box 29520 Raleigh, NC 27626-0520

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7 previously documented data that lacked supporting calculations to determine acceptability.

The events and circumstances of this item are similar to the problem associated with the diesel generator building walls addressed in Inspection Report 92-10, which is currently under review and consideration for escalated enforcement.

b.

During their review of the seismic integrity of diesel generator building walls on April 20, corporate engineering (NED) discovered that the poured concrete walls between diesel generator cubicles were not attached to the floor slabs and overhead beams with rebar, as previously believed.

Instead, these walls were found to be held in place by 4 x 4 inch angle steel and cinch anchors.

An initial inspection of these anchors found that some bolts were missing.

The worst case, as determined by visual inspection, appeared to be wall 9D-1 between the DG No. 1 cubicle and the E-6 switchgear room.

Visual and UT inspection determined that inadequate bolts were installed to support the wall during a seismic event.

The licensee declared DG No. 1 and switchgear E6 inoperable and entered the appropriate TS LCO at 2:10 a.m.,

on April 21.

At 4:20 a.m.,

technical support (onsite) engineering determined that the normal power feeder to switchgear E-5 also passed through this wall.

A failure of the wall could result in a loss of power to E-5.

The above condition placed the plant in TS 3.0.3 and required that both units be placed in hot i

shutdown within six hours.

l A power reduction was started at 4:48 a.m., and power was reduced to 30% at approximately 7:00 a.m.

The licensee then contacted Region II and NRR, requesting that a waiver of compliance be granted to permit emergent repairs on the walls while the units remained at approximately 30% power.

At that time, temporary repairs were underway and expected to be completed in about four hours.

This waiver was granted at 9:00 a.m.,

with the stipulntion that repairs and subsequent examination of the remaining walls be completed expeditiously.

The licensee confirmed that if additional discrepancies were discovered, the prescribed TS action would be taken.

Based on the above, the licensee started repairs on the 9D wall.

The repairs were completed on the North side of the wall at approximately 11:00 a.m.

Further evaluation by NED determined that an apparent pattern of false anchor installations existed in this and other

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walls; infoming that there were only a sufficient number of_ anchors to support the angle steel, but not j

the walls.

With this apparent 1sek of confidence in anchor installations, the licensee made a conservative decision to shutdown both units consnencing at noon on April 21.

t The licensee requested that they be granted time to

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perform a soft shutdown, one unit at a time.

Region II l

and NRR agreed to this waiver request.

The inspectors observed the shutdown and noted that it was controlled l

and orderly.

Both units achieved hot shutdown on April 21 and cold-shutdown on April 22.

While the units are down, a thorough inspection will be conducted and rework will be performed on all identified discrepant installations.

The previously scheduled 30 day outage on Unit 2 was entered early.

The work previously scheduled for the June PT outage on

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Unit 1 will also be performed during the current outage.

5.

Evaluation of Licensee Self Assessment (40500) a.

Onsite Review Committee The inspectors attended selected PNSC meetin' conducted during the period.

The inspectors arified that the meetings were conducted in accordance with Technical Specification requirements regarding quorum membership, review process, frequency and personnel j

qualifications.

Meeting minutes were reviewed to i

confirm that decisions and reconsnandations were reflected in the minutes and followup of corrective actions was completed.

There were no-concerns identified relative to the PNSC meetings attended.

The resolution of safety issues presented during these meetings was considered to be acceptable, b.

Nuclear Assessment Department On April 28, at the Plan-of-the-Day Meeting, the inspector noted that the manager of Project Assessment (NAD) onsite led a discussion relating to Technical Support and NAD inspection of plant areas to determine material condition.

Based on the above, it appeared that NAD was planning to perform line functions.

The planned inspection was to be performed by a team composed of engineers, with NAD personnel assisting.

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A Docket No. 50-280 License No. DPR-32 Virginia Electric and Power Company ATTN: Mr. W. L. Stewart Senior Vice President - Nuclear 5000 Dominion. Boulevard Glen Allen VA 23060 Gentlemen:

SUBJECT:

TEMPORARY WAIVER OF COMPLIANCE FOR SURRY UNIT 1 DOCKET NO. 50-280 This letter confirms the telephone conversation between Mr. J. P. O'Hanlon of your staff and Mr. Luis A. Reyes of my staff on April 24, 1992, granting a regional Waiver of Compliance for your Surry Unit 1 Nuclear Power Station facility.

The waiver was granted to Technical Specification (TS) 4.17.C.6 for one time only to eliminate additional snubber testing of mechanical snubbers.

During the current outage, three snubbers did not meet the acceptance criteria specified in TS 4.17.E.

The granting of the waiver was based on the premise that the three snubbers in question are fully operable and that acceptance criteria specific in TS 4.17.E was not applicable to the type mechanical snubber installed at Surry.

I understand that you plan to submit a TS amend-ment to correct this technicality.

The technical issues and your justification are documented in your followup letter (Serial No.92-291) dated April 27, 1992, which was received by electronic transmission on April 27, 1992.

Prior to granting the temporary Waiver of Compliance, the technical issues and the extent of the waiver were reviewed.

They were discussed in a telephone call among L. Reyes, E. Merschoff, M. Sinkule, and S. Tingen of Region II; G. Lainas, B. Buckley, H. Silver and H. Shaw of NRR; and M. Bowling and A. Price of Virginia Power.

This waiver was granted for one time only for TS 4.17.C.6.

Sincerely,

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t D. Ebneter egional Administrator

Enclosure:

Virginia Power Letter (Serial No.92-291) dtd April 27, 1992 cc w/ encl: See page 2 p

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APR 271992

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cc w/ encl:

E. W. Harrell Attorney General Vice President - Nuclear Services Supreme Court Building Virginia Electric & Power Company 101 North 8th Street 5000 Dominion Boulevard Richmond, VA 23219 Glen Allen, VA 23060 J. P. O'Hanlon Vice President - Nuclear Operations Virginia Electric & Power Company 5000 Dominion Boulevard Glen Allen, VA 23060 M. R. Kansler Station Manager Surry Power Station P. O. Box 315 Surry, VA 23883 M. L. Bowling, Jr., Manager Nuclear Licensing Virginia Electric & Power Co.

5000 Dominion Boulevard Glen Allen. VA 23060 Sherlock Holmes, Chainnan Board of Supervisors of Surry County Surry County Courthouse Surry, VA 23683 Dr. W. T. Lough Virginia State Corporation Commission Division of Energy Regulation P. O. Box 1197 Richmond, VA 23209 Michael W. Maupin Hunton and Williams P. O. Box 1535 Richmond, VA 23212 C. M. G. Buttery, M.D., M.P.H.

State Health Commissioner Office of the Comissioner Virginia Department of Health P. O. Box 2448 Richmond, VA 23218 l

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ENCLOSURE VtaatWIA Er.acfmac Awa Powan Coumry Rscuwows,V:merssa soses April 27,1992 Unhed States Nuoleer Reguielory Commission Serial No.82-291 Anantion: Document Control Desk NLAPMTS R5 Washington, D. C. 30555 Deciset No.

80 230 usense No.

DPR-at Gendemen:

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m sarnic asa powen 7==Auv At.a tRY pawna ATAT ON UMrf 1 nami enn==at nur== "a FUNCTIONAL TESTosa agoutamaassryg wa vna ap m.m em., =

Functional toallnp of mechenloal enutters wee performed during the current Unit 1 refusing outage in encontence wth the requirernents of Technies! 8peelReedon 4.17.

The comp 6sted funadonal test remute were compared to the ecooptance citeerta es defined in Season 4.17.E. Three of the tested mechanical anubbere eId not mest the Technical Specifloation requirement of less than a 50% inorosse in the drog force sinos the last funadonal test. For each Ishwe to most the requiremente of Technical 8pealleeden 4.17.E. Technical Apaansa=#aa 4.17.0.8 requires en ed Stonal 10% of thattype of snuttertotested.

The maximum 50% lacrosse in drog since the previous funcilonel test was a vand maanp*=gce criterion for the original mechanical enubbers (Peelec Scientlec et Surty. However, those snubbers have been repieced with snubbers)insteRed (Anchor Dersne) of a elflerent design. The vendor has provided their technical poellion that a 50% incremos in drog le not Indiceive of incipient failure. The drag test resulle are highly variable and, therefore, cannot be used to indicate a trend in snubber i

performenos.

it has been concluded that the most approprinde test le the one empkr mi by where the measured runnin0 dree force le compared to an sonoptance orserion, is based on Emlung dre0 to 3% of the maximum anubber doelen load An enginsedne evaluation has t>een performed and the enubbers have been determined to be tuey operable and cepeble of performing their intended function. However, applying the 50% increase in drog force criterion, verbatim compilance with the Techn' cal Specification requirements would require additional functional testing of a 10%

sample of the mochenical enubbers. These addrconal teste to satisfy an inappropnete criterion serve no purpose and would contribute to increased mMhnal exposure.

In an April 24, 1992 conference onll between Virginia Power and the NRC, we requested and received vertzel approval for a one time waiver from the 10% eddtional luretional testing requirements of Technical Spedfication 4.17.C.6 for mechanical l

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ENCLOSURE 2

enubbers. This squest and its approval mese bened on the scooptance erleonen (60% inomees in dag fofee) sisted in Technical 4.17.E.1.a and the above acoussion of enginosnns evolustione for of the enubben ellected by the oppsondon of this arterion. A Technical change wl4 he developed and autumated to medfy the tunadonal nie for machenleet i

enumbes to esabash appspresse enoeptenos creeds.

in adddon, we have reviewed tout resuhe from previous Ancher Dartne mechanical i

anubber functional teste and idonelted several cease where torcelnerossed by more than 50% from the previous test. These cases have reviewed and evaluated by Engineering and the anubbers were determined to be fuly operelde.

SAFETY IMPACT AND POTENTIAL CONSEQUENCES The engineering evaluatione of the subloot enubbers have determined that the enuhters are key capable of performing their intended sunadon, operanon of the enubbme under nooident condmone ewnsine erg Theresore, no advwee coneoguences reeut from eliminating the adenenal mechanical enubber taseng.

asNIFICANTHAZARDS CONSIDimATION The proposed welver of the adddonal machenlosl anubber inspespon requirements in Technical speamasson 4.17.C.8 lor this inspeadon interval does not resub in a alonmose hesense eeneuwason.

1.

The proposed waiver does not increase thefrobetnety or consequenose of an accident evalueled. The existing Technical Spedncesion rW;n.;

of less t increase in dnne fosos does not provide an appropriate indiosilon of operatWilly for the Anchor Darung mechanical snuthore lastated at Surry. The subjost snuttore have been evetussed and densmened to be her apemble and cepehto of their intended tunadon. Theretore, level it to unnenenemerto poders the knesonal topavidethesame of assurance derenutteropemidhy. Thus,the erconsequeneseof an sooldent wlN not ehenge due to this weher of machenical enutter funcWonal tealing rW x:.:

2.

The proposed waiver wiu not create the poseltety of a new or different Idnd of 2

aooidem from any accidem previously evawad Tne walvor elminates the need for addtional functional testing of machenical snubbers and does not change the operation or the ability of the anubbers to perform their latended function.

Thorotore, new sooident precursore er accident types are not being generated.

3 The proposed waiver does not involve a reduction in a margin of safety. The level of equipment (enuteore) operability le not bein0 reduced. The completed snubber functional tests have provloed the required assurance that the mechanical snubbers installed at Surry will perform their intended function, as required. Thus, no margin of safety is being reduced.

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6 ENCLOSURE 3

ENVIRONMENTAL CONSEQUENCES This waiver wlE not dange the types of any emuente that iney be reisesed oNeto, nor create a a nifloant increase m indvidual or cumulosive occupadonal radiadon expoews.

enuhbere remain capable of pertonning theirintended funceon.

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The weher of opeptance and the adM safely evoluution were miesed by tw Station Nuclear Safety and Operating Committee prior to pient conelons (i.e., esotodin0 2007 in the primary system). It has been rmined that no unreviewed safety question or significant naasnse consideresion eulege.

Verytruly yours.

Senior Vlos Preeksent-Nuoiser oc:

U. S. Nuclear Regulatory Commiselon Region il 101 Medetta Street,N. W.

Sube 2000 Allanta, Georgia $$$2S w.M.W.Bennch NRO Senior Resident inspedor Suny Power Staten L

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~ Docket Nos. ~ 50-280, 50-281 License Nos. DPR-32, DPR-37 Virginia Electric and Power Company ATTN: Mr. W. L. Stewart Senior Vice President - Nuclear 5000 Dominion Boulevard Glen Allen, VA 23060 2

i Gentlemen.

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SUBJECT:

NRC INSPECTION REPORT NOS 50-280/92-11 AND 50-281/92-11 This refers to the Nuclear Regulatory Commission (NRC) inspection conducted by Mr. M. W. Branch of this office on April 5 through May 9,1992. The inspection included a review of activities authorized for your Surry facility.

At the conclusion of the inspection, the findings were discussed with those members of i

your staff identified in the enclosed inspection report.

Areas examined during the inspection are identified in the report. Within these areas, the inspection consisted of selective examinations of procedures and representative records, interviews with personnel, and observation of activities in progress.

1 i

The enclosed Inspection Report -identifies activities that violated NRC requirements that will not be subject to enforcement action because the licensee's efforts in identifying and/or correcting the violation meet the criteria specified in Section VII.B of the Enforcement Policy.

In accordance with 10 CFR 2.790 of the NRC's " Rules of Practice", a copy of this letter and its enclosures will be placed in the NRC Public Document Room.

Should you have any questions concerning this letter, please contact us.

Sincerely, wY zle.,

Marvin V. Sinkule, Chief Reactor Projects Branch 2 Division of Reactor Projects

Enclosure:

NRC Inspection Report cc w/ encl:

See page 2 l

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Virginia Electric & Power 2

JUN 081992 c-Company cc w/ enc 1 cont'd:

E. W. Harrell Vice President Nuclear Services Virginia Electric & Power Company 5000 Dominion Boulevard Glen Allen, VA 23060 J. P. O'Hanlon Vice President - Nuclear Operations Virginia Electric & Power Company 5000 Dominion Boulevard Glen Allen,-VA 23060 M. R. Kansler Station Manager Surry Power Station P. O. Box 315 Surry, VA 23883 M. L. ; Bowling, Jr., Manager Nuclear Licensing Virginia Electric & Power Company 5000 Dominion Boulevard Glen Allen, VA 23060 Sherlock Holmes, Chairman i

Board of Supervisors of Surry County i

Surry County Courthouse Surry, VA 23683 Dr. W. T. Lough Virginia State Corporation Commission Division of Energy Regulation P. O. Box 1197 Richmond, VA 23209 Michael W. Maupin Hunton and Williams s

P. O. Box 1535 Richmond, VA 23212

'C. M. G. Buttery, M.D., M.P.H.

State Health Commissioner Office of the Commissioner Virginia Department of Health P. O. Box 2448 Richmond, VA 23218 Attorney General 101 North 8th Street Richmond, VA 23219

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see UNITED STATES i

NUCLEAR Re:ULATCRY COMMIS880N

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ATLANTA,OsOnG1A30333 Report Nos.:

50-280/92-11 and 50-281/92-11 Licensee: Virginia Electric and Power Company 5000 Dominion Boulevard Glen Allen, VA 23060 Docket Nos.:

50-280 and 50-281 License Nos.: DPR-32 and DPR-37 Facility Name: Surry 1 and 2 Inspection Conducted: April 5 through May 9, 1992 Inspectors: 4/2// h

.: 7 / M I s M. W.' preach, Senior Resident Inspector Date Signed h/J/ &

fff'fG 3 J. W. Tor g esident Inspector Da'te 5'igned -

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5. G. Twyer, Aes dent Inspector Irate sig ed Approved by: W

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7T" P.E.Fredrickson,SectionChiep Date Signed Division of Reactor Projects SUP9tARY Scope:

This routine resident inspection was conducted on site in the areas of operations, maintenance, surveillance, safety assessment'and quality verifica-tion, strike plans, and action on previous inspection items.

During the performance of this inspection, the resident inspectors conducted review of the licensee's backshift or weekend operations on April 5, 8, 12, 17, 18, and May 3, 1992.

Results:

In the operations area the following items were noted:

Operator performance during the two Unit I startups was considered excellent (paragraph 3.b).

Operator's response to the May 7 Unit I trip was good (paragraph 3.c).

A non-cited violation was identified as a result of a fire watch's inattentiveness to duties (paragraph 3.d).

6tS Y M t2 N N l [

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f In the maintenance / surveillance area, the following items were noted:

The lack of control of contractor maintenance activities resulted in a trip of Unit I and was considered a weakness (paragraph 3.c).

During the Integrated Leak rate Test, several minor weaknesses associated with procedural use and instructions occurred (paragraph 1

5.a).

In the Safety Assessment / Quality Verification area, the following items were noted:

The Unit I startup assessment adequately evaluated items for deferral and mode changes. Management involvement in this process was evident, and the startup assessment was effective in ensuring safe operation of the unit following the refueling outage (paragraph 6.a).

The Unit 1 post trip review was good and demonstrated a positive safety attitude (paragraph 6.b).

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I REPORT DETAILS 1.

Persons Contacted I

Licensoa Employees

R. Allen, Superintendent of Operations (Acting)

W. Benthall, Supervisor, Licensing

R. Bilyeu, Licensing Engineer

H. Blake, Superintendent of Site Services

R. Blount, Superini.endent of Station Procedures

D. Christian, Assistant Station Manager

J. Downs, Superintendent of Outage and Planning A. Flatcher, Assistant Superintendent of Engineering

R. Gwaltney, Superintendent of Maintenance D. Hart, Supervisor, Quality Assurance

M. Kansler, Station Manager A. Keagy, Superintendent of Materials

J. McCarthy, Assistant Station Manager (Actts)

J. McGinnis, Human Perfomance Evaluation Sa;ma Coordinator

J. O'Hanlon, Vice President - Nuclear, Corocrate A. Price, Assistant Station Manager R. F. Saunders, Asristant Vice President-Nuclear, Corporate

E. Smith, Site Quality Assurance Manager

T. Sowers, Superintendent of Engineering G. Woodzell, Senior Instructor NRC Personnel

M. Branch, Senior Resident Inspector

S. Tingen, Resident Inspector

J. York, Resident Inspector Accompanying NRC Inspector J.L. Shackelford, Reactor Inspector l

Attended exit interview.

Other licensee employees contacted included control room operators, shift technical advisors, shift supervisors and other plant personnel.

Acronyms and initialisms used throughout this report are listed in the last paragraph.

2.

Plant Status Unit I began the reporting period in a refueling outage.

The outay was completed on schedule and the unit was restarted on May 1.

After physics testing, the unit operated until the turbine trip / reactor trip on May 7.

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g, 2

The unit was restarted on the same day and was at 98.5% at the end of the inspection period.

Unit 2 began the reporting period in power operation.

The unit was at power at the end of the inspection period, day 143 of continuous operation.

3.

Operational Safety Verification (71707,42700)

The inspectors conducted frequent tours of the control room to verify proper staffing, operator attentiveness and adherence to approved procedures.

The inspectors attended plant status meetings and reviewed operator logs on a daily basis to verify operations safety and compliance with TSs and to maintain awareness of the overall operation of the facility. Instrumentation and ECCS lineups were periodically reviewed from control room indication to assess operability. Frequent plant tours were conducted to observe equipment status, fire protection programs, radiologi-cal work practices, plant security programs and housekeeping.

Deviation reports were' reviewed to assure that potential safety concerns were properly addressed and reported.

a.

Licensee 10 CFR 50.72 Reports On May 7, at 10:06 a.m. the licensee reported to the NRC that Unit I experienced a turbine trip / reactor trip from 785 power.

Contract maintenance personnel were attempting to stop an oil leak on the thrust bearing test valve. A nut on the bonnet of the test valve was loosened allowing oil to leak by the valve that resulted in thrust bearing high pressure, and subsequently a turbine trip. This event is further discussed in paragraph 3.c.

b.

Unit 1 Startup On May 3, the inspectors observed from the control room, the Unit 1 L

startup from 2% to 30% reactor power. Procedure 1-GOP-1.5, 2% reactor power to 255-30% reactor power, dated April 25, 1992 was used for this evolution.

Operator perfomance was excellent during the startup. Communications were good, procedures were followed, and evolutions were well coordinated.

Several times during the startup, just prior to commencing a difficult task, oprators would conduct a prejob briefing to ensure that all parties involved were aware of their duties.

The inspectors reviewed upgraded-procedure 1-G0P-1.5, which was used during the startup, and concluded that it was a quality product.

0betup was accomplished without requiring any changes to the proccdure and operators were able to easily adhere to its requirements.

The procedere, which was classified as " complex test" or " infrequently conducted", required senior operations management oversight in addition to the nomal shift supervisor oversight. This additional level of management involvement was an aid to the safe operation of the unit during the startup.

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With the exception of.the A FRV bypass valve, plant equipment operated satisfactorily. At approximately 155 power, SG i

feedwater control was transferred from manual to automatic mode.

During this evolution, operators were challenged when operation of the A FRV bypass valve became sluggish.

As a result, level in the A SG i

increased to 675. Operator action was taken before SG level reached i

75% which would have automatically tripped the unit. The A FRV bypass valve controller was replaced and the valve operated satisfactorily

)

thereafter.

Later in the startup, a rod control problem occurred which is discussed in paragraph 4.a.

i c.

Unit 1 May 7 turbine trip / reactor trip.

4 At 10:06 a.m. on May 7, Unit I experienced an automatic reactor trip from 78 percent power when the turbina was tripped during maintenance activities. A contractor employee was attempting to stop an oil leak i

on the thrust bearing trip test valve.

When the bonnet nut was loosened, the valve stem moved which allowed the valve to slightly i

open. Oil leakage past the valve allowed the sensing mechanism to see a thrust bearing high pressure condition that resulted in a turbine trip.

The work that was being performed was not controlled by any i

work order or procedure and the only worker instructions were to stop i

the oil leak. Procedure VPAP-801, Maintenance Program, dated December 31, 19g1 paragraph 6.18 covers the performance of maintenance by 3

outsids organizations. The performance objectives are to ensure that maintenance performed by outside organizations is controlled and contractor and other nonplant personnel are properly supervised and j

work under the same controls, procedures ' and standards as station maintenance personnel.

This failure to control maintenance being performed by an outside organization is identified as a weaknese.

e The operators response to the event was observed by the inspectors and good procedural adherence was noted. One problem was noted in that a procedure was not used. Operators were instructed by the operations superintendent to borat4 the reactor to ensure compliance w!th T',

3.12.A.4 for shutdown strgin. Whenever the reactor is subcritical, except for physics tests, the critical rod position, i.e., the rod l

position at which criticality would be achieved if the control rod assemblies were withdrawn in normal sequence with no other reactivity 1

changes, is required to be above the insertion limit for zero power.

The inspectors questioned the licensee as to why the E0P, 1-ES-0.1, Reactor Trip Response, did not contain instructions to borate for the conditions observed. At the end of the inspection period the licensee

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was evaluating the need to change this procedure.

The inspector observed that plant equipment responded well to the transient.

However, the inspectors did note that the TDAFW time response appeared to be slow. The licensee's review of post trip data determined that flow to the SGs from the TDAFW pump occurred 58 seconds after the low SG 1evel signal was received.

The licensee's post trip review team evaluated the as found time response of the TDAFW pump and found it to be acceptable. This was confirmed through r.

d 4

4 discussionswith the nuclear analysis group who indicated that 60 seconds was used in the accident analysis. The licensee will continue to evaluate the actual time response of the system dnce the 58 second-flow initiation does not provide much of a margin from the i

value used in the accident analysis.

i d.

Inattentive Fire Watch Each EDG room has a carbon dioxide fire suppression system which must be initiated manually if a fire occurs. Outside of each EDG room there is a panel that alarms if a fire occurs inside the room (red flashing light) and alarms if a fault occurs (yellow flashing light) in the carbon dioxide system electrical circuitry. On April 26, the No. 3 EDG carbon dioxide system panel yellow light began to flash on and off indicating a fault in the circuit.

In this condition, operators were unable to verify that the circuit was operable and a continuous fire watch was stationed in the No. 3 EDG room in accordance with TSs.

i On May 3, at approximately 5:00 p.m., the inspectors discovered that i

the fire watch stationed in the No. 3 EDG room was inattentive in that I

he was not monitoring for a fire. The inspectors immediately reported this to the assistant shift supervisor and the fire watch was replaced. Step 3.2.3.2 of SUADM-ADM-20, Special Processes Involving Ignition Sources, requires that fire watches look for fires and if one occurs, sound an alars and extinguish the fire if possible.

The failure to monitor for a fire in accordance with SUADM-ADM-201990 was identified as NCV 280,281/92-11-01, Failure of Fire to Follow i

Procedure. This NRC identified violation is not being cited because l

criteria specified in Section V.A of the NRC Enforcement Policy were j

satisfied.

Subsequent licensee investigation of the carbon-dioxide l

panel flashing light indicated that the fault did not effect the function of the system in that the system would have properly operated when manually initiated.

l e.

Temporary Waiver of Compliance j

i On April 24, the NRC granted a Temporary Waiver of Compliance to TS 4.17.C.6. The waiver applied to Unit I and was for one time use only.

During the RF0, three snubbers did not meet the acceptance criteria specified in TS 4.17.E and therefore, this required that additional snubbers be tested. Granting of this waiver eliminated the require-ment to test additional snubbers.

The granting of the waiver was based on the premise that the three snubbers in question were fully i

operable and that the acceptance criteria in TS 4.17.E was not applicable to the type of snubber installed at Surry. When discussing this issue, the licensee stated a TS amendment wor!J be submitted to correct this discrepancy.

Di. May 5, the NRC granted a Temporary Waiver of Compliance to TS I

3.12.C.3.

The waiver was for a one time use and applied to Unit 1 only.

Once on May 3 and twice on May 5 the rod urgent failure alarm

5 i

the unit is required to enter TS 3.12.C.3 which provides two hours for troubleshooting and repair prior to requiring that the unit be brought i

to hot shutdown in six hours. The urgent failures were diagnosed by the licensee as a circuitry problem in a cabinot of the control rod drive system. Granting of this waiver allowed additional time (up to 50 hours5.787037e-4 days 0.0139 hours 8.267196e-5 weeks 1.9025e-5 months ) to effect thorough troubleshooting and repairs.

The i

granting of the waiver was based on the fact tiat the affected control rod assemblies remain trippable (see paragraph 4.b for repair i

details).

Within the areas inspected, one NCV was identified.

4.

Maintenance Inspections (62703, 42700,)

l During the reporting period, the inspectors reviewed maintenance activities to assure compliance with the appropriate procedures.

The following maintenance activity was reviewed.

a.

Repair of Pressurizer Pressure Channel - Unit 1 On April 30, annunciator EH4, low pressurizer pressure / reactor trip, displayed an erratic indication in the control room.

The inspectors noted the annunciator and decided to follow the trouble shooting and repair.

Station deviation Report No. S-92-0797 was written and WO No. 3800126663 was used by the I&C technician to perform the work.

Two comparators were replaced and perodic test No.1-PT-2.4A (P r 457), Pressurizer Pressure Protection, dated February 20, 1992, was used to return the instrumentation to service.

Part of the mainte-nance was observed by the inspectors in the ESGR area and no discrep-ancies were noted.

7 b.

Repair of Unit 1 Power Cabinet 2AC On May 3, an annunciator alarm GA6, Rod Control Urgent Failure, was activated, indicating a problem in Unit I rod control cabinet 2AC.

The I&C personnel, after consulting with Westinghouse on the proper steps i.o use for trouble shooting the system, removed the failure detection cards, compared voltage readings between this cabinet and a second trouble free cabinet. No differences in voltage were noted and the cards were placed back into the cabinet.

The alarm was reset and the annunciator cleared.

Perodic test 1-PT-G.0, Control Rod Assembly Partial Movement, dated April 25, 1991, was used to return the system to service.

However, On May 5, at 5:38 am, the same annunciator, GA6, alarmed again.

The I&C technicians determined that one of the firing cards needed to be replaced.

First the annunciator alarm was cleared using the technique discussed previously.

The techni-cians were to use the DC hold bus to prevent the group C rods from dropping while replacing the firing card but a fuse was blown and trouble shooting had to be accomplished in this cabinet first (see par. 4.c).

Approximately 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months later, the

l 6

first (see par. 4.c).

Approximately 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months later, the annunciator came in a third time when the I&C group was repairing the DC hold cabinet.

This time, the alarm would not clear and the licensee decided to request the temporary waiver of compli-ance discussed in paragraph 3.e.

i The technicians replaced the firing card and then received a group C l

multiplex error which, after extensive troubleshooting, was cleared.

The inspectors were present when a telephone conference was held on May 6 between Westinghouse, station management, and.the I&C techni-t cians, during which a conclusion was reached that the problem had been solved. After repairs, the TS clock was exited within the time frame granted in the Temporary Waiver of Compliance.

c.

Repair of Unit 1 DC Hold Cabinet On May 5, while attempting to repair the problem with a rod control cabinet described in the previous paragraph, a problem with the DC hold cabinet was discovered (fuses were blowing).

The inspectors observed the I&C personnel methodically tr. king data and trouble shooting the problem.

The technicians use<J WO No. 3800126838 and t

procedure IMP-C-EPCR-46, Maintenance of Rod Control System, dated June i

26, 1989, to accomplish the task.

A b'down fase on one of the electrical phases supplying power to the r.abinet was diagnosed. The fuse was replaced and no further problems accurred. No problems were identified by the inspectors.

5.

Surveillance Inspections (61726,42700)

During the reporting period, the inspectors reviewed surveillance activities to assure compliance with the appropriate procedure and TS requirements.

The inspectors observed part of the Unit I type A containment test that was i

performed using procedure 1-NPT-CT-101, Reactor Containment Building Integrated Leak Rate Test ' Type A Containment Testing), dated April lo, 1992. This test was complead satisfactorily within TS limit. During the test, several procedural a.d administrative weaknesses were identified and and are indicated below:

Atmospheric pressure is needed to calculate the containment pressure.

The atmospheric pressure was not recorded in the procedure; however, the licensee was able to retrieve sufficient information from i

installed test equipment.

Atmospheric pressure is needed to calculate the containment pressure.

Test procedure does not specify that containment pressure must remain-above the calcuir? Y value of test pressure throughout the duration of the test (this it s irement was adhered to during the testing).

t l

1 7

Pen and ink changes were made to the test. procedure, based on discussions with the vendor, which modified required suction pressure and-discharge oil pressures on the dryer panel which is non-safety related.

Procedure VPAP-0502, Procedure Process Control, contains guidance which requires that a PAR be issued for this type of change.

These deficiencies were identified on deviation report No. S-92-0732. -

In general, the conduct of the test was good and the personnel involved.

with the test were knowledgeable.

The test was satisfactorily completed with acceptable results.

1 6.

Safety Assessment and Quality Verification (40500) i a.

Unit 1 Startup Assessment The inspectors reviewed the Unit 1 RF0 Startup Assessment.

The l

licensee does not have an administrative procedure that specifies startup assessment requirements, but one is being developed. Startup assessments are directed by the SNSOC and MRB, who identify what must be evaluated for a startup following a RFO. They also approve items that can be deferred until after startup or later. Examples of items l

evaluated prior to the Unit I startup were periodic or special tests, i

uncompleted DCPs and EWRs, insulation and scaffolding, deferred commitments, deferred corrective and preventive maintenance W0s, open station deviations,

JC0s, reactivity management

issues, PPRs, temporary power supplies, E0P and startup procedures, and post I

maintenance tests. The startup assessment also identifies items that t

must be completed prior to changing plant modes of operation.

Each department is required to identify the outstanding startup assessment items in their area and ensure that the items that cannot be deferred are completed as required.

The inspectors attended several startup assessment meetings, reviewed the completed Unit 1 RF0 Startuo Assessment, dated April 26,1992, and reviewed the deferred corresive maintenance work orders and open i

station deviations.

The inspectors concluded that the startup assessment adequately evaluated items for deferral and mode changes.

Management involvement in this process was evident, and the startup assessment was effective in ensuring safe operation of the unit following the RFO.

b.

Unit 1 Post Trip Review On May 7, the inspectors attended the post trip review for the Unit I automatic reactor trip, which occurred earlier in the day.

Prior to a unit restart, a post trip review is held to ensure that the cause of the trip was known and that the equipment operated satisfactorily i

during the transient.

The post trip review was performed in accor-l dance with SUADM-0-02, Post Trip Review, dated June 2, 1989. During the post trip review the cause of the trip was thoroughly discussed and understood. Also, sevecal minor equipment problems were discussed i

I l

~..

- ~

8 that were to be repaired prior to restart.

The post trip review concluded that all major equipment operated satisfactorily during trip and subsequent plant transient and that the unit could be restarted.

i The inspectors concluded that this post trip review demonstrated a i

positive safety attitude.

7.

Licensee Plans for Coping With Strikes (92709)

During this inspection period, the possibility existed for a strike at both the Surry and North Anna Nuclear Plants.

The inspectors reviewed the licensee's plan at Surry for coping with the strike.

The plans were reviewed for the following:

The minimum number of qualified and proficient personnel were available thereby ensuring plant operation and safety.

Plant sa urity was to be maintained at a level consistent with proper plant integrity and operation.

The contents of the plant strike plans are consistent with regulatory requirements and that these requirements are met.

The strike contingency plans supplemented with additional discussions with licensee security management was reviewed by the regional safeguards inspection staff.

It was concluded that the plans were adequate.

On Nay 9, licensee management and the IBEW union reached a tentative agreement on a new three year contract. The proposed contract will require approval by union members.

l 8.

Action On Previous Inspection Items URI 280,281/88-04-02 Licensee Evaluation of Steam Flow Indication at

{

Lower Power Levels From a Design, Safety Analysis, and Operator Action Point of View, involved steam flow indication not being available for operator information until the indicated power level reached approximately 18%. When this URI was initially identified, the licensee concluded that waiting until about 25% power level to verify operability of instrumenta-tion would have no impact on the existing safety analysis. This issue was then referred to NRC management for further review. This URI was closed in IR 280,281/91-04.

The basis for closure was that the issue was being considered for multiplant implications and that any concerns would be addressed when the review was complete. The NRC has reviewed this issue and concluded that the accident analysis was bounded and that waiting until 255 power to conduct channel checks was acceptable.

During this review, the staff noted that Westinghouse Electric Corporation evaluated this issue for their plants and concluded that there is a potential for an ambiguity or incompleteness in the FSAR. This may not completely identify the implicit credit taken for diverse trips / functions that are required to ensure that the accident analyses presented by the FSAR remain valid and bounding.

Westinghouse reconsended to the affected licensee's that the FSARs for 31 plants, including Surry, be reviewed to ascertain if changes are required I

I

5 g

to clarify operability and use of the associated functions.

The licensee has received the letter and has prepared a FSAR change to clarify this issue.

The FSAR change was being reviewed by the licensee as the inspection period ended. After the review is completed, the change will be incorperated into the FSAR.

9.

Exit Interview The inspection scope and results were summarized on May 15, with those individuals identified by an asterisk in paragraph 1.

The following summary of inspection activity was discussed by the inspectors during this exit.

I Item number Closed Descrintion and Reference NCV 280,281/92-11-01 Closed Failure of Fire Watch to Follow Procedure (paragraph 3.d) 9.

Index of Acronyms and Initialisms CFR CODE OF FEDERAL REGULATIONS DC DIRECT CURRENT DCP DESIGN CHANGE PACKAGE ECCS EMERGENCY CORE COOLING SYSTEM i

EDG EMERGENCY DIESEL GENERATOR E0P EMERGENCY OPERATING PROCEDURES ESGR EMERGENCY SWITCHGEAR ROOM EWR ENGINEERING WORK REQUEST FRV FEEDWATER REGULATING VALVE FSAR FINAL SAFETY ANALYSIS REPORT i

GL GENERIC LETTER IBEW INTERNATIONAL BROTHERHOOO OF CLECTRICAL WORKERS I&C INSTRUMENTATION AND CONTROLS IR INSPECTION REPORT JC0 JUSTIFICATION FOR CONTINUED OPERATION MRB MANAGEMENT REVIEW BOARD MS MAIN STEAM NCV NON-CITED VIOLATION NRC NUCLEAR REGULATORY COMISSION POTENTIAL PROBLEM REPORT PPR RF0 REFUELING OUTAGE t

SG STEAM GENERATOR SNSGC STATION NUCLEAR AND SAFETY OPERATING ComITTEE TDAFW TUR8INE DRIVEN AUXILIARY FEEDWATER TS TECHNICAL SPECIFICATION URI UNRESOLVED ITEM WO WORK ORDER i

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M24 UNITED STATES

./

NUCLEAR REOULATORY COMMISSION

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CE2 SON ll -

g 101 MARIETTA STREET N.W.

ATLANTA, GEOMOI A 30323 MAR 261992 Docket Nos. 50-280, 50-281 License Nos. DPR-32, DPR-37 Virginia Electric and Power Company ATTN: Mr. W. L. Stewart Senior Vice President - Nuclear 1

5000 Dominion Boulevard

{

Glen Allen, VA 23060 i

Gentlemen:

SUBJECT:

NOTICE OF VIOLATION (INSPECTIONREPORTNOS. 50-280/92-04 AND 50-281/92-04)

This refers to the Nuclear Regulatory Consnission (NRC) inspection conducted by Mr. M. W. Branch of this office on February 2 through March 7,1992.

The

(

inspection included a review of activities authorized for your Surry facility.

At the conclusion of the inspection, the findings were discussed with those members of your staff identified in the enclosed inspection report.

L Areas examined during the inspection are identified in the report.

Within these areas, the inspection consisted of selective examinations of procedures and representative records, interviews with personnel, and observation of activities in progress.

Based on the results of this inspection, certain activities appeared to be in violation of NRC requirements, as specified in the enclosed Notice of Violation (Notice).

The violation is of concern in that it involves your failure to promptly correct repetitive malfunctions of high head safety injection pump lube-oil temperature. control valves.

Previous failures of these valve have resulted in high temperature alarms for the HHSI pumps bearing and your operators have had to respond locally to an area that would be inaccessible during a design basis accident to temporarily correct the malfunction.

Based on the results of this inspection, two other activities also appeared to i

be in violation of NRC requirements.

However, no violation is being issued based on the fact that your self initiated program for improving procedure quality identified the deficiencies and your efforts in correcting the violations meet the criteria specified in section V.G of the NRC's Enforcement l

Policy.

You are required to respond to this letter and should follow the instructions specified in the enclosed Notice when preparing your response.

In your response, you should document the specific actions taken and any additional actions you plan to prevent recurrence. After reviewing your response to this l

Notice, including your proposed corrective actions and the results of future inspections, the NRC will determine whether further NRC enforcement action is necessary to ensure compliance with NRC regulatory requirements.

c W H W FT SEP r

Virginia Electric & Power Company 2

g g g jggg In accordance with 10 CFR 2.790 of the NRC's " Rules of Practice", a copy of this letter and its enclosures will be placed in the NRC Public Document Room.

Th9 responses directed by this letter and the er. closed Notice are not subject to the clearance procedures of the Office of Management and Budget as required by the Paperwork Reduction Act of 1980, Pub. L. No.96-511.

Should you have any questions concerning this letter, please contact us.

Sincerely,

%u V.

A Marvin Sinkule, Chief Reactor Projects Branch 2 Division of Reactor Projects

Enclosures:

1.

Notice of Violation 2.

NRC Inspection Report cc w/encis:

E. W. Harrell Vice President - Nuclear Services Virginia Electric & Power Company 5000 Dominion Boulevard Glen Allen, VA 23060 J. P. O'Hanlon Vice President - Nuclear Operations Virginia Electric & Power Company 5000 Dominion Boulevard Glen Allen, VA 23060 M. R. Kansler Station Manager Surry Power Station P. O. Box 315 Surry, VA 23883 M. L. Bowling, Jr., Manager Nuclear Licensing Virginia Electric & Power Co.

5000 Dominion Boulevard Glen Allen, VA 23060 Sherlock Holmes, Chairman Board of Supervisors of Surry County Surry County Courthouse Surry, VA 23683

Virginia Electric & Power Company 3

gg Dr. W. T. Lough

)

Virginia State Corporation Comission i

Division of Energy Regulation P. O. Box 1197 Richmond, VA 23209 cc w/encls cont'd: See page 2 cc w/encls cont'd:

Michael W. Maupin Hunton and Williams P. O. Box 1535 Richmond, VA 23212 C. M. G. Buttery, M.D., M.P.H.

State Health Comissioner Office of the Comissioner Virginia Department of Health P. O. Box 2448 Richmond, VA 23218 Attorney General Supreme Court Building 101 North 8th Street Richmond, VA 23219 i

I

ENCLOSURE 1 NOTICE OF VIOLATION I

i Virginia Electric and Power Company Docket No. 50-280, 50-281 I

Surry Unit 1 and 2 License No. DPR-32, DPR-37 During the Nuclear Regulatory Comission (NRC) inspection conducted on February 2 through March 7, 1992, 3 violation of NRC requirements was identified.

In accordance with the " General Statement of Policy and Procedure for NRC Enforcement Actions," 10 CFR Part 2. Appendix C (1991), the violation is listed below:

10 CFR 50, Appendix B, Criterion XVI, as implemented by Operational Quality Assurance Program Topical Report (VEP 1-5A, Section 17.2.16),

' requires, in part, that measures be established to assure that conditions adverse to quality be promptly identified and corrected, and in the case of significant conditions adverse to quality, these measures shall assure that the cause of the condition is determined and corrective actions be taken to preclude repetition.

Contrary to the above, actions taken since 1990 to correct recurring failures associated with the temperature control valves that regulate service water flow to the high head safety injection pumps' lube oil I

coolers have not been fully effective.

Malfunctions continue to occur, the most recent failures occurring on March 2, and 6,1992, and on September 10 November 11, and December 3,1991.

In all instances, these failures either rendered the automatic lube oil temperature control i

feature inoperable or resulted in degraded operation.

1 This is a Severity Level IV Violation (Supplement I).

J Pursuant to the provisions of 10 CFR 2.201, Virginia Electric and Power Company is hereby required to submit a written statement or explanation to the U.S.

i Nuclear Regulatory Connission, ATTN: Document Control Desk, Washington, D.C.

20555 with a copy to the Regional Administrator, Region II, a copy to the NRC Resident Inspector, within 30 days of the date of the letter transmitting this Notice of Violation (Notice).

This reply should be clearly marked as a Reply to a Notice of Viclation" and should include for each violation:

(1) the reason for the violation, or, if contested, the basis for disputing the violation, (2) the corrective steps that have been taken and the results l

achieved. (3) the corrective steps that will be taken to avoid further violations, and (4) the date when full compliance will be achieved.

If an adequate reply is not received within the time specified in this Notice, an I

order may be issued to show cause why the license should not be modified, i

suspended, or revoked, or why such other action as may be proper should not be taken. Where good cause is shown, consideration will be given to extending the response time.

Dated at Atlanta, Georgia

)

this 26th day of March 1992 1

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/p #"'W #e, NUCLEAR RECULATCC.Y COMMIS$10N t

4 UtflTED STATES

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101 MAllETTA STCEET.NQ.

ATL ANTA, GEORGIA 30323

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Report Nos.:

50-280/92-04 and 50-281/92-04 Licensee: Virginia Electric and Power Company 5000 Dominion Boulevard Glen Allen, VA 23060 Docket Nos.: 50-280 and 50-281 License Nos.: DPR-32 and DPR-37 l

Facility Name:

Surry 1 and 2 Inspection Conducted: February 2 through March 7,1992 Inspectors:

Ib/ b 3

b j

M. W. Br%gn/5enior Resident Inspector Fat ~e Tigned h

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$2b2.

J.' W. Yofk/R#sident Inspector D(te Sfigned A. % # &

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5 ~. Tin n/KesidentInspeqtor Ddte 5igned m

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.3b/72 Approved by:

P. E. Fret rickson, Section Chief Dtte Vigned i

Division of Reactor Projects SUPMARY Scope:

This routine resident inspection was conducted on site in the areas of

'l operations, maintenance, surveillance, quality verification and safety t

assessment review, independent plant evaluation, and licensee event review.

During the performance of this inspection, the resident inspectors conducted reviews of the licensee's backshift or weekend operations on February 2,13,16, 17, 19, 23, March 1, 3, 4, and 5, 1992, i

Results:

}

In the operations area, the following items were noted:

A weakness was identified in that, procedures do not recognize the manual mode of oper6 tion of the ventilation system (paragraph 3.a).

j i

The ability to trend hours spent in action statements will significantly enhance the licensee's ability to focus on problem areas (paragraph 3.e).

Housekeeping throughout the plant is generally good (paragraph 3.c).

Sc%w rwp

2 In the maintenance / surveillance area, the following items were noted:

. Planning and implementation of the switchyard CT replacement (paragraph 3.b) demonstrated the following:

. Coordination of many parallel and series activities as well as the regulatory awareness was observed as a strength.

. The switchyard design does not allow for normal preventive and corrective maintenance of some switchyard equipment.

. The failure to provide adequate procedures to calibrate the station blackout motor driven AFW pump start relays and to test the T average port of the ESF logic circuits are non-cited licensee identified violations (paragraphs 10.a and b).

. The E3F looic testing observed was well coordinated and received a high level of management attention as evidenced b Operations Manager to this infrequent task (y assignment of the Senior paragraph 4.b).

In the SA/QV area, the following items were noted:

. The TS and FSAR failure to describe the ventilation systems manual mode of operation was identified as a weakness (paragraph 8).

. The corporate IR, IDER, and CNS assessment and event review programs were found to be effective and met TS requirements (paragraph 6).

. The failure to properly correct HHS! pump lube oil temperature control valve deficiencies is identified as a violation and weakness (paragraph 3.g).

I

1 REPORT DETAILS 1.

Persons Contacted Licensee Employees

W. Benthall, Supervisor, Licensing

R. Bilyeu, Licensing Engineer

~ H. H. Blake, Nuclear Safety l

D. Christian, Assistant Station Manager J. Downs. Superintendent of Outage and Planning

A. Fletcher, Assistant Superintendent of Engineering i

R. Gwaltney, Superintendent of Maintenance

D. Hart Supervisor, Quality Assurance M. Kansler, Station Manager

J. McCarthy, Superintendent of Operations

K. Moore, Vice President-Nuclear Engineering Services

A. Price, Assistant Station Manager

R. F. Saunders, Assistant Vice President-Nuclear

S. Semmes, Senior Staff Engineer

E. Smith, Site Quality Assurance Manager T. Sowers, Superintendent of Engineering NRC Personnel

M. Branch, Senior Resident Inspector

S. Tingen, Resident Inspector

J. York, Resident Inspector

Attended exit interview.

Other licensee employees contacted included control room operators, shift technical advisors, shift supervisors and other plant personnel.

Acronyms and initialisms used throughout this report are listed in the last paragraph.

2.

Plant Status 4

Unit 1 began the reporting period at 97 percent power.

On January 30, 1992, coastdown began and on February 29, the unit was shutdown from 73 percent power to begin a scheduled 64-day refueling outage.

j Unit 2 began the reporting period in power operation.

The unit was at power at the end of the inspection period, day 80 of continuous operation.

2

~..

Operational Safety Verification (71707,42700,37828) l The inspectors conducted frequent tours of the control room to verify proper staffing, operator attentiveness and adherence to approved procedures.

The inspectors attended plant status meetings and reviewed operator logs on a daily basis to verify operations safety and compliance with TS and to maintain awareness of the overall operation of the facility.

Instrumentation and ECCS lineups were periodically reviewed i

from control room indication to assess operability.

Frequent plant tours were conducted to observe equipment status, fire protection programs, i

radiological work practices, plant security programs and housekeeping.

Deviation reports were reviewed to assure that potential safety concerns were properly addressed and reported.

j a.

Operation Of The Ventilation System The inspectors reviewed the various operational modes for the emergency ventilation system.

When both units are operating at power, the ventilation system will automatically realign when an SI signal occurs in either unit.

When the ventilation system realigns, the areas that contain-ECCS pumps are exhausted through filters to remove fission products and provide cooling for pump motors.

In addition, ventilation to the non-ECCS areas is secured, and i

ventilation is provided for the operating charging pump in the other unit.

When one unit is operating and the other unit is moving fuel, the ventilation system is aligned such that the primary objective is j

to ensure that the fuel building and containment exhaust is discharged through filters.

In the ventilation system's refueling mode alignment, if an SI signal occurred in the operating unit, the ventilation system would not automatically realign to the SI mode of operation. It would remain in the refueling configuration.

Operators would be required to place the fuel in a safe condition and then manually realign the ventilation system for the SI mode of operation.

Step 18 of EP 1-E-0, Reactor Trip or Safety Injection. dated January 16, 1992, provides instructions for realignment of the ventilation system when i

in the refueling mode of operation.

Operators estimated that it j

would take approximately five minutes to place the fuel in a safe condition and realign the ventilation system if required.

The ventilation system can be realigned from the control room.

The inspectors reviewed DC 78-534, Auxilary Ventilation System, dated April 27, 1979.

This DC was implemented in 1980 and significantly modified the ventilation system.

One of the ventilation system changes implemented by DC 78-S34, added the need to manually realign the system as previously discussed.

Prior to 1980, the ventilation system would automatically realign on receipt of an SI signal during the movement of fuel in the other unit.

The safety analysis performed for DC 78-S34 recognized this change of j

i

3 operation and considered it acceptable. The safety evaluation, dated January 17, 1984, performed by the NRC staff for amendments 91 and 92 to the operating license, approved this method of operation.

The licensee stated that the offsite dose during a refueling accident was significantly higher if the ventilation - system exhaust was' not filtered; however, not filtering the exhaust from ECCS areas during the first twenty minutes following a LOCA had only a minor effect on the off-site dose.

l t

The inspectors reviewed section 3.22 of the TS and FSAR chapters 5.3 and 9.13 in order determine if the ventilation system was required to realign automatically or manually upon receipt of an SI signal during the movement of fuel. The FSAR only discussed the automatic features of the system and did not describe the need to manually realign the ventilation system in the event of an SI signal in one unit when moving fuel in the other unit.

The TS did not state that the system was required to be automatic, but the basis section did describe the system as automatic.

The TS and FSAR failure to describe the ventilation systems manual mode of operation was identified as a weakness.

The inspectors noted another example where the emergency ventilation system was aligned such that manual action was required if the system was required to respond to an SI.

During this inspection period, operators placed the controllers for the emergency ventilation fans from automatic to manual. In this alignment, operators would have to make ventilation system flow rate adjustments during an SI where J

normally the flow rate is automatically adjusted.

Also, this alignment increases the potential for a fan to trip due to excessive i

flow rates.

Procedures do not recognize this alternate mode of operation.

This is considered a weakness because procedures should alert the operators that additional precautions are invoked when in this configuration.

b.

Operational Activity Associated With The Replacement of Switchyard Bus #5 Current Transformer.

On February 28, the licensee replaced a current transformer on one of the three phases of bus #5.

This activity involved several TS action statements and was closely observed by the inspectors.

Switchyard bus #5 supplies power to 2 of the 3 RSSTs, A and B.

The A RSST provides off-site power to emergency bus 1-J and the B RSST provides off-site power to the 2-H emergency bus.

The CT which provides protective and metering functions for the 34.5kva/120 vac was noted as having a low fluid level and was leaking fluid.

The licensee postulated that failure was eminent.

Failure would cause an unplanned loss of 2 of the 3 RSSTs which has in the past resulted in turbine runbacks due to IRPI power spikes.

Also, the failure would affect both units and challenge the fast start of 2

.1 4

of the 3 EDGs.. Several TS action statements impact taking the CT and bus #5 out-of-service:

TS 3.9 " Station Services Systems" requires that the 4160 emergency buses to be energized as explained in TS 3.16 TS 3.16 " Emergency Power System" requires two EDG to be -

operable, two emergency buses energized, and two independent offsite circuits to energize the 4160v buses.

TS 3.16.B.2 allows the primary source of offsite power to be unavailable for up.to seven days as long as back-feed capability exists.

TS 3.16.8 requires that the EDGs be operable when offsite power is degraded (i.e. 3.16.B only allows 3.16.B.1 or 3.16.B.2).

TS 3.0.2, " Limiting Conditions For Operation" specifies that if the emergency power supply for equipment on one train is inoperable that the normal and backup power supplies for the other equipment must be operable.

The licensee decided to replace the defective CT prior to Unit I shutdown with both units at power with the IJ and 2H emergency buses being powered by the #3 and #2 EDGs.

Leaving Unit 1 on line allows for emergency backup power by backfeeding the emergency buses if necessary from the station service trans-formers.

During the 6-8 hour time that bus #5 would be unavail-able, primary offsite power and EDG alignment would be as follows:

RSST A would be deenergized.

RSST B would be deenergized.

RSST C would be energized.

EDG#3 will be in standby for the 1H bus.

EDG#2 will be running and supplying power to the 2H bus.

EDG#3 will be running and supplying power to the IJ bus.

EDG#3 is the swing EDG and would not be 100 percent operable to supply the Unit 2J bus in an emergency.

It would swap to the 2J bus on an ESF signal, but would not on degraded or under voltage conditions.

The above offsite power alignment and EDG availability for the 2J bus would result in violation of TS 3.16.B and, therefore, TS 3.0.1 or 3.0.2 would apply.

To replace the CT with both units at power would require entry into TS 3.0.1 if it could be accomplished within the time allowed by TS 3.0.1.

However, the licensee determined that based on their estimates the repair would take longer then allowed by TS 3.0.1 and would require a waiver of compliance.

5 On Jebruary 28. at 1236. TS 3.0.1 LCO was entered and the repairs to s # chyard bus #5 began.

The inspectors monitored the establishment of ',hc required electrical alignment, briefing of the shifts, and narting of and operational parameters for the #2 and #3 EDG's. The licensee used temporsry maintenance operating procedure No. TM0P-312, Removal From Service of 34.5 KV Bus #5, dated March 2,1992.

The inspectors made several trips to the :;witchyard and verified that switchyard access was under control of' the security department and that bus #6 had access restricted by barriers.

The inspectors observed the removal and replacement of the defe:tive CT and the inspection of the othar two cts which were found to be acceptable.

The inspectors also manitored the restoration of the plants electrical systems after replacement of the CT.

The actual time spent in the action of TS 3.0.1 was such that the waiver of compliance was not needed. However, the provisions in the licensee's l

written request.for TS waivar, dated February 28, were verified by the inspectors. The NRC acknaledged the waiver request in a March 2 l

letter from the Region !! Ragional Administrator to the Senior Vice-President, Nuclear. The NE recognized the licensee's extensive planning and regulatory awareness as contributors in reducing the time for repairs such that the requested waiver was not actually needed.

c.

Housekeeping Housekeeping throughout the plant is genenlly good.

The licensee has significantly improved housekeeping in the condensate polishing building, boric acid flats, Unit 1 charging pumps cubicles, cable faults, emergency switchgear room, turbine building, and auxiliary building by refinishing the floors and/or repainting wall and component surfaces.

The licensee is in the process of repainting the No. 1 EDG room and Unit 2 charging pump cubicles.

Prior to repainting, the original surfaces were sanded or chipped awey which sometimes resulted in poor housekeeping in the adjacent areas.

Station management has reemphasized the need to maintain goed housekeeping to station personnel while painting or other maintenance is in process.

d.

Operations TPUP Review The TPUP program has completed approximately 1162 of the 3700 procedures requiring upgrade in the operations area.

The number of completed procedures exceeded the program goals.

This program is closely monitored by management and reports are routinely issued in

'3 order to inform management of program completion status.

The inspectors routinely monitor the performance of upgraded procedures and consider them to be of good quality.

The licensee utilized QA assessments and quarterly procedure upgrade surveys to evaluate the effectiveness of this program.

Approximately 100 randomly picked procedure users are surveyed quarterly in order to track the stations

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j i

6 perception of new procedures.

The results of these surveys are utilized to further enhance the quality of_ procedures.

I Vendor manuals are being updated in accordance _with the Configuration Management Program. The inspectors were informed that procedures are being upgraded prior to updating vendor manuals and that any vendor manual update that effersed procedures would have to be incorporated into procedures at a later date.

I e.

Computer Programs The Operations department has implemented a new computer program, VPASS, which aid operators in performing their duties and also records and trends hours spent in TS action statements.

Whenever a TS action statement is entered, operators are required to enter the appropriate data into VPASS.

At shift turnovers, operators are able to print out all TS action statements for review.

Also, the VPASS record of action statements is provided to station management for review.

The program is able to sort and trend action statements in many different ways, and provide valuable historical information relative to action statements.

For example, the licensee is able to accurately specify how many hours were spent in TS action statements in 1991 due to inoperable charging pumps or any other component or 1

system covered by the TS..

The ability to trend hours spent in action statements will si on problem areas. gnificantly enhance the licensee's ability to focus t

f.

HHSI Pump Lube 011 Cooler TCVs Each of the six HHSI pumps has a lube oil cooler. Service water is aligned to each cooler to remove heat from the lube oil. As the lube oil temperature increases, a TCV automatically opens and regulate SW flow through the cooler. Review of 1990 and 1991 station deviations revealed that failure of TCVs to automatically control lube oil temperature in the required band was a reoccurring problem.

The primary failure mechanisms were the TCV being stuck in the shut or intermediate position due to debris from the SW system that accumu-lated in the valve internals or the temperature controller not maintaining the proper setpoint.

In order to correct these TCV deficiencies, the licensee has replaced TCV disks with disks that are i

different in material and design on five of the six HHSI pumps and initiated routine flushes to remove silt and other debris from the SW system.

The new TCV disks were installed in June,1990 on all three i

Unit 1 HHSI pumps and the Unit 2A HHSI pump and in July 1991, on the Unit 2C HHSI pump.

This modification has not been perfonned on the Unit 2B HHSI pump.

On August 26, 1991, the licensee began to rou-tinely flush the valves on a two-week interval.

The licensee's corrective actions have reduced TCV failure rates, but the problem continues to exist.

On September 10, 1991, the TCV on the Unit IB HHSI pump failed to properly operate. On November 10 and y

=+

I December 3,1991 and on March 2,1992, the TCV on the Unit 28 HHSI failed to properly operate. On March 6, 1992, the TCV on the Unit 2A i

HHSI pump failed to properly operate.

When these failures occurred, operator manual action' or maintenance was required to correct the

_ problem.

The licensee is aware that the corrective actions implemented have not eliminated this problem and was in the process of procuring redesigned TCVs and controllers.

The materials and procedures required to accomplish this modification are scheduled to be available May 1, 1992.

Installation of these new components has l

not been scheduled.

The modification does not require an outage and therefore could be started when materials and procedures are available.

The inspectors concluded that until the proposed modifi-l cation is installed, the licensee needs to implement additional' temporary corrective measures to preclude repetitive TCV failures.

HHSI pumps are required to automatically start and operate on receipt of an SI signal. By design, operator manual actions are not required '

for pump operation during the initial phases of a LOCA. In addition, during the LOCA RMT phase, high radiation levels in the area of the HHSI pumps would prohibit operators from manipulating the TCV controllers.

The inspectors are concerned that if a TCV failed to properly control lube oli temperature during a LOCA, significant HHSI pump degradation or failure would occur.

y The failure to implement adequate corrective actions to prevent

'i repetitive TCV failures was identified as Violation 280,281/92-04-01.

Within the areas inspected, one violation was identified.

j 4.

MaintenanceInspections(62703,42700,71500)

During the reporting period, the inspectors reviewed maintenance activities to assure compliance with the appropriate procedures.

The following maintenance activities were reviewed.

a.

Roofing Leaks One of the areas examined during the last inspection period involved the number of roofing leaks present at the Surry plant. During this inspection period, a meeting was held with the manager of Civil / Mechanical Engineering to discuss the roof program. There were several parts to this program; and one part, the auxiliary building i

roof replacement, has had the specifications established and the roof designed.

The total roofing program will be prioritized with the auxiliary building roof being first.

The presentation of the roof management program recommendations to upper management is scheduled l

for March 31, 1992.

These recomendations will include repair, replacement, and retrofit for a five-year period.

The inspectors will continue to follow this program and its effect on decreasing the number of leaks.

i f

8 b.

. Maintenance Program Innovations The inspectors observed several maintenance innovations that are

[

being implemented to improve the overall performance of the maintenance department. These innovations are as follows*

i During a maintenance self assessment, it was determined that there was a lack of communication between the maintenance manager and the maintenance craftsmen.

The maintenance manager decided to alleviate this situation by holding quarterly meetings starting February 1992.

The inspectors attended'one of i

these meetings and noted that there was a good exchange of information.

The maintenance department has started issuing a maintenance department report on a monthly basis.

It's purposes are to explain various department tasks and processes, to make individuals more cognizant of their own and other dr.partments' work.

Inputs to the December,1991 report are from electrical maintenance, mechanical maintenance, maintenance engineering, preventive maintenance MOV, predictive analysis, and welding groups.

These articles included such topics as ALARA update on i

exposure reduction, challenges identified by the maintenance self assessment, EDG task team report, and malfunction of a 3

control rod that caused a manual trip.

j Another innovation involved the meeting of individual-maintenance teams with the QMQ ALARA coordinator and some of.the managers to establish goals that will improve quality of work and reduce the radiation exposure.

The inspectors will-. monitor the effect of these innovations with respect to the effects on the quality of maintenance.

c.

Feedwater Regulation Valve Repair During the last two inspection periods, the inspectors have followed the repair of FRVs.

In the December period, these valves may have contributed to a turbine / reactor trip caused by a high feedwater level in the B steam generator. A review was made of the licensee's evaluation of the FRV oscillation, including testing and modification documentation.

Modification documents and current evaluation showed i

that a smaller size tubing had been installed for the supply air i

lines. This smaller tubing size could cause a longer stroke time for the valves.

A station deviation (No. S-92--0121) was written.

The licensee i

reviewed the time for the closing of the valves by reviewing a previous trip /ESF actuation and noted that it took seven seconds to close the valves. Analysis assumptions were for no more than a 10 to

...wi

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l 9

e 15 second closing' time.

The licensee is replacing the Unit 1 tubing with the proper size during this outage and the valves'will be placed-in an.151 program that will provide periodic timing testing of the valves.

Within the areas inspected, no violations were identified.

5.

Surveillance Inspections (61726,42700)

During the reporting period, the inspectors reviewed surveillance activities to assure compliance with the appropriate procedure and TS requirements.

The following surveillance activity was reviewed:

a.

Testing of Unit I and 2 Relays During a review of TS change no. 235, the licensee discovered that a relay in the SI system logic sequence was not adequately tested as an active component.

The subject relay actuates on low Tave and makes up the matrix needed for high steam flow in coincidence with-low Tave r

or low steam line pressure.

The monthly periodic test checks continuity but does not test for relay actuation at the SI contacts.

The licensee eritered a'six hour clock to hot shutdown (TS 3.7 table 3.7-2) at 1413 on February 14.

The appropriate perodic tests, 1-PT-8.3A (dated June 27,1989) and 2-PT-8.3A (dated-October 2, 1990), Safety Injection and Feedwater Control Isolation Logic, were revised to include the testing for these relays.

The inspectors observed this testing in the ESGR room for both units and reviewed i

the documentation.

Both units were successfully tested and the six hour clock was exited at 1434 hours0.0166 days 0.398 hours 0.00237 weeks 5.45637e-4 months .

An LER (no. S1-92-003) was written to cover this event and is discussed further in paragraph 10.b.

b.

IJ Bus ESF Actuation with Undervoltage and Degraded Voltage The inspectors witnessed the testing of ESF actuation with undervoltage on the IJ bus.

The test was accomplished in accordance with procedure 1-0PT-ZZ-002, ESF Actuation With Undervoltage and Degraded Voltage - IJ Bus, dated February 27, 1992.

The inspectors reviewed the test instructions and attended the pre-evolution briefing.

The licensee had assigned a Senior Operation Manager on duty during performance of this infrequently performed task.

This provided the shift crews with the needed support as well as allowing the managers to participate in the briefing and monitor the performance.

Within the areas inspected, no violations were identified.

i

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10 g

S 6.

Quality Verification and Safety Assessment Review (40500)

The inspectors conducted a review of the licensee's corporate independent review functions and industry operatino experience program.

TS 6.1.C.2 requires that the MSRC be responsible for the review of safety evaluations, unreviewed safety questions TS changes, violations, significant abnormalities, LERs, deficiencies that could affect nuclear safety, and SNSOC meeting minutes.

the licensee implemented the requirements by submitting all LERs, violations and TS changes to MSRC members for review.

f Additionally, all safety evaluations are independently reviewed by CNS while performing as a subcommittee to the MSRC.

CNS also reports to the Manager of Nuclear Licensing and Programs when conducting independent assessments of station activities and when implementing the industry operating experience program.

Tne inspectors reviewed the following program implementing procedures:

LICP-4000 Corporate Nuclear Safety, LICP-2001 Independent Review Program, NLP ADM 4.1 Review and Processing of Industry Operating Experience Documents and VPAP 3002 Operating Experience Program.

a.

Independent Review Process Through the Independent Review program, CNS independently reviews all safety evaluations performed in accordance with 10CFR50.59 and reviews all SNSOC meeting minutes.

The inspectors discussed the program with responsible personnel, reviewed selected independent verification packages for effectiveness and reviewed qualifications of individuals.

Personnel assigned to perform the reviews appeared to collectively possess experience and competence in the diverse disciplines necessary to be effective.

However, the training folders for'the persons assigned the IR function were not always complete and were difficult to audit.

The inspectors questioned the licensee on the use of the IR process to meet the MSRC oversight requirements of TS 6.1.C.2 since the TE did not specifically discuss the use of subcommittees.

The licensee's TS amendment that invoked the current MSRC oversight does discuss the use of subcommittees in the support information and the use of subcommittees is described in the NRC's guidance on oversight of offsite connittees.

The inspector found the licensee process acceptable and in compliance with TSs.

The IR program was clearly defined by the controlling procedure and appeared to be effective in identifying and resolving concerns as well as tracking and reporting the status of items.

The inspectors noted that while safety evaluations were reviewed, the licensee's program had no requirements to independently review a sample of activity screening checklists.

Improper use of screening checklists could result in not performing the necessary written safety evaluation.

Additionally, the person assigned the primary review function for the SNSOC meeting minutes does not attend the meetings.

The licensee agreed to consider the

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11

.s i

need to have the reviewer periodically attend SNSOC meetings and to i

continue with their assessment of the quality of the safety evalua-i tion screening process.

b.

Industry Operating Experience Review l

CNS is responsible for maintaining the licensee's IDER Program with the purpose of reviewing 10ER documents to assess applicability and develop action plans necessary to prevent or minimize the consequences of previously experienced industry events.

IDER documents include NRC Information Notices, Generic Letters, Virginia Power LERs, 10 CFR 21 Notifications, INPO event reports and Westinghouse Technical Bulletins.

10ER documents are initially screened within 10 days and assigned a priority to prepare an analysis report and develop all action plan within 30, 60, or 90 days to address the concern. The inspectors selected a sampling of documents and determined that appropriate priority had been assigned and that action plans were of high quality, clearly identifying the concerns and needs for further action.

10ERs selected for review included IN 91-46, GL 91-05, IN 88-60, and GL 90-05. The inspectors i

identified weaknesses with the licensee's tracking system for documents. In many cases, due dates were not assigned, due dates had been exceeded or proposed actions had been rejected with no indication that followup was being pursued.

The inspectors determined that in general the actions were being adequately pursued i

and the problems were confined to maintenance of the tracking system data base.

c.

CNS Assessments and Event Reviews The CNS assessment and event review process is controlled by procedure LICP-4000, Procedure for Performing Assessments and Event Reviews.

At the time of the inspection, this procedure was in the concurrence cycle for approval. The new procedure replaced procedure NL&P-ADM-2.2 and incorporated changes in the program and j

organization. The assessment and event review process is not required by the TS.

The stated purpose of the CNS event review and assessment i

process is to independently evaluate technical issues, performance problems or other areas as requested by the MSRC, senior management, or station management and make recommendations for improvements.

l The inspectors discussed the assessment and review process with the supervisor of nuclear safety review and several members of his staff.

The planned CNS assessments are integrated with other review activities scheduled at the station. In some cases, personnel from other organizations are included as part of the team.

The list of 1991 assessments and reviews were discussed and management's involvement in the process was evident by the number of senior management requested assessments that were performed.

Within the areas inspected, no violations were identified.

12 7.

IPE' Internal Flooding Corrective Action Review (71500)

Surry Power Station's IPE determined that it had a higher than expected degree of vulnerability for~ turbine building flooding. A team inspection was made in November,1991, to ' assess the licensee's corrective action plans and interim protective measures.

The Chaiman held a public meeting on this subject at the Surry Nuclear Information Center on November 29, 1991. Certain actions were taken to reduce this vulnerability, among thes was inspection of one of the main condenser outlet expansion joints by the i

licensee. - This was done in order to estimate the service life of the -

1 eight affected expansion joints.

The inspection showed degradation of this expansion joint and the licensee decided to inspect the remaining i

expansion joints.

There were varying degrees of degradation found in these remaining joints. Consequently, the licensee decided to replace all of these 96 inch diameter expansion joints and committed to accomplish this by February 28.

On February 22 this task was completed.

Each expansion joint replacement took about ten days and initially the licensee believed that TS waivers would be required for.four of these replacements o

(2 for each unit) because emergency service water' lines would have to be isolated by stop' log installation. ' However, the licensee developed and designed a system that did not compromise safety, gave two barriers for-worker safety, and eliminated the need to isolate a safety system train i

thereby negating the need for an TS waivers.

Within the areas inspected, no violations were identified.

8.

ESF Verification (71710)

The inspectors walked down the safety related portions of the ventilation system. The ventilation system is shared between the units. Sheets-1, 2, and 3 of drawing 11448-FB-60 were utilized for this walkdown.

The following discrepancies were identified during the walkdown:

Overall labeling of ventilation system components was poor.

Manual dampers were not labeled, many had the identification numbers and open/ closed positions annotated in handwriting with a felt marker on the component.

The handwheel on the motor operated dampers to th's charging pump motors were not labeled. Other components were labeled with red tape, duct tape, pencil, or felt marker.

The inspectors walked this system down with the Configuration Management labeling personnel, and were informed that the relabelit.g program which is scheduled for completion in March, 1993 would resolve these deficiencies.

011 was dripping from 1-M00-VS-100B hydraulic actuator.

There was oil on the piping and wall below the MOD. The inspectors noted that a work order to repair the oil leak was initiated in February 1990, but was classified as low priority and had not been scheduled to be worked.

1-MOD-VS-1008 is required to automatically operate on an SI signal.

The inspectors were informed that monthly periodic testing

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13 I

on the ventilation system verifies that the MOD repositions.

The inspectors were also informed that if the oil level in the damper's reservoir got too low, the MOD would not open as required.

The MOD-

' oil leak has been scheduled to be repaired during the second week of March, 1992.

l The inspectors noted that the physical condition of the ventilation system was in the process of being improved. Some of the duct work was.recently painted or primed, but the majority of the duct work still needed' painting. Housekeeping in the ventilation system areas was adequate.

Within the areas inspected, no violations were identified.

9.

Technical Procedures Upgrade Program (42700)

The inspectors discussed the technical procedure upgrade program with the I

licensee on March 3 and 5.

This program was started December 31, 1989,

.t and is scheduled to be completed by December 1996.

The following table shows the disciplines and the number of technical procedure that are to be written over the life of the program.

Discipline Number of Procedures Electrical 1072 Mechanical 585 ISC 1538

0ps(Dual) 1915

- 0ps(Single) 1784

- - 0ther 588 i

Annunciator Procedures and E0Ps

- Normal OPS Procedures

- - Special Tests, etc.

i A review of the status of the TPUP revealed that most of the procedure disciplines are above or just slightly below the goal with the exception of the 18C procedures. - The procedures group exceeded the 1991 yearly goal for writing I&C procedures, but still continues to be below the overall i

goal,'i.e. 210 procedures completed and the goal was approximately 410 completions.

The inspectors also reviewed the backlog of PAR's that are used to change or modify the procedures.

The PAR program was started in February 1990.

Actual procedure revisions would be made when SNSOC directed the proce-dures group to make the change.

In July 1990, this consnittee directed the procedures group to incorporate changes to procedures when the number of PAR's reached five or more and on February 10, 1992, the process of -

incorporation of all PAR's into procedures was included in VPAP 0502. As of December 1991, the number of outstanding PARS was 1323 and this appears excessive to the inspectors.

Also as of this date there were 23 proce-dures outstanding that had five or more PARS's and 339 PARS's outstanding i

I 14 F

that were written in 1990 (161 of these PARS's were for the I&C l

procedures). Approximately 15 percent of the upgraded procedures have one or more (open or closed) PAR's and approximately 31 percent of the non-upgraded procedures have one or more. This indicates that the upgraded procedures are of beMer quality and require fewer changes within the areas inspected.

No violations'were identified.

- 10. LicenseeEventReview(92700) f The inspectors reviewed the LER's listed below and evaluated the adequacy.

of corrective action.

The inspector's review also included followup on the licensee's implementation of corrective action.

a.

(Closa0 LER 280,281/9t-002, 4160 Volt Transfer Bus D, E, and F Undervoltage Relay Trio Setpoints Set Below TS Limit Due to Procedure Error.

This issue inulved not setting the station blackwt motor i

driven AFW pump start relays in accordance with the values specified in TSs.

This issue and corrective actions were discussed in Inspection Report 280,281/92-02.

This event was caused by an error in calibration procedures in that an incorrect UV relay trip setpoint was specified.

TS 6.4.A.2 requires detailed written procedures for j

calibration of componer.35 involving nuclear safety of the station.

s The failure to provide an adequate procedure to calibrate the station blackout motor driven AFW pump start relays is identified as NCV 280,281/92-04-02.

This violation will not be subject to enforcenint action because the licensee's efforts in identifying and correcting the violatior, meet the criteria specified in Section Y.G. of the Enforcement Policy.

b.

(Closed) LER 280,281/92-003, Incomplete Engineered Safety Features Testing Due to Procedure Deficiency. This issue involved the failure to fully test certain ESF system logic actuation relays in accordance with TS Table 4.1-1 Item 26. Specifically, actuation of the relays which energize on low reactor coolant average temperature were not being verified (see paragraph 5.a for more details).

The licensee discovered this during a procedure upgrade. TS 6.4.A.2 requires detailed written procedures for calibration of components involving nuclear safety of the station.

The procedures were revised and the i

relays were tested. This failure to provide an adequate procedure to I

fully test the ESF system logic actuation relays is identified as NCV j

230,281/92-04-03.

This violation will not be subject to enforcement action because the licensee's efforts in identifying and correcting i

the violation meet the criteria specified in Section V.G. of the i

Enforcement Policy.

j c.

(Closed)LER 280/91-13, MCC Room Fire Suppression System Inoperable Due tc Personnel Error in Administratively Controlling the MCC Room Exit Door.

This issue involved personnel blocking open the Unit 1 cable vault upper level MCC room exit door without estat>l1shing I

15 provisions to shut the door if a fire in the area would have occurred.

Tnis issue was discussed in Inspection Report 280,281/91-29 and was left open because the licensee had not completed corrective actions.

The licensee has installed signs on fire doors that explain the special precautions that must be followed when the door is open.

Within the areas inspected, no violations were identf fied.

11. Exit Interview The inspection scope and results were sumarized on March 9,1992, with those individuals identified by an asterisk in paragraph 1.

The following summary of inspection activity was discussed by the inspectors during this exit.

Item Number Status Description and Reference VIO 50-280,261/92-04-01 Open Ineffective Corrective Action Associated With HHSI Pump Lube-Oil Cooler TCVs (paragraph 3.g).

NCV 50-280,281/92-04-02 Closed failure to Properly Test the Blackout Relays for Starting Motor Driven AFW (paragraph 10.a).

NCV 50-280,281/92-04-03 Closed Failure to Properly Test the Average Temperature Portion of ESF Logic Circuits (paragraph 10.b).

LER 50-280,281/92-002 Closed 4160 Volt Transformer Bus D, E, and F' Undervoltage Rela;r Trip Setpoints Set Below TS Limit Due to Procedural Error (paragragh 10.a).

LER 50-280,281/92-003 Closed Incomplete Engineered Safety Features Testing Due to Procedural Deficiency (paragraph 10.b).

LER 50-280/91-13 Closed MCC Room Fire Suppression System Inoperable (paragraph 10.c).

12.

Index of Acronyms and Initialisms ALARA AS LOW AS REASONA8LY ATTAINABLE AFW AUXILIARY FEEDWATER

/ p ase&q d

UNITED STATES i

4 NUCLEAR CE!ULATORY COMMIS$10N 83 nEoioN u I

y 101 MARIETTA STREET N.W.

,AT t.ANTA, GEORGI A 30323 FEB 2 0 892 Docket Hos.:

50-250, 50-251 License Nos.: DPR-31, DPR-41 Florida Power & Light Company ATTN: Mr. J. H. Goldberg President - Nuclear Division Nuclear Energy Department P. O. Box 14000 Juno Beach, Florida 33408-0420 Gentlemen:

SUBJECT:

TEMPORARY WAIVER OF COMPLIANCE - TURKEY POINT UNIT 3 This letter confirms the telephone conversation between Mr. L. W. Pearce of your staff and Mr. R. C. Butcher of my staff on February 19, 1992, granting a Regional Waiver of Compliance for Turkey Point Unit 3.

Our action was based on your written request letter dated February 19, 1992.

Technical Specification (TS) 3.6.1.3, " Containment Air Locks " requires that each containment air lock shall be operable during Modes 1, 2, 3, or 4.

Action statement b. states:

"With the containment air lock inoperable, except i

as the result of an inoperable air lock door, maintain at least one airlock l

door closed; restore the inoperable air lock to OPERABLE status within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months or be in HOT STANDBY within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in COLD SHUTDOWN within 4

the following 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months ."

On February 18, 1992, during the performance of the TS 4.6.1.3.c required six month surveillance test on the interlock between the inner and outer air lock doors, personnel were able to crack open the inner door on the Unit 3 emergency escape hatch with the outer door closed and the interlock set to open the outer door.

As a result, the containment emergency air lock was considered inoperable.

You were unable to complete repairs within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months , and requested a waiver of compliance from TS 3.6.1.3 for up to 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . You expect to complete repair of the interlock within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

As compensatory action until the air lock is repaired, you will station a dedicated operator at the emergency air lock to ensure that only one door is opened at a time and that the door does not remain open any longer than is required.

Your waiver request was reviewed by the Plant Nuclear Safety Committee and approved by the Plant General Manager.

%263ttMN Npp

FE8 20 591 j

Florida Power & Light Company 2

Prior to granting the temporary Waiver of Compliance, the technical issues and extent of the Waiver were reviewed.

They were discussed in a telephone call among L. Reyes, E. Merschoff, M. Sinkule, and R. Butcher of RII; G. Lainas, H. Berkow, and G. Hubbard of NRR; and R. Grazio and L. W. Pearce of FP&L.

This one-time Waiver of Compliance was granted for up to 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months based on the justification and compensatory measures documented ir: your request letter.

If you have any questions concerning this letter, please contact us.

Sincerely, i

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/

Stewart D. E er Regional Administrator

Enclosure:

FPL Letter (L-92-048) dtd February 19, 1992 l

cc w/ encl:

K. N. Harris, Sr. Vice President Pluclear Operations Florida Power and Light Co.

P. O. Box 14000 Juno Beach, FL 33408 R. E. Grazio, Director Nuclear Licensing Florida Power and Light Co.

P. O. Box 14000 Juno Beach, FL 33408-0420 T. F. Plunkett, Vice President Turkey Point Nuclear Plant P. O. Box 029100 Miami, FL 33102 L. W. Pearce, Plant Manager Turkey Point Nuclear Plant P. O. Box 029100 Miami, FL 33102 L. W. Bladow Quality Manager Turkey Point Nuclear Plant P. O. Box 02FQ 0 Miami, FL 331J2 (cc w/ encl cont'd - See page 3)

FEB 28 E Florida Power & Light Company 3

(cc w/enci cont'd)

E. J. Weinkam Licensing Manager Turkey Point Nuclear Plant P. O. Box 029100 Miami, FL 33102 Harold F. Reis, Esq.

Newman and Holtzinger, P.C.

1615 L Street, NW Washington, D. C.

20036 John T. Butler, Esq.

Steel. Hector and Davis 4000 Southeast Financial Center Miami, FL 33131-2398 Attorney General Department of Legal Affairs

.The Capitol Tallahassee, FL 32304 Jacob Daniel Nash Office of Radiation Control Department of Health and Rehabilitative Services 1317 Winewood Boulevard Tallahassee, FL 32,399-0700 Jack Shreve Public Counsel i

Office of the Public Counsel c/o The Florida Lesgislature 111 West Madison Ave., Room 812 Tallahassee, FL 32399-1400 Administrator Department of Environmental Regulation Power Plant Siting Section State of Florida 2600 Blair Stone Road Tallahassee, FL 32301 Robert G. Nave, Director Emergency Management Department of Connunity Affairs 2740 Centerview Drive Tallahassee, FL 32399-2100 (cc w/enci cont'd - See page 4) t i

I

FEB t81982

.8 Florida Power & Light Company 4

i (cc w/enci cont'd)

Joaquin Avino County Manager of-Metropolitan i

Dade County j

111 NW 1st Street, 29th Floor

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ENCLOSURE

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a. m.a FE L-92-048 l

Stewart D. Ebneter FEB 191992 l

Regional Administrator, Region II U. S. Nuclear Regulatory Commission 101 Marietta St.,

N.W., Suite 2900 Atlanta, GA 30323 Mr. Stewart D. Ebneter:

Re:

Turkey Point Unit 3 Docket No. 50-250 Operation During Repair of the Emergency Escape Hatch Interlock Temocrarv Waiver of Compliance This letter documents riorida Power and Light's request of Region II for a 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months temporary waiver of compliance with Technical Specification 3.6.1.3,

" Containment Air Locks," Action statement b.,

"With the containment air lock inoperable, except as the result of an inoperable air lock door, maintain at least one' airlock door closed; restore the inoperable air lock to OPERABLE status within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months or be in HOT STANDBY within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in COLD SHUTDOWN within the following 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months .

Since the inner air lock door has been satisfactorily vacuum tested l

and administrative control of the door positions will be maintained by a dedicated operator, no significant safety hazards or environmental impacts exist.

On February 18, 1992 during the performance of 3-OSP-051.6,

" Containment Air Lock Doors operability Test" on the Unit 3 emergency escape hatch, personnel performing the test were able to break the seal on the inner door during an attempt to force open the inner door with the outside door closed and the interlocks set to open the outer door.

The door could not be freely opened but an apparent leak path could be created.

When the interlocks operate as designed the inner door can not be opened with the interlocks set for the outer door to open.

The interlocks were not considered functional and therefore the containment emergency air lock 'was i

considered inoperable due to a cause other than an inoperable air lock door.

Unit 3 then entered the above action statement at 1312 hours0.0152 days 0.364 hours 0.00217 weeks 4.99216e-4 months and repair of the interlocks began.

Current repair efforts of the interlocks have been partially successful.

Complete repair or replacement of the interlock system is expected to be completed within the next 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

A representative of the Chicago Bridge and Iron Corporation, i

manufacturer of emergency hatch systems, has been asked to come to a m s,

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Enclosure the site to aid in the repair of the cam interlock system.

Currently both the inner and outer doors are closed except during the repair effort.

A vacuum test of the inner door was performed to verify the integrity of the inner door seal.

The surveillance requirements of 4.6.1.3.c. state: "At least once per 6 months by verifying that only one door in each air lock can be opened at a time."

Since the interlock between the inner and outer doors failed and is considered inoperable, therefore Technical Specification 3.6.1.3 is not met.

- Draft NUREG 1431, WOG Merits Program Phase III, Standardized Technical Specifications for Westinghouse Plants provides an Action statement which allows for the locking of doors and 31 days for repair with an air lock door interlock mechanism inoperable in one or more air locks as long as an operable door is closed.

The WOG Merits also permits entry and exit into containment under the control of a dedicated operator.

Until the air lock is repaired, a dedicated individual will be stationed at the emergency air lock to ensure that only one door is opened at a time and that the door does not remain open any longer than is required.

This request has been reviewed by the Plant Nuclear Safety Committee and approved by the Plant General Manger.

This administrative control of the position of the doors is in place.

'If you have any questions concerning this issue please contact us.

i Very truly yours, Wf

(

T. F. Plunkett Vice President Turkey Point Nuclear TFP/JEK/jek cc:

Document Control Desk, USNRC Raj Auluck, Project Manager, NRR, USNRC Senior Resident Inspector, USNRC, Turkey Point Plant t

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10 6 L" -

CM MAR 091992

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j Docket Nos. 50-250, 50-251 License Nos. DPR-31, DPR-4 O NE t"'o Florida Power and Light Company ATTN: Mr. J. H. Goldberg President - Nuclear Division Nuclear Energy Department P. O. Box 14000 Juno Beach, FL 33408 Gentlemen:

SUBJECT:

NOTICE OF VIOLATION I

(NRC INSPECTION REPORT N05. 50-250/92-03 and 50-251/92-03)

This refers to the Nuclear Regulatory Commission (NRC) inspection conducted by Mr. R. C. Butcher of this office on January 25 through February 28, 1992. The inspection included a review of activities authorized for your Turkey Point facility. At the conclusion of the inspection, the findings were discussed with those members of your staff identified in the enclosed Inspection Report.

Areas examined during the inspection are identified in the report. Within i

these areas, the inspection consisted of selective examinations of procedures and representative records, interviews with personnel, and observation of activities in progress.

Based on the results of this inspection, certain of your activities appeared to be in violation of NRC requirements, as specified in the enclosed Notice of Violation (Notice). We are concerned about the violation because of the importance of safety related equipment maintaining integrity following the effects of an earthquake.

You are required to respond to this letter and should follow the instructions i

specified in the enclosed Notice when preparing your response.

In your response, you should document the specific actions taken and any additional actions you plan to prevent recurrence. After reviewing your response to this i

Notice, including your proposed corrective actions and the results of future inspections, the NRC will detemine whether further NRC enforcement action is ne:essary to ensure compliance with NRC regulatory requirements.

In accordance with 10 CFR 2.790 of the NRC's " Rules of Practice," a copy of this letter and its enclosures will be placed in the NRC Public Document Room.

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14 administrative control of the air lock door positions by a dedicated operator will be in place.

i both the inner and outer air lock doors are maintained closed except during the repair effort. The inner door is not to be manipulated except for testing of the air lock interlock until the interlock is repaired.

in recognition of a generic problem with TS in this area, the draft NUREG 1431 WOG Merits Program Phase III Standardized Technical Specifications for Westinghouse Plants, provides an action statement which allows for the locking of doors and 31 days 1

for repair with an air lock door interlock mechanism inoperable in one or more air locks as long as an operable door is closed. The WOG Merits Program also permits entry and exit into containment under the control of a dedicated operator.

By letter L-92-048 dated February 19, 1992, the licensee submitted

, FPL's written request for the temporary waiver of compliance. At 12:45 p.m. on February 19, 1992, the NRC verbally approved a 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months temporary waiver of compliance with TS 3.6.1.3.

The licensee completed repairs to the emergency escape hatch door interlock mechanism at 8:50 p.m. on February 19, 1992, and exited the temporary waiver of compliance for TS 3.6.1.3.

By letter dated February 20, 1992, the NRC confirmed the granting of a temporary waiver of compliance based on the licensee's letter of February 19, 1992.

e.

At 2:45 p.m. on February 23, 1992, the licensee entered the action statement for TS 3.9.11, Water Level - Storage Pool, when the water level in the Unit 4 SFP was identified to be 2 inches below the TS limit of 56 feet-10 inches. This was the result of an ongoing problem with the keyway gate seal which allowed water to leak from the SFP to the fuel transfer canal. The licensee added water to the SFP, increased the air pressure to the keyway gate boot seal, and exited the LC0 at 3:45 p.m. on the same day. Water had also been added to the Unit 4 SFP on January 16 and February 8,1992. The SFP and fuel transfer canal water levels have now been equalized. On October E 1991, the licensee submitted a PWO (WA911007213000) for replacement ?

the keyway gate seal. A SFP shuffle was also completed on February D, 1992, in order to move spent fuel assemblies away from the keyway gate to provide a safe load path for removing the keyway gate, replacing the seal, and re-installing the gate. Work on the keyway gate seal replacement job has been tentatively scheduled to begin by March 11, i

1992, and Operations has been monitoring and will continue to monitor

^

the Unit 4 leak chase system per 0-050-201.2, SNP0 Daily Logs. No leakage from the fuel transfer canal has been detected. The inspectors will continue to followup on the licensee's actions regarding this i

matter.

13 breakers in the racked-out position and prior to October 10, 1991, there was no procedural requirement to restrain the breakers while in the racked-out position. Breakers 3AA09, 3AA22, 3AB22, 4AA09, 4AA22 and 4AB22 are nomally in a racked-out position and other. Class 1E breakers may be racked-out for maintenance. The failure to maintain the Class 1E 4 kv switchgear in a seismically qualified configuration is a violation of 10 CFR 50. Appendix A Criterion 2.

Although this event met most of the critria of Section V.G. of the enforcement 4

policy for a non-cited violation, the lack of timeliness in reporting (fromOctober 18, 1991, to February 10,1992) requires this be cited as a violation. This item will be tracked as violation 50-250,251/92-03-01. The licensee's program to track industry events and initiate corrective actions is a strength, c.

At 6:25 p.m. on February 16, 1992, all inservice blackstart diesel generators were declared out of service for transformer changeout and fuel oil tank switch preventive maintenance. The No. 3 blackstart diesel generator had already been taken out of service for

, quarterly preventive maintenance. All blackstart diesel generators

}

' except for No. 3 were returned to service at 11:45 a.m. on the following day.

d.

On February 18,1992, at 1:12 p.m., during the performance of 3-0SP-051.6, Containment Air Lock Doors Operability Test, on the Unit 3 emergency escape hatch, test personnel were able to break the seal on the inner door during the attempt to force open the inner door with the interlocks set to open the outer door. The inner door should remain secure, however the door moved sufficiently to create an apparent leak path. The interlock was not considered operable and therefore the containment emergency air lock was considered inoperable. Unit 3 then entered TS 3.6.1.3, Containment Air Locks, action statement b which states: With the containment air lock inoperable, except as the result of an inoperable air lock door, maintain at least one airlock door closed; restore the inoperable air lock to OPERABLE status within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months or be in HOT STANDBY within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in COLD SHUTDOWN within the following 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months .

The licensee's efforts to repair the interlock problem was partially successful in that the inner door interlock was made operable but the outer door interlock was then found to not function properly due to 4

looseness in the interlock mechanism.

On February 19, 1992, the licensee concluded that repair of the Unit 3

{

emergency escape hatch air lock doors interlock mechanism would take longer than the 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months allowed by TS 3.6.1.3.

At 12:00 noon on February 19 by telecon, the licensee requested the NRC approve a 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Temporary Waiver of Compliance with TS 3.6.1.3 based on the following:

the inner air lock door seals successfully passed a vacuum test following the above maintenance activities.

e,y02 teh UNITED STATES

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NUCLEAR RE0uLATORY cOMMissi N Cts: ION il y

101 Man ETTA STREET, N.W.

AT4.ANTA.GEonom 30323

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i Docket Nos. 50-325, 50-324 License Nos. DPR-71, DPR-62 Carolina Power and Light Company ATTN: Mr. R. A. Watson Serwor Vice President Nuclear Generation P. O. Box 1551 Raleigh, NC 27602 Gentlemen:

SUBJECT:

TEMPORARY WAIVER OF COMPLIANCE FOR BRUNSWICK UNITS 1 AND 2 This letter acknowledges your letter of May 8,1992, requesting a Temporary Waiver of Compliance from the Action Statements associated with Technical Specification 3.3.5.9, Table 3.3.5.9-1, item 1. Table 3.3.5.9-1, item 1 (Main Stack Monitoring System) requires the system's noble gas activity monitor, iodine sampler cartridge, particulate sampler filter, system effluent flow rate measurement device, and sampler flow rate measurement device to be OPERABLE at all times. If the noble gas activity monitor is out of service, Action Statement 123 requires grab samples to be taken at least every 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and analyzed. If the iodine sampler cartridge or pprticulate sampler filter are out of service, Action Statement 127 requires samples to be continuously collected (using auxiliary sampling equipment) and analyzed. If the system effluent flow rate measurement device or sampler flow rate measurement device are out of service, Action Stats-ment i22 requires pathway flow rate to be estimated at least every eight hours.

Your letter requested that the main stack monitoring system be taken out of service without the performance of Action Statements 122,123 and 127. This request was made in support of necessary modifications to the main stack isokinetic sampling probe, which when taken out of service, renders the main stack monitoring system inoperable and precludes alternate sampling required by Action Statements 122,123 and 127. In addition, the main stsck high radiation instru-i ment's primary containment purge and vent valve isolation function will also be disabled. This is an automatic function required by Technical Specifications in Operational Conditions 1, 2 and 3.

Recognizing the need to modify the main stack isokinetic sampling probe, and discerning no adversa impact, your May 8,1992 Temporary Waiver Request was qgv06iC M bpp j

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ERY 15 W Carolina Power and Light Co.

2 granted verbably by the Regional Administrator on May 15,1992 with the follow-ing understandings:

(1)

The waiver is for a single 24-hour period, which will occur during the current dual unit outage.

(2)

NRC (Region 11) will be notified by CP&L approximately 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months prior to proceeding with actual implementation of the modification.

j (3)

During the 24-hour waiver period, the units will remain in cold shutdown (Operational Condition 4) and other plant activities that have the potential for changing the levels of radioactive effluents released (i.e., fuel movements; grinding; cutting, or welding work relating to the primary containment; etc..) will be restricted.

(4)

As described in Enclosure 1 of your letter, alternative methods will be established for the monitorirg of changes to effluent releases and to account for effluent releases that might occur during the 24-hour waiver period.

Sincerely, i

A.sL.7//rA>

wart D. Ebne Jtegional Administrator i

cc:

R. B. Richey Vice President Brunswick Nuclear Project P. O. Box 10429 Southport, NC 28461 J. W. Spencer Plant General Manager Brunswick Steam Electric Plant P. O. Box 10429 Southport, NC 28461 (cc cont'd - See page 2)

Carolina Power and Light Co.

3 AIAY 15 532 (cc cont'd)

H. Ray Starling Manager - Legal Department Carolina Power and Light Co.

P. O. Box 1551 Raleigh, NC 27602 Kelly Holden I

Board of Commissioners P. O. Box 249 Bolivia, NC 28422 Chrys Baggett State Clearinghouse Budget and Management 116 West Jones Street Raleigh, NC 27603

'Dayne H. Brow n, Director Division of Radiation Protection N. C. Departme nt of Environment, Health & Natural Resources P. O. Box 27687 Raleigh, NC 27611-7687 H. A. Cole Special Deputy Attorney General State of North Carolina P. O. Box 629 Rale!gh, NC 27602 Robert P. Gruber Executive Director Public Staff - NCUC P. O. Box 295.20 Raleigh, NC 27626-0520

14 The Hydrogen Injection System for Unit 2 had been repaired and was fully operable at the time of this inspection.

The Hydrogen Injection-System for Unit 1 (referenced in paragraph 3.A of IR 50-325, -324/91-29) had been installed by Plant Modification (PM)86-080 and was partially operational.

Turnover and full-final operability of the Unit 1 Hydrogen Injection System was expected by early January, 1993.

The inspectors concluded that the licensee's HNC Program was being carefully evaluated to maximize its effectiveness.

No violations or deviations were identified.

12.

Temporary Waiver of Compliance for Main Stack Probe (84750)

On May 8, 1992, the licensee requested a temporary Waiver of Compliance to the requirements of TS 3.3.5.9, Table 3.3.5.9-1 to allow the Main Stack Radiation Monitor to be r

out of service without the performance of alternate sampling for a aing1e twenty-four period during the current dual-unit outage.

The action was requested to support the modification of the Main Stack Isokinetic Sampling Probe.

While the modification was taking place, the stack monitoring system would be inoperable and would preclude the alternate sampling required by TS Action Statements 123, i

i 123, and 127.

The primary containment purge and vent isolation functions of the main stack high radiation instrumentation would also be disabled during the work activities.

(This is an automatic function required by TSs in Operational Conditions 1, 2, and 3.)

The waiver was granted on May 15, 1992 with the following conditions:

The waiver was for a single twenty-four hour period during the current dual-unit outage.

The licensee was to notify the NRC (Region II) approximately forty-eight hours prior to implementation of the modification.

During the waiver period, both units were to remain in cold shutdown (Operational Condition 4) and any other plant activities which had the potential for changing the levels of radioactive offluents released (i.e.,

fuel movement; grinding, cutting, or welding work relating to the primary containment; etc.) were to be restricted.

r 15 Alternative methods for monitoring changes to effluent

)

releases and to account for any effluent releases which may occur during the waiver period were to be established.

The. inspectors were told that the modification had been completed.

Discussions with cognizant licensee personnel and review of the Shift Foreman's Log and the Outage Log confirmed that the four conditions had been satisfied.

Specifically, Region II was notified on July 20, 1992 that the work would begin on July 22.. The work began at 0826 hours0.00956 days 0.229 hours 0.00137 weeks 3.14293e-4 months on July 22 and was completed at 1626 hours0.0188 days 0.452 hours 0.00269 weeks 6.18693e-4 months of the same day, despite a severe thunderstorm which halted work for approximately an hour and a half.

An entry at 0827 hours0.00957 days 0.23 hours 0.00137 weeks 3.146735e-4 months in the Shift Foreman's Log dated July 22, 1592, showed that no fuel movement or other activities with pctential for altering levels of radioactive effluents released were allowed during the waiver period.

Furthermore, the log indicat6d that a pre-job briefing was held to authorize Engineering Evaluation Report (EER) 91-0358, which j

authorized the use of a grab sample before and after the' modification and used the higher of the two measured i

activities as though it had occurred during the entire modification time and added these results to the appropriate monthly /cr2arterly offluent report.

The inspectors concluded that the licensee had satisfied all conditions of the waiver during the modification of the Main Stack Isokinetic Sampling Probe.

No violations or deviations were identified.

13.

Solid Radioactive Waste Management (86750) 10 CFR 20.311 requires the licensee who transfers radioactive waste to a land disposal facility to prepare all waste so that the waste is classified in accordance with 10 CFR 61.55 and meets the waste characteristics requirements of 10 CFR 61.56.

It further establishes specific requirements for conducting a quality control program and for. maintaining a manifest tracking system for all shipments.

The inspector reviewed the licensees's solid waste management program for wastes generated from the Brunswick Steam Electric Plant (BSEP) operations.

The review included the following:

adequacy of implementing procedures to classify and characterize the wastes; preparation of the manifest and marking of packages; overall performance of the process control and quality control programs; and the adequacy of required records, reports, and notifications.

In addition, the inspector reviewed the methods used by the

7 N0TATION V0TE RESPONSE SHEET TO:

SAMUEL J. CHILK, SECRETARY OF THE COMMISSION FROM:

COMISSIONER ROGERS

SUBJECT:

SECY-92-184 - PROPOSED CHANGE TO THE GENERAL STATEMENT OF POLICY AND PROCEDURE FOR NRC ENFORCEMENT ACTIONS, 10 CFR PART 2, APPENDIX C APPROVED FEC@*- DISAPPROVED ABSTAIN NOT PARTICIPATING REQUEST DISCUSSION COMENTS:

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WITHHOLD VOTE

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ENTERED ON "AS" YES No en=% \\P

NOTATION VOTE RESPONSE SHEET TO:

SAMUEL J. CHILK, SECRETARY OF THE COMISSION FROM:

C0lHISSIONER DE PLANQUE

SUBJECT:

SECY-92-184 - PROPOSED CHANGE TO THE GENERAL STATEMENT OF POLICY AND PROCEDURE FOR NRC ENFORCEMENT ACTIONS, 10 CFR PART 2, APPENDIX C APPROVED X

DISAPPROVED ABSTAIN NOT PARTICIPATING REQUEST DISCUSSION COMENTS:

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RELEASE VOTE

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ML20078M647

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