Text

Responds to 930611 Memo Re Requested NRR Interpretation of Footnote in WNP-2 TS That Dealt W/Secondary Containment Established
	ML20079R505
Person / Time
Site:	Columbia
Issue date:	10/06/1993
From:	Adensam E; Office of Nuclear Reactor Regulation
To:	Perkins K; NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION V)
Shared Package
ML20078M603	List: ML20078M647; ML20078M696; ML20079R505; ML20079R685; ML20079R923;
References
	FOIA-94-167 TAC-M86762, NUDOCS 9310150241
	Download: ML20079R505 (3)
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Docket No. 50-397 HEMORANDUM FOR:

Kenneth E. Perkins, Director Division of Reactor Safety and Projects i

Region V FROM:

Elinor G. Adensam, Assistant Director for Region IV JL V Reactors Division of Reactor Projects !!!/IV/V Office of Nuclear Reactor Regulation

SUBJECT:

INTERPRETATION OF OPERATIONS WITH THE POTENTIAL. FOR DRAINING j

THE REACTOR VESSEL AT WNP-2 (TAC NO. M86762) l We are providing the NRR response to your memorandum to Jack Roe dated June 11, 1993.

Your memorandum, which followed extensive discussions with NRR staff and an E-mail request from Phillip H. Johnson dated June 3, 1993, j

requested NRR's inter)retation of a footnote in the WNP-2 technical specifications (TS) t1at dealt with having secondary containment established

"[W) hen irradiated fuel is being handled in the secondary containment and during CORE ALTERATIONS and operations with a potential for draining the j

reactor vessel." We have addressed this action as a Task Interface Agreement (TIA).

In the TS, the word " potential" means "something that exists in a state of potency or possibility for changing or developing into a state of actuality."

It follows from this definition that even though features are provided that reduce the likelihood of draining the reactor vessel, the potential for such draining can continue to exist. The operation described in your memorandum was the use of the residual heat removal (RHR) system to lower the water level in the reactor cavity. Two independent suction valves were designed to automatically isolate at a specified water level. However, since the failure of both is possible, this is an 'optration with a potential for draining the l

reactor vessel."

If the licensoc believes that any conditions described by " operations with a potential for draining the reactor vessel" should not requtre the 2

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establishment of secondary containment, a request for change to the TS along i

with justification (e.g. compensatory action) should be made to the staff.

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good avenue to propose the change is through the Owners Groups in the impicmentation of improved Standard Technical Specif'. cations.

i The NRR staff recognizes the generic applicability of this issue.

We are i

working with the BWROG to ensure a consistent definition for this 15.

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j Elinor G. Adensam, Assistant Director i

for Region IV & V Reactors 3

Division of Reactor Projects !!!/lV/V 1

Office of Nucicar Peactor Regulation i

cc:

C. Hehl, RI 1

f. Herschoff, Rif j

[. Creenman, Rill i

1. Gwynn, RIV

5. Varga i

G. Lainas 1

J. Calvo 1

J. Zwolinski

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Oc tober 6,1993 1

4 Kenneth E. Perkins establishment of secondary containment, a request for change to the TS along with justification (e.g. compensatory action) should be made to the staff.

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good avenue to propose the change is through the Owners Groups in the implementation of improved Standard Technical Specifications.

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The NRR staff recognizes the generic applicability of this issue. We are working with the BWROG to ensure a consistent definition for this TS.

Or qn n.il u oned by:

Elinor G. Adensam, Assistant Director i

for Region IV & V Reactors 1

Division of Reactor Projects Ill/IV/V Office of Nuclear Reactor Regulation cc:

C. lichl, RI E. Merschoff, Ri!

i E. Greenman, Rlll T. Gwynn, RIV S. Varga G. Lainas J

J. Calvo i

J. Zwolinski E. Rossi i

C. Grimes DJ11R_lEUJJSL4:

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/C/ 6 /93 DATE OfIIC1AL RECORD COPY DOCUMENT NAML:WNP86762.NEM s

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Docket No.:

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License No.:

DPR-32

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N0ED 93-2-006 ij by Virginia Electric and Power Company i

ATTN:

Mr. W. L. Stewart 0

i Senior Vice President - Nuclear M

i 5000 Dominion Boulevard Glen Allen, VA 23060

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Gentlemen:

1993 4

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SUBJECT:

NOTICE OF ENFORCEMENT DISCRETION FOR VIRGINIA ELECTRIC AND POWER j

COMPANY REGARDING SURRY UNIT 1 l

By letter dated October 21, 1993, you referred to your request for the U. S.

Nuclear Regulatory Commission (NRC) to exercise its discretion not to ereforce compliance with the required acticns in Technical Specification (TS) 3.12.C.3 which required inoperable control rod assemblies to be restored to operable status within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months or be in Hot Shutdown within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months .

The i

discretion would permit continued operation of Surry Unit 1 in POWER OPERATION for a period of 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months vice the 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months specified in TS 3.12.C.3 to effect troubleshooting and repairs to the Control Rod Driva System. By a telephone call 4

i on October 21,1993, at 1:00 p.m., you informed the NRC that Surry Unit I would not be in compliance with TS 3.12.C.3 which requires the plant to be in Hot Shutdown by 5:44 p.m. on October 21, 1993.

You provided as justification for continued operation that the affected Control Bank D control rod assemblies which were immovable on demand from the Control Rod Drive System were aligned, above j

the insertion limits, and trippable. In addition, the faulted condition did not affect the ability of the control rod assemblies to perform their intended safety function when a safety system setting is reached. As a compensatory action, you j

indicated that the power level will be maintained stable during the j

troubleshooting and repair activities.

i Based on our review of your justification, including the compensatory measure i

j identified above, we have concluded that this course of action involves minimum or no safety impact, and we are clearly satisfied that this exercise of

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enforcement discretion is warranted from a public health and safety perspective.

Therefore, we will not enforce compliance with TS 3.12.C.3 for the period 1

9:44 a.m. on October 21,1993, to 9:44 a.m. on October 24, 1993. This discretion was granted verbally by a telephone call from M.

V.

Sinkule, NRC, to M. L. Bowling, Virginia Electric and Power Company, on October 21, 1993. It is i

our understanding that you resolved the problem using only 1 of the 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months .

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OCT 2 21993 Virginia Electric and 2

Power Company Therefore this discretion has been terminated.

However, we will consider enforcement action, as appropriate, for the conditions that led to the need for l

this exercise of enforcement discretion.

Sincerely, I

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, y af.! f.$h Stewart D. Ebneter Regional Administrator cc:

M. L. Bowling, Jr., Manager Nuclear Licensing Virginia Electric & Power Company 5000 Dominion Boulevard Glen Allen, VA 23060 l

M. R. Kansler Station Manager Surry Power Station P. O. Box 315 Surry, VA 23883 i

Ray D. Peace, Chairman Surry County Board of Supervisors P. O. Box 130 Dendron, VA 23839 Dr. W. T. Lough Virginia State Corporation Commission Division of Energy Regulation P. O. Box 1197 Rich:nond, VA 23209 Michael W. Maupin Hunton and Williams l

Riverfront Plaza, East Tower 951 E. Byrd Street Richmond, VA 23219 l

l Robert B. Strobe, M.D., M.P.H.

State Health Comunissioner I

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

cc:

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Power Company cc:

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Attorney General i

Supreme Court Building 101 North 8th Street Richmond, VA 23219 i

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the 44Y, value and that reactor power be controlled to minimize 4

level oscillations.

The C SG level setpoints were returned to the 44, value and reactor power was lowered to 987, and level os'.111ation was reduced to the pre-test value. The inspectres continued to 4

monitor the licensee's corrective actions in this area and will review any C SG planned outage related activities, i

d.

Notice of Enforcement Discretion Negef #[f-5-f /W On October 21, the NRC granted Enforcement Discretion to TS 3.12.C.3 for Unit 1 only. On October 21, the Unit 1 Bank D control rod assemblies became inoperable when a rod control system urgent failure alarm occurred when operators were performing 1-PT-f 6, Control Rod Assembly Partial Movement. TS 3.12.C.3 requires that inoperable control rod assemblies be restored to operable

,4 status within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months or that the plant be put into a hot shutdown p

condition within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months . The discretion permitted 5

continued operation of Surry Unit 1 in Power Operation for a D

period of 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months versus the 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months specified in TS 3.12.C.3.

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This additional time was projected to allow troubleshooting and possible repairs to the Control Rod Drive System.

Although the 1

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1 Bank D control rod assemblies were immovable on demand from the i

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Control Rod Drive System, the ability of the control rod

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assemblies to perform their intended safety function (trip into the core) when a safety system setting was reached was not 4

k'I effected. A biown fuse was identified as the cause of the rod i

l control system urgent failure alarm which resulted in the immovable Bank D control rod assemblies. The fuse was replaced and the control rods were satisfactorily tested in accordance with 1-PT-6. The Control Rod Drive System was returned to operable J

i status appr imately one hour after the Notice of Enforcement i

Discretic as Iverbally approved by the NRC.

Wa-s.

Since rod control system failures appear to be a continuing problem, the NRC requested the licensee discuss their assessment of previous failures with NRC management. The inspectors continue i

to monitor the licensee's rod control system reliability improvement activities and are currently reviewing the RCM study i

of that system and the status of implementing any recommended corrective actions.

Unit 1 B Accumulator In-Leakage e.

On October 9 and 15, 1993, sample analyses from the Unit 1 B i

accumulator revealed that the boron concentration was less than l

the minimum required by TS.

It was suspected that back leakage J

from the RCS through the accumulator check valves diluted the boron concentration in the accumulator.

TS 3.3.8 states that any i

one of the following SI components may be inoperable at any one l

time and that if the condition is not restored within the allowed 1

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NUCLEAR REGULATORY COMMISSION UNITED STATES 3

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DEC 191993 i

Docket No.:

50-281 i

License No.: DPR-37

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NOED 93-2-008 i

FR Virginia Electric and Power Conpany

.* t ATTN:

Mr. W. L. Stewart n

Senior Vice President - Nuclear 5000 Dominion Boulevard Glen Allen, VA 23060 Gentlemen:

SUBJECT:

NOTICE OF ENFORCEMENT DISCRETION FOR VIRGINIA ELECTRIC AND POWER COMPANY REGARDING SURRY UNIT 2 By letter dated December 15, 1993, you referred to your request for the U. S.

Nuclear Regulatory Commission (NRC) to exercise its discretion not to enforce compliance with the required actions in Technical Specification (TS) 3.12.C.3 which required inoperable control rod assemblies to be restored to operable status within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months or be in Hot Shutdown within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months . The discretion would permit continued operation of Surry Unit 2 in POWER OPERATION for an additional 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months over the the 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months specified in TS 3.12.C.3 to effect troubleshooting and repairs to the Control Rod Drive System.

By a telephone call on December 15,1993, at 11:00 a.m., you infonned the NRC that Surry Unit 2 would not be in compliance with TS 3.12.C.3 which requires the plant to be in Hot Shutdown by 4:37 p.m. on December 15, 1993.

You provided as justification for continued operation that the affected control rod assemblies, which were immovable on demand from the Control Rod Drive System, were trippable. Hence, the faulted condition did not affect the ability of the control rod assemblies to perform their intended safety function when a safety system setting is reached.

In addition, existing analyses established that power and peaking distributions used in the safety analysis were unaffected with any bank of control rod assemblies inserted up to IB steps.

This bounds the present configuration, i.e., Shutdown Bank A Group 2 control rod assemblies inserted 3 steps. As a compensatory action, you indicated that the power level would be maintained stable during the troubleshooting and repair activities.

Based on our review of your justification, including the compensatory measure identified above, we have concluded that this course of action involves minimum or no safety impact, and we are clearly satisfied that this exercise of enforcement discretion is warranted from a public health and safety perspective. Therefore, we will not enforce compliance with TS 3.12.C.3 for the period from 10:37 a.m. on December 15. 1993,to 10:37 a.m. on December 16, 1993. This discretion was granted by the Deputy Regional Administrator and verbally conveyed to D. A. Sommers, Virginia Electric and Power Company, by G. A. Belisle, NRC, on December 15, 1993.

It is our understanding that you resolved the problem and exited the TS 3.12.C.3 action statement at 3:06 p.m.

DEC 161993 Ele ric and 2

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on December 15, 1993.

Therefore, this discretion has been terminated.

However, we will consider enforcement action, as appropriate, for the conditions that led to the need for this exercise of enforcement discretion.

Sinc ely, j

/w Stewart D. E t

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Regional Admini rator cc:

M. L. Bowling, Jr., Manager Nuclear Licensing Virginia Electric & Power Company 5000 Dominion Boulevard Glen Allen, VA 23060 M. R. Kansler Station Manager Surry Power Station P. O. Box 315 i

Surry, VA 23883 Ray D. Peace, Chaiman Surry County Board of Supervisors i

P. O. Box 130 Dendron, VA 23839 l

Dr. W. T. Lough I

Virginia State Corporation Comission Division of Energy Regulation P. O. Box 1197 Richmond, VA 23209 Michael W. Maupin Hunton and Williams Riverfront Plaza, East Tower 951 E. Byrd Street Richmond, VA 23219 1

Robert B. Strobe, M.D., M.P.H.

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

Cont'd see page 3

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N Docket Nos. 50-280, 50-281 License Nos. DPR-32, DPR-37

-'un Virginia Electric and Power Company ATTN: Mr. W. L. Stewart Senior Vice President - Nuclear 5000 Dominion Boulevard Glen Allen, VA 23060 Gentlemen:

i

SUBJECT:

NRC INSPECTION REPORT N05. 50-280/93-30 AND 50-281/93-30 This refers to the Nuclear Regulatory Commission (NRC) inspection conducted by.

Mr. M. Branch of this office on December 5,1993, through January 1,1994.

The inspection included a review of activities authorized for your Surry facility. At the conclusion of the inspection, the findings were discussed with t'.wse members of your staff identified in the enclosed 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.

P Within the scope of the inspection, no violations or deviations were identified.

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

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

Sincerely, OY

',_ "b Marvin V. Sinkule, Chief Reactor Projects Branch 2 Division of Reactor Projects

Enclosure:

NRC Inspection Report cc w/ encl:

(See page 2) kD M

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Virginia Electric & Power Company 2

M 27 M cc w/ enc 1:

M. L. Bowling, Jr., Manager Nuclear Licensing 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 Ray D. Peace, Chairman Surry County Board of Supervisors i

P. O. Box 130 Dendron, VA 23839 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 Riverfront Plaza, East Tower 951 E. Byrd Street l

Richmond, VA 23219 l

Robert B. Strobe, M.D., M.P.H.

State Health Commissioner Office of the Commissioner Virginia Department of Health l

P. O. Box 2448 Richmond, VA 23218 Attorney General Supreme Court Building 101 North 8th Street Richmond, VA 23219

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NUCLEAR REGULATORY COMMISSION l

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'4 REGION 11 101 MARIETTA STREET. N.W., SUITE 2900 l

ATLANTA. GEORGIA 3EI234190 1

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Report Nos.:

50-280/93-30 and 50-281/93-30 1

Licensee: Virginia Electric and Power Company 5000 Dominion Boulevard i

Glen Allen, VA 23060 i

l Docket Nos.:

50-280 and 50-281 License Nos.:

DPR-32 and DPR-37 Facility Name:

Surry 1 and 2 Inspection Conducted: December 5, 1993 through January 1, 1994 l

Inspectors:

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M.W.y'oranch, Senior Resident Dtte Signed j

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//24/fY J. W. Verk, Resident Inspector Date Signed L. A

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//M /H S. G. Tlngen, Resident Inspector Date Signed-Approved by:

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G.' A. Belisl O ection Chief D&te Signed Division of Reactor Projects SIM1ARY Scope:

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

status, operational safety verification, maintenance inspections, balance of plant inspections, review of plant modifications, and action on previous inspection items.

While performing this inspection, the resident inspectors 4

conducted reviews of the licensee's backshifts, holiday or weekend operations on December 10, 12, 19, 22, and 28, 1993.

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2 Results:

Operations functional area:

Adequate implementation of the freeze protection program was noted (paragraph 3.b).

Maintenance functional area:

Repetitive process vent Kaman radiation monitor problems continued to occur throughout 1993.

The licensee's trending programs have identified this as a recurring problem.

Corrective actions have been implemented and plans to I

implement additional corrective action were ongoing (paragraph 4.a).

Enoineerino functional area-Station Nuclear Safety Operating Committee review of a safety evaluation identified an area that required additional engineering analysis. This analysis resulted in a procedural change for injecting temporary leak sealant into the packing of the Unit 2 loop fill control valve (paragraph 4.b).

An unresolved ites was identified associated with the fire barrier adequacy (i.e., HER-5 chiller cable protection), pending demonstration by the licensee i

l that the installation and design meets commitments to and regulatory requirements of 10 CFR, Part 50, Appendix R (paragraph 6).

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REPORT DETAILS i

1.

Persons Contacted l

Licensee Fmnlovees

W. Benthall, Supervisor, Licensing l

R. Bilyeu, Licensing Engineer j-H. Blake, Jr., Superintendent of Nuclear Site Services a

R. Blount, Superintendent of Maintenance i

D. Christian, Assistant Station Manager J. Costello, Station Coordinator, Emergency Preparedness

J. Downs, Superintendent of Outage and Planning D. Erickson, Superintendent of Radiation Protection A. Friedman, Superintendent of Nuclear Training

B. Hayes, Supervisor, Quality Assurance

M. Kansler, Station Manager C. Luffman, Superintendent, Security 3

J. McCarthy, Superintendent of Operations

A. Price, Assistant Station Manager j

R. Saunders, Assistant Vice President, Nuclear Operations j

E. Smith, Site Quality Assurance Manager

T. Sowers, Superintendent of Engineering J. Swientoniewski, Supervisor, Station Nuclear Safety

G. Woodzell, Nuclear Training l

NRC Personnel

M. Branch, Senior Resident Inspector

5. Tingen, Resident Inspector

J. York, Resident Inspector

Attended Exit Interview l

Other licensee employees contacted included control room operators, j

shift technical advisors, shift supervisors and other plant personnel.

l Acronyms and initialisms used throughout this report are listed in the l

last paragraph.

2.

Plant Status Unit 1 began the reporting period at 80% power on day 31 of the power coastdown for refueling. On December 21, power was reduced from 72% to i

approximately 625 in order to remove one tanden drive motor from one of the two main feedwater pumps for use on Unit 2.

The unit operated at 62% power for the remaining period, limited by only one MFWP.

The j

refueling outage is still scheduled to commence on January 21, 1994.

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I Unit 2 began the reporting period at 100% power. On December 22, power j

was reduced to approximately 60% in order to replace a main feedwater i

pump motor that was experiencing vibration problems. After the Unit 1 i

motor was installed in Unit 2, the unit was returned to 100% power on l

December 25.

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3.

Operational Safety Verification (71707, 42700) 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 i

operator logs on a daily basis to verify operational safety and compliance with TSs and to maintain overall facility operational awareness.

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 j

programs, radiological work practices, plant security programs and i

housekeeping. Deviation reports were reviewed to assure that potential j

safety concerns were properly addressed and reported.

a.

Unit 2 Control Rod Drive System Urgent Failure Alarm and N0ED I

On December 15, at 8:37 a.m., a rod control system urgent failure l

occurred on Unit 2 during scheduled control rod exercising. The i

urgent failure rendered group 1 rods powered from cabinet (2-RC-

)

CAB-1AC) immovable (TS inoperable). The rods affected included j

group 1 rods in SDB "A" as well as CB "A" and "C".

In SDB "A",

the first bank tested, the four group 2 rods had inserted three steps into the core while the four group 1 rods that were also i

selected remained fully withdrawn. At 8:37 a.m., a LCO was entered in accordance with TS 3.12.C.3.

TS 3.12.C.3 required that inoperable control rod assemblies be restored to operable status within two hours or that the plant be put into a hot shutdown condition within the next six hours.

I Initial troubleshooting began inmediately and was witnessed by the inspectors. This troubleshooting involved looking for lit indicator lamps or blown fuses as well as taking electrical reading at test points inside the rod control cabinet. There were l

no lit indicator lights or indication of blown fuses and the electrical readings appeared normal.- The K-2 failure detector j

card appeared loose (i.e., about 1/8-inch from fully seated).

i This card was removed, reinstalled, and additional electrical l

measurements made with no change in readings noted. The K-2 card was replaced and again there was no noted change in electrical readings. The old card was reinstalled. However, when the I-2 card, removed to ensure the gripper coils would stay de-energized i

during troubleshooting, was reinserted, I&C personnel noted that lights on the J-1 failure detector card began flashing. The J-1 1

card was replaced and the urgent failure reset. After realigning

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the SDB "A" rods to fully withdrawn per a temporary change to the i

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perform therod realignment proced 3

After determining th rod exercise PT. e perators ure, th not be o

requested enforcement dcompleted within theat furthe The attempted to again acti The NRC verbally iscretion.on time o ing and repairsreoccurred.

for Unit 2 oniy du i of granted enforcement di the TS, the licens 1993 could W1 f r g a telephone The disr :tten n

ee enforcement discretion for scretion from TS e ion permitted contin a peri conference on December.12.C.

3.12.C.3. ce cf 3

additional 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months versus the t ued operationwas issued the Althoughtroubleshooting a d Yhe 15 next day, was projectedwo hoursof Geit 2 at powe.

time n

the the Control repairs to the Control R Rod Drive System thcontrol r d assemblie specified assemblia r

o to allow in TS the core. s to perform their intended ability ofwere immovableod Drive System.

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a safety system Additional trouble hsetting wassafety function (rol rodon de the cont revealed reached was trip into that the s

capacitors that were ooting after the not removed J-1 failure d card had masked the p second urgent failur The roblem that causednot correctly soldered the failuresecond urgent etection failure resulted i e

the first urgent fThis defective circuitry occurred in the phas circuit w.

Both the phase n the J-l card indi ere Controlsatisfactorily testedreplaced and control and firing cae "C" stationary ailure.

the grippercating that Rod Assembly Partial System accordancecontrol rods rds for this in was on the December 15 returned to were wit Movement. h periodic test 2 PTrealigned and service furtherThe inspectors This NOEDisand the LCOThe Control

-6 with examplesnoted that theseconsidered closedterminated at 3:06 Rod Drive concernsthe Control Rod Drive Systemof continuing equipmrod equipm p.m.

Level with the Station Manager.

1 priority had bee ent malfunctions s were failures The inspectors discassociated licensee's and make who indicated n pened for o

current schedule for thirecommendations fo review ussed should be engineering tothat a Stationtheir 2 improvementsimprovements during completed in time to s projectmprovements. review past September 1994 the The allow for the impleme tindicates that t should be factored (int upcoming January 1994) Unit 1 Cold Weather Prote t o the RFO. n ing licenseeDuring a plant c ion (71714) next RF0, scheduled f Unit tour or Severe Weather OCwas performing operation December 12, the i the f rains,ollowing fore, cast weatherdated September 7 check lisnsp ons extreme

, 199 noted conditions:3. t procedureThis procedure. OC cold and/or heavy sno that the no high winds w, and severe hot weathand/or heavy covers er.

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High winds and freezing weather had been forecast for this period l

of time.

High winds and below freezing temperatures were expected i

in the area and operations, maintenance, etc., used this procedure i

to ensure that proper preparations have been made for the expected i

inclement weather.

i 1

In addition, the inspectors discussed the nomal freeze protection j

program with the licensee. This program was implemented by i

monthly performance (October through March) of STP-52, Cold 1

Weather Protection, dated April 3, 1992. This procedure contained i

a detailed checklist of areas and components that need to be l

routinely inspected to ensure that there was adequate protection j

i te prevent freezing. This procedure, STP-52, was perfonned by both operations and maintenance personnel. Deficiencies that were noted while perfonning STP-52 were documented and discrepancy j

reports / work requests were written to schedule corrective action, j

On December 20, the inspectors reviewed the latest deficiency list and noted that they were either complete, being worked, or 1

i scheduled. Walkdowns of exposed areas susceptible to freezing was conducted by the inspectors. No discrepancies were identified i

that would indicate that the program was not being adequately j

implemented.

f l

Within the areas inspected, no violations were identified.

4.

Maintenance Inspections (62703, 42700)

During the reporting period, the inspectors reviewed the following l

maintenance activities to assure compliance with the appropriate j

procedures.

a.

Process Vent Radiation Monitor 1

i During this inspection period the inspectors reviewed the reliability of the Kaman process vent high range affluent monitors.

Previous irs have addressed recurring problems with the Kaman radiation monitors. Most recently, IR 93-23 addressed 4

i l

spiking on the Kaman ventilation vent effluent monitor 1-VG-RI-l (TS Table 3.7.6 Item 12).

l TS Table 3.7.6, specified operability requirements for accident monitoring instrumentation.

Itse 11 of this table specified operability requirements for the process vent high range effluent radiation monitors. Kaman radiation monitors 1-GW-RM-130-1/2 l

fulfill this requirement. Whenever these radiation monitors are i

declared inoperable, an alternate method for monitoring the process vent effluent was implemented in accordance with TSs.

i The process vent Kaman radiation monitors have a history of l

operational problems.

In 1991, approximately 11 DRs were written due to operational problems. Ten DRs were written in 1992.

i l

3 3,

i j

5 Twenty DRs were written in 1993.

Recurring problems associated with these radiation monitors involved defaulting setpoints, the i

iodine / particulate sample becoming saturated with water, check source failures, and miscellaneous other problems.

The licensee's i

trending programs have identified this as a recurring problem.

j Corrective actions have been implemented and plans to implement i

additional corrective action are ongoing. The inspectors will continue to monitor the performance of the process vent Kaman j

radiation monitors in order to evaluate the corrective action's 1

effectiveness.

)

b.

Valve Packing Repair with Temporary Leak Sealant-l TS 4.ll.A.4 and 3.3.A.12 specify that total system uncollected j

leakage from SI system valves, flanges, and pumps located outside 4

of containment not exceed 3836 cc/hr. The SI system leakage is i

monitored-by performing periodic testing and walkdowns.

System i

leakage measurements are recorded and tracked in accordance with procedure 2-NPT-ZZ-001, Quantifying of System External Leakage.

i j

While performing a system leakage inspection on December 23, i

operators identified a significant leak rate coolant increase from j

the packing of the Unit 2 loop fill control valve,- 2-CH-FCV-2160.

The packing leak rate which was previously identified as 6 cc/hr i

had increased to 1800 cc/hr. On December 27, the coolant leak rate from the packing increased to 3120 cc/hr.

Leakage from the remaining components in the SI system was very low and therefore the system's total leakage rate remained below the TS maximum i

value of 3836 cc/hr.

4 On December 31, the loop fill control valve packing leak was j

stopped by injecting a temporary leak sealant into the packing 1

area. This maintenance was accomplished by WO 260090-3 and l

procedure 0-MCM-1918-01, On Line Repairs. The inspectors reviewed the procedure and verified that there were provisions for limiting i

the amount of leak sealant injected into the packing area and I

restricting the leak sealant injection pressure.

The inspectors 1

also reviewed the work history dating back to 1991 for the Unit 2 l

loop fill control valve and verified that the valve had not i

previously been injected with a temporary leak sealant.

The valve i

was repacked during the previous Unit 2 1993 RF0.

The inspectors also verified that there was a WR initiated to return the valve to j

it's original condition.

j The loop fill control valve is a containment isolation valve that l

is normally closed and not repositioned while the plant is

{

operating.

Injecting temporary leak sealant into the. packing area j

precluded further valve operation.

SE 93-246, dated December 30, j

was prepared to evaluate operating the unit with the loop fill control valve permanently shut. The SE concluded that it was acceptable to operate the unit in this condition until the next i-

- = - -

l-6 l

RFO. The inspectors reviewed SE 93-246 and attended the initial i

SNSOC meetings that reviewed the SE. The inspectors noted that l

the SE was not initially approved by SNSOC. SNSOC had qu6stioned i

if the design pressure rating of the packing leak off piping was evaluated when detemining the maximum temporary leak sealant s

injection pressure. The packing leak off piping was the injection i

point for the temporary leak sealant and the design pressure of this piping was not originally evaluated. As a result of $NSOC questioning, the maximum temporary leak sealant injection pressure I

was reevaluated and lowered. The SE was subsequently approved by l

SNSOC. The inspectors concluded that the initial engineering f

review for the temporary leak repair was incomplete. However, the SNSOC review and approval added value to the leak repair process, j

resulting in an acceptable temporary repair.

Within the areas inspected, no violations were identified.

j 5.

BOP Inspection (71500) i The inspectors conducted tours of selected TB and other plant areas l

susceptible to flooding. During these tours, the inspectors verified j

the availability of the non-safety related TB sump pumps which the licensee relies upon to mitigate certain flooding scenarios.

Additionally, the inspectors were sensitive to any work activities that 1

would increase the possibility of TB flooding such as openings in the condenser waterboxes or piping systems On December 29, the inspectors witnri d the licensee performing maintenance associated with replacing fB sump pump 1-PL-P-2F discharge i

isolation valve 1-PL-12. This maintenance was accomplished in j

accordance with WO 279713-04.

In order to accomplish this maintenance, the power supplies to three of the nine TB sump pumps were danger tagged in the off position. The three TB sump pumps were inoperable for j

approximately 2.5 hours5.787037e-5 days 0.00139 hours 8.267196e-6 weeks 1.9025e-6 months while the maintenance was perfomed.

i j

Previous licensee commitments to the NRC stated that at least seven of i

the nine TB sump pumps would be operable. The licensee reevaluated the l

IPE calculations and concluded that for short periods of time it was j

acceptable to have at least six TB sump pumps operable.

Installing improved SW expansion joint spray shields was one of the contributors in j

reducing the critical flood flow rate which allowed operating with six TB sump pumps. The licensee was drafting a letter to the NRC revising j

their commitment.

l The inspectors concluded that 1-PL-12 replacement was accomplished in i

accordance with the licensee's procedures for minimizing the impact of i

flooding in the TB.

Within the areas inspected, no violations were identified.

j i

l

l.

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i 7

6.

Review of Plant Modifications (37828)

The inspectors have been closely monitoring the plant modification to i

improve the reliability of the control room and emergency switchgear i

room chillers.

This project is commonly referred to as the MER-5 modification. The modification basically consisted of constructing a i

seismic structure to contain two additional chiller units with their i

support systems. Additionally, the modification added flexibility to j

the power supplies for the two new and the three existing chiller units.

f On December 28, the inspectors witnessed / reviewed two activities j

associated with the MER-5 modification. The first involved a freeze seal to allow valve replacement and tying chill water to one of the l

three existing chillers. The second involved installing 3-M fire wrap i

over cables and conduit in order to establish fire separation between the two electrical trains that power the chiller units.

A j

The freeze seal was installed using WO 262059-08 and was controlled by procedure 0-MCM-1918-03 revision 0, Freeze Seal of Piping. The j

procedure required that a SE be perforined and approved by SNSOC. The inspectors reviewed the SE (93-239A) and found it acceptable.

The i

piping being frozen was 3-inch diameter carbon steel piping. The j

inspectors noted that the piping surface in the freeze seal vicinity was very rusty and would be difficult to perform the NDE required prior to freeze seal installation. The Site Services personnel working the job showed the inspectors IPR 93-431 that documented the surface condition and provided the engineering disposition of the concern prior to the freeze seal installation. Specifically, surface grinding to smooth the i

area being frozen was performed followed by a successful NDE of the area.

1 The conduit fire wrap was being installed per DCP 90-07. The fire

{

barrier being installed on the conduit that housed "H" bus power supply cables was necessary since the "H" bus conduit was routed through the "J" bus switchgear room within approximately 1-2 feet of the switchgear.

10 CFR 50, Appendix R requires that train (bus) separation be j

established by physical distance (20 feet), or by 3-or 1-hour fire barriers depending on the specific circumstances. The stated purpose of the modification was to provide a 1-hour fire barrier between the two electrical power trains.

i The inspectors reviewed the work package at the job site and noted that i

the 3-M installation / qualification instructions discussed a

{

configuration that was different from that being installed. The 3-M i

qualification for a 1-hour fire rating described a three wrap system for j

< 5 inch aluminum conduit, consisting of two wraps of E-53 and one wrap 4

of E-54. The system being installed consisted of three wraps of E-54 which was described by the licensee and their contractor as thicker material than the E-53 wrap. The inspectors requested verification that the actual installation configuration of 3 wraps of 3-M E-54 was bounded by test reports from the vendor.

f 1

8 The inspectors were provided a copy of a memorandum from the corporate fire protection engineer to Site Engineering.

This memorandum contained the engineering evaluation for qualifying three wraps of E-54 material.

The basis for the fire wrap qualification configuration being installed was stated to be several 3-M test reports.

However, fire test report no. 3MFT87-11, which was described as the closest to the actual installation, in a memorandum from PROMATEC, the licensee's contractor, was not referenced. The inspectors requested a copy of fire test report no. 3MFT87-11 for review.

The above referenced memorandum also contained engineering evaluation no. 25 titled, " Evaluation of Lack of an Automatic Fire Suppression System in Unit 2 Emergency Switchgear Room Surry Power Station". The evaluation's purpose was to allow using 1-hour fire barrier (i.e., 3 layer fire wrap on power supply cables for the chiller units).

The original design had specified a 3-hour fire barrier (i.e., 5 wraps of 3-M material) for the cables in question but, because of space considerations, only 3 wraps could be installed.

The evaluation referenced 10 CFR 50, Appendix R, section III.G.2.c requirement that stated that two trains of safe shutdown cables could be separated by a 1-hour rated fire barrier, with fire detection and an automatic fire suppression system installed in the area.

The licensee's evaluation was addressing the fact that the emergency switchgear room, where the cables in question were located, was equipped with a manual not automatic fire suppression Halon system.

10 CFR 50, Appendix R, section III.G.2.c would require a 3-hour barrier for this area and an exemption would be necessary.

During subsequent discussions, the licensee produced a Surry Appendix R Report that states that the emergency switchgear rooms for Units 1 and 2 (fire zones 3 and 4) only had to meet the requirements of 10 CFR 50, Appendix R, section III.G.3 in lieu of III.G.2.c since remote shutdown capability existed.

Section III.G.3 only required a fixed suppression system and did not require it to be automatic. Additionally, train separation was not specified.

Based on the conflicting data, it was unclear as to the fire protection and cable protection design requirements for this area.

The fire protection design engineer stated that for new installations, III.G.2.c requirements were desired. Since the control room and emergency switchgear room chiller system were common to both units, the inspectors questioned the licensee as to whether the system would be needed to cool equipment that was relied upon for remote / alternate shutdown. Thereby, it would be required to meet the requirements of III.G.2.c (i.e., protected by a 3-hour barrier or 1-hour barrier with automatic fire detection and suppression).

The inspectors requested additional information and historical correspondence as to the design requirements for protecting the cable in question. This item is identified as URI 50-280, 281/93-30-01, HER-5 Power Supply Cables Fire Barrier Adequacy, pending demonstration by the licensee that the installation and design meets comitments to and regulatory requirements of 10 CFR 50, Appendix R.

Additionally, 3-M

W 9

fire test report 3MFT87-11 has not been provided by the licensee or reviewed by inspectors. The licensee has elected to maintain a fire watch in the area until this issue is resolved.

Within the areas inspected, no violations were identified.

l 7.

Action on Previous Inspection Items (92701, 92702) a.

Closed VIO 50-280,281/92-07-03, Failure To Prevent Foreign Material From Entering SW System. When flow testing the Unit 1 RSHXs during the 1992 Spring RF0, it was identified that the flow rate through RSHX 1-RS-E-1B was low.

Inspection of the heat exchanger revealed that a rain jacket and rain pants were present in the tubesheet area which restricted the flow of SW.

It was concluded that the rain gear was inadvertently left in the system during maintenance that was performed during the previous fall 1990 RFO.

In a letter dated May 29, 1992, the licensee responded to this violation. The cause of this event was attributed to inadequate implementation of FME controls during the maintenance As corrective performed on the RSHX system during the 1990 RFO.

action VPAP-1302, Foreign Material Exclusion Program, was implemented after the Fall,1990, Unit 1 RF0 to establish station wide FME controls.

In addition, VPAP-1302 was revised following rain gear identification to further er. hance the FME program by requiring additional requirements for documenting closecut inspection results. The inspectors reviewed VPAP-1302, revision 3, and verified that the corrective actions in response to violation were implemented.

b.

Closed VIO 50-280,281/92-13-01, Failure to Perform Safety Evaluations for Procedures That Were Used to Operate Plant Systems Differently Than Described in the UFSAR. This issue involved three examples in which the licensee operated plant systems in a different manner than described in the UFSAR but had not first prepared written safety evaluations pursuant to 10 CFR 50.59. The licensee responded to this violation in a letter dated July 31, 1992. As corrective action, safety evaluations were prepared for each of the examples identified. The inspectors reviewed SEs 92-126, dated June 4, 1992,92-127, dated June 4, 1992 and 92-171, dated July 22, 1992.

SEs 92-171 and 92-127 identified that l

additional procedural controls were necessary. The inspectors reviewed procedures 2-0P-49.7, Filling and Draining RSHX Service Water Supply Piping, revision 2 and 0-0PT-FP-005, Fire Protection l

l Water Pumps, revision 1 and verified that the additional procedural controls were properly incorporated.

Within the areas inspected, no violations were identified.

i.

j 1

i 10 8.

Exit Interview 1

l The inspection scope and findings were summarized on January 4, 1994, with those persons indicated in paragraph 1.

The inspectors described the areas inspected and discussed in detail the inspection results listed in the front of the report and those listed

>elow.

i Description i

Ites Number ILg.tgi (Parmaraoh No.)

URI 50-280, 281/93-30-01 Open MER-5 Pouer Supply Cable Fire i

Barrier Adequacy i

(paragraph 6).

1 i

VIO 50-280, 281/92-07-03 Closed Failure To Prevent Foreign j

Material From Entering SW System (paragraph 7.a).

i VIO 50-280, 281/92-13-01 Closed Failure to Perform Safety j

Evaluations for Procedures That Were Used to Operate i

Plant Systems Differently Than l

Described in the UFSAR 4

(paragraph 7.b).

I Dissenting comments were not received from the licensee.

Proprietary l

information is not contained in this report.

i l

9.

Index of Acronyms and Initialisms t

i B0P BALANCE OF PLANT I

CB C')NTROL BANK CC/HR -

CUBIC CENTIMETERS PER HOUR DCP DESIGN CHANGE PACKAGE DR DEFICIENCY REPORT ECCS EMERGENCY CORE COOLING SYSTEM FME FOREIGN MATERIAL EXCLUSION I&C INSTRUMENTATION AND CALIBRATION IPE INDIVIDUAL PLANT EXAMINATION IPR INSTALLATION PROBLEM REPORT INSPECTION REPORT IR i

LC0 LIMITING CONDITIONS OF OPERATION j

MER MECHANICAL EQUIPMENT ROOM MAIN FEED WATER PUMP J

MFWP NDE NONDESTRUCTIVE EXAMINATION NOTICE OF ENFORCEMENT DISCRETION j

N0ED NUCLEAR REGULATORY C0f011SSION i

NRC i

OC OPERATIONS CHECKLIST 3

PT PERIODIC TEST RF0 REFUELING OUTAGE RECIRCULATION SPRAY RS i

1

i II RSHX RECIRCULATION SPRAY HEAT EXCHANGER SDB SHUT DOWN BANK SE SAFETY EVALUATION SI SAFETY INJECTION SNSOC -

STATION NUCLEAR SAFETY AND OPERATING C0fMITTEE SW SERVICE WATER TB TURBINE BUILDING TS TECHNICAL SPECIFICATION UFSAR -

UPDATED FINAL SAFETY ANALYSIS REPORT URI UNRESOLVED ITEM VIO VIOLATION WO WORK ORDER WR WORK REQUEST I

i

/

f4 h*Omme"f)2

- WASHINGTON D.C. 3M54001 UNITEDTTATES fi[.j NUCLEAR REGULATORY COMMISSION j

gm November 10, 1993 I

Docket No. 50-339 I

NOED No. 93-6-026 i

1 Nr. W. L. Stewart kN7 Senior Vice President - Nuclear i

Virginia Electric and Power Company 5000 Dominion Blvd.

l Glen Allen, Virginia 23060 l

Dear Nr. Stewart:

SUBJECT:

NOTICE OF ENFORCENENT DISCRETION FOR VIRGINIA CONPANY (VEPCO) REGARDING THE NORTH ANNA POWER STATION (NA-2) i This letter provides documentation of our oral granting of enforcement i

discretion on November 8,1993.

Your staff informed the U.S. Nuclear i

Regulatory Counission (NRC) on November 8, 1993, that NA-2 was not in j

compliance with Technical Specification (TS) 4.5.2.h.1.

This TS contains specifies the flow values. surveillance requirements for high head safety injec By letter dated November 9 1993, you provided a written request for i

enforcement discretion rega,rding the surveillance requirements in the NA-2 T 4.5.2.h.1. for 1) a 24-hour period to readjust the seal injection flows to the i

reactor coolant pumps in order to meet the total pump flow rate in TS l

4.5.2.h.1. of s 660 gps, and 2) to eliminate the simulated reactor coolant situation was created when inaccuracies in the flow measure This instrumentation used for the surveillance test were discovered.

provided the following as justification for continued operation. Your letter i

The total pump flow rate of s 660 gpu is specified in the TS to ensure that the pumps do not exceed flow capacity and protect against pump runout.

as-left total pump flow rate could have been as high as 670 gpe.

The manufacturer's actual runout limit is 675 gym and original manufacturer The testing demonstrated pump perfonsance to approximately 700 gpe.

period was granted to lower seal injection flow to bring total pump flow rate A 24-hour i

within TS limits.

NA-2 entered an action statement at 14:45 on i

i November 8, 1993 The 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months were, required to revise affected procedures i

and to document the supporting engineering calculations.

.l 4

i DM N hp

i i.

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l.

Mr. W. L. Stewart

- 2.--

Nsv:ab:r 10, 1993 i

i*

A recent license amendment issued on August 4, 1993 added TS 4.5.2.h.l.c, 4

specifying a specific range'of calculated values for seal injection flow to be j

used during the actual flow balancing process.

The design basis accident i

analysis takes no credit for this flow.

By meeting TS 4.5.2.h.1.a and b, the j

limits of the safety analysis are met with margin.

The requirement to specify i

a simulated seal injection flow rate has inhibited the ability to meet the j

minimum and maximum flow rate specifications.

1 The capability of the system to perform its emergency core cooling system i

design function is not affected and the system performance will remain bounded j

by the existing safety analysis. Compensatory measures, including revisions i

to operating procedures and logs, and shift briefings to inform operators of the change, have been implemented to ensure that the intent of the TS j

continues to be met.

f On the basis of our review of your justification, including any compensatory measures identified above, the staff has concluded that this course of action j

j involves minimum or no safety impact, and we are clearly satisfied that this exercise of enforcement discretion is warranted from a public health and j

j safety perspective. Therefore, it is our intention to exercise discretion not to enforce compliance with TS 4.5.2.h.l. until the staff can process a change 1

to your TS on an emergency basis.

In addition, a one-time enforcement j

discretion allowing 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months to adjust seal injection flow was granted as j

discussed above.

It is our understanding that you will submit the request for j

TS change by November 12, 1993. This requested change to the Units 1 and 2 TS will delete TS 4.5.2.h.l.c that was added by the August 4, 1993 amendment. A 5

l draft copy of the proposed TS change is enclosed.

Notwithstanding the granting of this enforcement discretion, the NRC will l

consider e.forcement action, as appropriate, for the conditions that led to the need for tais exercise of enforcement discretion.

Please notify me immediately if your understanding differs from that set forth above.

i l

(Original signed By)

Gus C. Lainas, Assistant Director for Region II Reactors l

Division of Reactor Projects I/II 1

Office of Nuclear Reactor Regulation

?

Enclosure:

As stated t

i cc w/ enclosure:

See next page j

1 0FC LA:PDII-2, PE:PDII-2 s PM:POII-2 PD:PDII-2 SRXB a

NAME ETana d i RCroteauk LEMh M RJoneINd.-

ge y

s y i

DATE

/

/93

/

/93 li /e

/93

'i/t$ /93

/

/93 0FC D:RIIVD ADINII NAME EMersc M Ghnas DATE

// / /s /93 U / l0 /93

/

/93

/

/93 a

l Document Name: ENF DIS.NA2 1

J i*

'~

t i

i Mr. W. L. Stewart North Anna Power Station

~

i Virginia Electric & Power Company Units 1 and 2 i

cc:

J Mr. William C. Porter, Jr.

Robert B. Strobe, M.D., M.P.H.

County Administrator State Health Commissioner i

Louisa County Office of the Commissioner j

P.O. Box 160 Virginia Department of Health Louisa, Virginia 23093 P.O. Box 2448 i

Richmond, Virginia 23218 j

Michael W. Maupin, Esq.

i Hunton and Williams Regional Administrator, RII i

Riverfront Plaza, East Tower U.S. Nuclear Regulatory Commission 951 E. Byrd Street 101 Marietta Street, N.W., Suite 2900 1

Richmond, Virginia 23219 Atlanta, Georgia 30323 i

j Dr. W. T. Lough j

Virginia State Corporation Commission Mr. G. E. Kane, Manager Division of Energy Regulation North Anna Power Station P.O. Box 1197 P.O. Box 402 Richmond, Virginia 23209 Mineral, Virginia 23117 Old Dominion Electric Cooperative 4201 Dominion Blvd.

Glen Allen, Virginia 23060 i

Mr. M. L. Bowling, Manager f

Nuclear Licensing & Programs 1

Virginia Electric and Power Company i

Innsbrook Technical Center j

5000 Dominion Blvd.

i Glen Allen, Virginia 23060 1

Office of the Attorney General Supreme Court Building j

101 North 8th Street j

Richmond, Virginia 23219 i

j Senior Resident Inspector l

North Anna Power Station U.S. Nuclear Regulatory Commission Route 2, Box 78 Mineral, Virginia 231172

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y_

m.

a.w

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.- a u wa a af.h s

ameer.versunz:cubrismuu SURVSil.t.WCE RSQUIREMENTS gentasse er v=teng met each at *= mamag pues= enves, me wneens menai,e -

f.

(aner sue:rnanno suadon presswe) en roeirculauen now wnen asme pumus.u a Speniscaten 4.c.s.

1. coneWugal eheroing pun, premer men er equal to a41o peig.

2. 1.aw head saiser infondon pump gamer se er equei = 1ss peig.

g. By verw ing that the tonowing manual vahms requiring ad>siment to prevent pump r

'runour and seseguent component osmage me hakes ane tagges in = paper poemen for injecdon:

1. Within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months fomewing compteden of any reposhioning or rnaintenance en the vehe unen sw SCCs synnes me requkes is he opSust.a.

i

2. At least once ps-18 fnenet.

1. 2.S1 4e LampAColdLag

2. 2 81-97 Lampscaldtas

3. 2-81 103 LaspCCeltLag

4. 2-81 114 LampAHettag

s. 2 81111 Lasps Hottag

8. 2 88123 LampCHetLag i

h. By performing a flow halance test. during shoesown, fonowing comoseson of meddications so me SCCS suesystems met aber sw subsystem sew charamensees and vertfying that:

1. For high head safety initation lines, we a single pump running:

a) The sum of the iniendon ilne Sow rates, eachutng the highest Gow rate. is a 359 gym,%

b ) The total pump tow rate is s 800 gun,.eh

,,- -.u,.u Se S..

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Dated November 10, 1993 pf 4.y, t, 3 e

l DISTRIBUTION b

i Dacket File R. Jones O'

NRC & Local PDRs j

PD 2-2 Reading 09,oy'; g }

g g ; ;;

T. Murley

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i F. Miraglia L J. Callen, Acting i

W. Russell j

S. Varge G. Lainas L. Engle R. Croteau i

H. Berkow OGC E. Tata D. Hagan C. Hill (2)

C. Grimes ACRS (10) i OPA OC/LFDCB J. Lieberman, GC M. Thandani IL""7trschaff_Regjen. Il cc:

Plant Se>vice list l

i

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UNITED STATES f',a gs:

NUCLEAR REGULATORY COMMISSION j

. -[. '

'01 MAmETTA STRE

.W.. SUITE 2900 E

ATLANTA. GEORGIA 30323 0190 d

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DEC I 41993 L

MN TI-4 ~

Docket Nos. 50-338, 50-339 l

License Nos. NPF-4, NPF-7 N

Virginia Electric and Power Company 1

i ATTN: Mr. W. L. Stewart i

Senior Vice President - Nuclear j

5000 Dominion Boulevard Glen Allen, VA 23060 Gentlemen:

I j

SUBJECT:

NOTICE OF VIOLATION (INSPECTION REPORT NOS. 50-338/93-27 AND 50-339/93-27) 1

]

This refers to the Nuclear Regulatory Coussission (NRC) inspection conducted by j

Mr. R. McWhorter of this office on October 17 - November 20, 1993. The I

j inspection included a review of activities authorized for your North Anna facility. At the conclusion of the inspection, the findings were discussed j

with those members of your staff identified in the enclosed report.

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

these areas, the inspection consisted of selective examinations of procedures 1

i and representative records, interviews with personnel, and. observation of l

activities in progress.

i Based on the results of this inspection, certain of your activities appeared j

to be in violation of NRC requirements as specified in the enclosed Notice of Violation (Notice). The violation is of concern because it involved a

]

personnel error which resulted in disabling safety equipment.

In addition to the need for corrective action regarding the specific matters identified in the enclosed Notice, we are concerned about the implementation of your I

l cperating procedures that contributed to this event.

Consequently, your j

i response should describe those particular actions taken or planned to improve j

the effectiveness of operating procedures.

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

specified in the enclosed Notice when preparing your response.

In your response, you should document the specific actions taken and any additional i

i actions you plan to prevent recurrence. After reviewing your response to this 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.

{

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 Publi:: Document Room.

j I

l j HC!C'!um 2(p

~

4 DEC 141993 Virginit / D*ctric 'a Power Co'mpany 2

The responses directed by this letter and the enclosed 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,

&v Y.

L. V u.5.

Marv$n V. Sinkule, Chief Reactor Projects, Branch 2 Division of Reactor Projects

Enclosures:

1.

Notice of Violation 2.

NRC Inspection Report cc w/encis:

M. L. Bowling, Jr., Manager Nuclear Licensing 5000 Dominion Boulevard Glen Allen, VA 23060 G. E. Kane, Station Manager North Anna Power Station P. O. Box 402 1

Mineral, VA 23117 Executive Vice President Old Dominion Electric Cooperative 4201 Dominion Boulevard i

Glen Allen, VA 23060 Dr. W. T. Lough Virginia Corporation Commission P. O. Box 1197 Richmond, VA 23209 William C. Porter, Jr.

County Administrator P. O. Box 160 Louisa, VA 23093 Michael W. Maupin, Esq.

Hunton and Williams 951 E. Byrd Street Richmond, VA 23219 cc w/encls cont'd:

(See page 3)

l Virginia Electric & Power Company 3

DEC i 41993 cc w/encls cont'd:

Attorney General Supreme Court Building 101 North 8th Street Richmond, VA 23219 Robert B. Strobe, M.D., M.P.H.

i State Health Commissioner Office of the Commissioner Virginia Department of Health P. G. Box 2448 Richmond, VA 23218 i

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l ENCLOSURE 1 NOTICE OF VIDLATION Virginia Electric and Power Company Docket No. 50-339 North Anna Unit 2 License No. NPF-7 During an NRC inspection conducted on October 17 - November 20, 1993, a 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, the violation is listed below:

Technical Specification (TS) 6.8.1.c requires that written procedures be established, implemented and maintained covering surveillance and test activities of safety-related equipment. The licensee's Periodic Test Procedure 2-PT-82H, 2H Emergency Diesel Generator Slow Start Test, revision 14, provides instructions for testing Emergency Diesel Generator 2H.

Procedure 2-PT-82H, Step 6.4.5, for unloading the emergency diesel generator states to open breaker 25H2.

Contrary to the above, on October 29, Periodic Test Procedure 2-PT-82H was not implemented correctly. While performing step 6.4.5 (opening breaker 25H2), the operator incorrectly placed the control switch for the breaker in " pull-to-lock." This rendered Emergency Diesel Generator 2H inoperable from approximately 1:20 a.m. until 7:55 a.m.

This is a Severity Level IV violation (Supplement I).

Dated at Atlanta, Georgia this /W day of December 1993 i

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' UNITED STATES

?pa neo,,'*>,*

L NUCLEAR REGULATORY COMMISSION REGION 11

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10t MARIETTA STREET. N.W. $UlTE 2500 ATLANTA. GEORGIA 30323-0190 j

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Report Nos.: 50-338/93-27 and 50-339/93-27 Licensee:

Virginia Electric & Power Company 5000 Dominion Boulevard l

Glen Allen, VA 23060 Docket Nos.: 50-338 and 50-339 License Nos.: NPF-4 and NPF-7 Facility Name: North Anna 1 and 2 Inspection Conducted: October 17 - November 20, 1993 f

Inspectors:

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/1- / v-o 3 R. D. McWhorter, Senior Resident Inspector Date Signed

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Sw i 2.-ty-y y U. R. Taylor, Resident Inspector Date 51gned

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G. A. Belisle, SeUMan Chief Date Signed Division of Reactor Projects SLMIARY Scope:

This routine resident inspection was conducted on site in the areas of plant status, operational safety verification, maintenance observation, surveillance observation, engineered safety feature system walkdown, licensee event report followup, and action on previous inspection items.

Inspections of licensee backshift activities were conducted on October 17, 23 and 26, and November 5, 8 and 18, 1993.

Results:

Doerations functional aren A violation was identified for a failure to correctly implement a periodic test procedure which led to disabling Emergency Diesel Generator 2H for approximately six hours (paragraph 3.c).

Removing and storing the loose fuel material identified during the Unit 2 refueling outage was well planned and controlled (paragraph 3.d).

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i Enoineerino functional area i

An Inspector Follow-up Item was identified concerning the determination of a proper venting interval to ensure that the Low Head Safety Injection system initiates without excessive pressure surges (paragraph 8.a).

On November 8, as a result of continued evaluations into the cause of High Head Safety Injection flow balance test problems, all charging pues were i

I determined to be inoperable (paragraph 5.a).

Enforcement discretion was granted to allow the licensee 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months for corrective action, i

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REPORT DETAILS i

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Persons Contacted j

Licensee Fmnlovees L. Edmonds, Superintendent, Nuclear Training R. Enfinger, Assistant Station Manager, Operations and Maintenance

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G. Gordon, Acting Superintendent, Maintenance f

i J. Hayes Superintendent of Operations D. Heacock, Superintendent, Station Engineering l

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G. Kane, Station Manager i

P. Keep, Supervisor, Licensing i

W. Matthews, Acting Assistant Station Manager, Operations and i

f Maintenance J. O'Hanlon, Vice President, Nuclear Operations j

D. Roberts, Supervisor, Station Nuclear Safety R. Saunders, Assistant Vice President, Nuclear Operations D. Schappell, Superintendent, Site Services R. Shears, Superintendent, Outage and Planning

J. Smith, Manager, Quality Assurance i

A. Stafford, Superintendent, Radiological Protection j

J. Stall, Assistant Station Manager, Nuclear Safety and Licensing 3

Other licensee employees contacted included engineers, technicians, i

operators, mechanics, security force members, and office personnel.

NRC Personnel i

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R. McWhorter, Senior Resident Inspector i

D. Taylor, Resident Inspector 4

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Attended exit interview l

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

2.

Plant Status Unit 1 operated the entire inspection period at or near 1005 power, i

Unit 2 began the inspection period in MODE 5 recovering from a refueling 2

outage. On October 24, the unit entered MODE 4, followed by MODE 3 i

entry on October 25. A reactor startup was performed following MODE 2 entry on October 26. The unit entered MODE 1 on October 27, reaching approximately 1005 power on October 31. The unit continued at or near 4

j 1005 power for the remainder of the inspection period.

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2 3.

Operational Safety Verification (71707) j The inspectors cor. ducted frequent control room tours to verify proper staffing, operator attentiveness, and adherence to approved procedures.

l The inspectors attended daily plant status meetings to maintain 3

awareness of overall facility operations and reviewed operator logs to i

verify operational safety and compliance with TS.

Instrumentation and i

safety system lineups were periodically reviewed from control room

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indications to assess operability.

Frequent plant tours were conducted I

to observe equipment status, fire protection program implementation, j

radiological work practices, plant security, and housekeeping. DRs were reviewed to assure that potential safety concerns were properly reported i

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and resolved.

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Outage Commitments i

The inspectors reviewed several licensee outage commitments to

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ascertain that actions were completed.

The inspectors verified the outage commitment status by reviewing documentation, direct

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inspection of selected plant areas, and discussions with cognizant i

licensee personnel. Activities reviewed by inspectors included:

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Testing of manual S1 input to reactor trip circuits i

Inspection of FW rupture restraints Ultrasonic inspection of Unit 2 ASME XI piping as a result j

of a temporary non-code repair on Unit 1 Inspection of Unit 2 containment personnel hatch i

Fire barrier penetration inspection and repairs i

ISI exam on 2-51-153 bolting j

Seismic qualification walkdowns.

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The inspectors raited that outage cosmiitments were accurately i

tracked and reporttd to station management on a weekly basis.

j Based on the licensu successfully completing the above j

activities, the inspectors concluded that outage commitments made j

to the NRC were being fulfilled.

b.

Unit 2 Startup i

On October 26, 1993, the inspectors observed a reactor and turbine j

startup per 2-0P-1.5, Unit Startup from MODE 3 to MODE 2, revision 39; 2-0P-2.1, Unit Startup from MODE 2 to MODE 1, revision 50; and j

2-OP-15.1, Operation of the Main Turbine, revision 24. The i

startup was perfomed with very few equipment problems and was j

well controlled by the operators. One example of an equipment problem occurred when during the rod pull sequence, Bank C Rod 3

j H-10C failed to move.

In response, the CR0 fully inserted bank C j

as required by procedure 2-OP-1.5.

Subsequent troubleshooting j

identified the problem to be a blown fuse.

After the fuse was l

replaced, the startup proceeded and no further problems were observed.

The inspectors noted extensive management oversight for the reactor startup and placing the unit on line.

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3 c.

Emergency Diesel Generator 2H Inoperability On October 29, 1993, at 07:55 a.m., the Supervisor of Shift j

Operations identified that the control switch for the EDG output breaker, breaker number 25H2, was in the " pull-to-lock" position.

With the switch in this position, EDG 2H was prevented from automatically loading onto its emergency bus.

The condition was immediately corrected by placing the switch in the neutral i

position. Subsequent reviews by the licensee indicated that the switch was incorrectly put in the " pull-to-lock" position earlier that morning by an operator while perfoming 2-PT-82H, 2H Emergency Diesel Generator Slow Start Test, revision 14. The 4

procedure required the operator to open breaker 25H2. The i

operator put the breaker switch in " pull-to-lock," which was not i

called for by the procedure. This failure to properly follow J

procedure 2-PT-82H by incorrectly positioning the control switch for breaker 25H2 is identified as Violation 50-339/93-27-01:

Failure to follow Procedure 2-PT-82H.

The inspectors reviewed the SR0 and CR0 logs to verify compliance with TS action statement time limits and to identify if opposite 4

train equipment was out-of-service. The EDG was taken out of service at 9:28 p.m., on October 28, while performing 2-PT-82H.

j At 1:20 a.m., on October 29, following the apparent successful i

completion of the PT, the EDG was declared operable. At 7:55 j

a.m., the error was discovered and the switch was placed in j

neutral. The total time the EDG was inoperable was approximately i

6.5 hours5.787037e-5 days 0.00139 hours 8.267196e-6 weeks 1.9025e-6 months . The inspectors determined that no opposite train equipment was out of service during this period of EDG inoperability; consequently, TS action statement time limits were met.

l The inspectors reviewed compliance with TS action statement i

1.8.1.1.b.

The action statement allows one EDG to be out of service for up to 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months provided that the operability of the AC l

off-site power sources be demonstrated by perfoming surveillance i

requirement 4.8.1.1.1.a within one hour and at least once per 8 3

hours thereafter. The inspectors concluded that the 72-hour time limit had not been exceeded, but questioned the completion of the associated surveillance requirement. A review of logs indicated that the licensee used 2-PT-80, AC Sources Operability Verification, revision 8, to meet the surveillance requirement at 4

9:28 p.m., and again at 8:30 a.m.

Although 2-PT-80 was not formally completed, the licensee stated that operator observations j

and logs verified that equivalent actions were taken at least once during the period between 1:00 a.m. and 2:00 a.m.

The inspectors j

reviewed the licensee's findings and found that the equivalent j

actions had been documented to meet the 8-hour TS surveillance j

requirement.

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The inspectors evaluated the potential impact on plant safety for this event, since the EDG was prevented from automatically

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performing its safety function. The inspectors concluded that the j

safety significance of the event was minor because no opposite i

train equipment was inoperable, and the amount of time the EDG was in this condition was minimal.

In addition, the E0Ps require the operators to check EDG operations early during a transient, which 1

i would allow for the ouick detection and correction of this condition.

It was also noted that the improper switch position should have been identified during walkdowns for the 7:00 a.m. shift turnover.

i As a result, the licensee modified the shift turnover checklist to add the switch to formal turnover checks. The inspectors noted i

that good oversight by plant supervision was responsible for the i

l prompt discovery of the condition.

I The inspectors also reviewed 2-PT-82H for adequacy.

It was found i

1 that after unloading the EDG, step 6.4.5 required the operator to "Open breaker 25H2."

It was while performing this step that the operator put the breaker handswitch in the " pull-to-lock" position. The inspectors noted the switch did not have an "open" j

position, but rather had:

" pull-to-lock," " trip," neutral j

(unlabeled) and "close." The licensee's corrective actions included procedural changes to clarify the desired breaker 4

position. Additionally, the inspectors noted that the procedure i

did not contain independent verification requirements for control j

room switch alignments following the test. Concern was expressed to the licensee about the lack of independent verifications in the l

procedure. The licensee's investigations revealed that procedure j

writers did not routinely place independent verification l

requirements in procedures for switches which spring return to the desired position. The licensee informed the inspectors that, as a result of the incident, tney were commencing a procedure review to l

identify similar steps and add verification requirements where appropriate.

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d.

Removal of Fuel Pellets from Transfer Canal On November 18, 1993, the inspectors reviewed the licensee's i

actions for the recovering fuel material from the Unit 2 transfer canal. The material was found while moving fuel during the fall j

1993 refueling outage. The inspectors observed the pre-job brief j

and reviewed the videotaped results of the recovery and

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radiological surveys. The recovery was performed using temporary procedure 0-TOP-4.26, Removal of Y-48 Debris From the Unit 2 Transfer Canal in the Fuel Building, revision 0.

The procedure, radiological requirements, and precautions were thoroughly reviewed during the pre-job brief. The procedure involved using a heavy bristle brush attached to a pole to sweep the fuel into a

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stainless steel debris container. The container was then placed into an unusable fuel storage location. The procedure also.

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required practice runs in the new fuel storage area and in the i

Unit 1 transfer canal. Overall, the inspectors considered the recovery process well planned and concluded that the licensee's i

actions had been successful in safely storing the loose material j.

in the spent fuel pool.

e.

Licensee NRC Notifications (1)

On November 2,1993, the licensee informed the NRC, as i

i required by 10 CFR 50.72, concerning notifying off-site i

I authorities. Specifically, the licensee notified the J

i Commonwealth of Virginia of chroeste discharges into Lake l

Anna from a CCW 1eak. The inspectors reviewed this j

notification and verified that there was no regulatory concern associated with the event.

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(2)

On November 9,1993, the licensee infomed the NRC, as required by 10 CFR 50.72, concerning notifying off-site authorities. Specifically, the licensee notified the i

Federal Energy Regulatory Cosssission of a Lake Anna Das emergency diesel generator failure. The inspectors reviewed this notification and verified that there was no regulatory concern associated with the event.

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On November 17, 1993, the licensee informed the NRC, as l

required by 10 CFR 50.72, concerning notifying off-site i

i authorities. Specifically, the licensee notified the l

Commonwealth of Virginia of the transport off-site of a non-contaminated individual requiring medical attention.

The inspectors reviewed this notification and verified that j

there was no regulatory concern associated with the event.

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One violation was identified.

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Maintenance Observation (62703) 1 Station maintenance activities were observed and reviewed to verify that i

the activities were conducted in accordance with TS, procedures.

l regulatory guides, and industry codes or standards.

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Leak Sealant Repair 1

j On November 1,1993, the inspectors observed leak sealant repair on the pivot pin bearing cap to valve 2-FW-62, the main feedwater i

to A SG inlet check valve, which also serves as a containment isolation valve. The mechanical joint developed a 3 gps estimated leak during power ascension. The on-line leak repair war perforised using WO 274747 and procedure 0-MCN-1904-01, On-Line Repair Using Contractor Leak Sealant Methods, revision 0.

The procedure was issued October 22, 1993, and replaced three procedures previously used for leak sealant repairs.

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6 The SNSOC-approved procedure provided 19 methods for leak repair 1,

which were dependent on the specific application.

The inspectors observed the leak repair from the HSVH and reviewed j

the completed work package. The inspector noted that although not required by procedure, SNSOC rtquested the work package be presented for review prior to injection of the valve. The valve was injected using section 6.7, New Injection of a Flange With i

Clamp.

The inspectors judged that the maintenance was well i

controlled with sufficient management oversight.

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No violations or deviations were identified.

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Surveillance Observation (61726) 4 Station surveillance testing activities were observed and reviewed to i

verify that testing was performed in accordance with procedures, test instrumentation was calibrated, LCOs were met, and any deficiencies j

identified were properly reviewed and resolved.

a.

HHSI Flow Balance Test j

Near the end of the previous inspection period, the inspectors i

observed licensee personnel performing 2-PT-138.1, HHSI Flow i

Balance, revision 1-P2.

The purpose of the test was to verify that ECCS flow met TS 4.5.2.h requirements. During the initial l

run for the cold leg verification, branch line flows did not meet i

TS requirements. This failure was the subject of HRC Inspection Report Nos. 50-338,339/93-28.

l Inspectors monitored the licensee's corrective actions on this issue in preparation for Unit 2 entry into MODE 4.

The inspectors j

met with system engineers on October 18 to discuss probable causes 4

l for the repeated problems in HHSI flow balances. The valves which j

control HHSI flow (2-51-89, -97, and -103) were identified to be Rockwell-Edwards " univalves," which were the subject of NRC i

l IN 84-48 (with Supplement 1). The IN detailed problems with l

valves similar to this design in the areas of stem breakage and disc separation. As a result of these issues, the licensee performed radiographs of all three valves on October 20. The radiographs revealed that the internal components of the valves i

appeared to be intact.

l On October 21, 1993, a conference call was held between the l

licensee and the NRC to discuss the HHSI test failure. The i

licensee stated that the most probable cause for test failure i

continued to be valve stem movement.

In addition to actions taken j

in the past to prevent valve movement, the licensee installed a thread locking compound on the valve stem to prevent movement due i

to vibration or other means. The licensee also presented safety analysis results for out-of-specification HHSI flow balances. The results demonstrated that the margin to exceeding transient. PCT j

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limit. The largest flow imbalance measured was approximately 3 l

gpa below the TS limit.

On November 8, 1993, continued licensee's investigations into the i

caur.e for the HHSI test failure identified that the "Controlotron" j

flow in:truments used for the test may have contained excessive errors. The licensee performed extensive testing concerning the 4

effects of pipe configuration on the accuracy of the instruments i

and concluded that the Unit 2 piping arrangements may have led to t

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as much as ten percent error in measured flow.

This inaccuracy j

was analyzed, and the licensee conclud9d that performance could be assured within the system design basis.

4 However, due to the potential maast rement errors, the licensee i

could no longer demonstrate that tie TS 4.5.2.h requirements had been met. As a result, the licensen declared all three HHSI pumps inoperable, entered TS 3.0.3 at 2:45 p.m., on November 8, and requested enforcement discretion. The enforcement discretion requested a 24-hour period from TS 4.5.2.h.1 (readjust seal water i

f flows to the reactor coolant pumps) and TS 4.5.2.h.1.c (eliminate t

j simulated reactor coolant pump seal injection flow requirement).

A telephone conference call was held between the NRC and the licensee, and the licensee's request was granted based on the fact that the licensee's evaluations showed that the system could carry i

i out its design safety functions. The licensee exited TS 3.0.3 at 2:02 p.m., on November 9 which was within the enforcement i

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discretion time limits.

This enforcement discretion is considered closed. Details of the enforcement discretion were documented in j

the licensee's letter, serial 93-727, dated November 9,1993.

These issues were also discussed between the NRC and the licensee 4

j as a part of the enforcement conference conducted on. November 10, i

1993, involving actions associated with NRC Inspection Report Nos.

i 50-338,339/93-28.

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b.

Reactor Protection System Testing i

On October 22, 1993, the inspectors observed periodic test 2-PT-36.1A, Train A Reactor Protection and ESF Logic Channel l

Functional Test, revision 9.

The test was performed in preparation for mode change from MODE 5 to MODE 4.

The inspectors observed operability verification of the reactor trip and reactor trip bypass breakers from the control room, and observed the logic j

and permissive circuitry test at the logic test panel in the i

emergency switchgear relay room. The test was adequately l

controlled and all equipment performed as required.

No violations or deviations were identified.

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Engineered Safety Feature System Walkdown (71710)

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The inspectors performed a detailed CVCS system boration flow path walkdown. The portions of the system selected were those used to meet j

TSs 3.1.2.2, 3.1.2.4, 3.1.2.6 and 3.1.2.8 requirements. The inspectors compared system alignments with drawings and procedures 1-PT-13.3 and 2-PT-13.3, Boration Flow Path Verification, revisions 15 and 7, respectively. Additionally, general system material condition and housekeeping were observed. The inspectors found that the system j

appeared to be in good material condition.

System components were found to be in the proper lineup. Only minor housekeeping problems were i

identified. The licensee corrected these minor problems. Overall, 1

inspectors judged radiological conditions in the cramped area around system valves to be good. However, it was noted that the posting for j

one radioactively contaminated area boundary was vague. The posting was i

promptly enhanced by the licensee.

The inspectors concluded that the j

system met TS requirements and was properly aligned and maintained.

l Nr, violations or deviations were identified.

7.

I.icensee Event Report Followup (92700) 4 The following LERs were reviewed and closed. The inspectors verified that reporting requirements had been met, causes had been identified, corrective actions appeared appropriate, and generic applicability had

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been considered.

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(Closed) LER 50-338/91-19:

Inadequate Procedure Causes an l

l Improper LHSI Relief Valve Blowdown Ring Setting Resulting in j

Operability Issues This LER was issued as a result of a LHSI relief valve which i

opened during a pump start and failed to reseat.

The relief valve failure consequences were reviewed and documented in paragraph 8.a i

l of this report.

b.

(Closed) LER 50-339/92-10:

Cold Leg Safety Injection Branch Line Flow Below Technical Specification Requirements j

This LER concerned the licensee's failure to meet TS requirements 1

for h'iSI flow balance and was related to Violation 50-339/92-10-04 j

discussed in paragraph 8.b.

The inspectors reviewed the LER ank verified that licensee's corrective actions had been implemented.

After recurrence of this problem, this issue was addressed by 3

actions related to NRC Inspection Report Nos. 50-338,339/93-28.

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Action on Previous Inspection Items (92701, 92702)

The following previous inspection items were reviewed and closed:

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(Closed) URI 50-338/91-22-02:

LHSI Relief Valve Inoperability i

Safety Consequences This URI concerned evaluating the safety consequences for an event where the LHSI relief valve lifted and failed to reseat. The i

inspectors reviewed this issue to verify that the LHSI relief valve failure could not result in off-site and on-site l

radiological consequences exceeding regulatory limits. The inspectors requested information regarding the dose calculations documented in LER 50-338/91-19.

Prior to providing the i

information to the inspectors, systra engineers reviewed the data i

and identified that the off-site FA8 and LPZ doses were incorrect i

(low) by a factor of three. A revision to the LER was promptly j

initiated. The inspectors found that the revised calculations i

indicated that "best estimate" doses were well within 10 CFR 100 and GDC criteria 19 limits. This action resolved the URI.

Separate from the safety consequences issue, the inspectors also i

reviewed the history of problems associated with the LHSI due to i

pressure surges during pump start operations.

Specifically, i

pressure surges caused by inadequate venting have challenged the system and resulted in equipment failures. Most recently, NRC i

Inspection Report Nos. 50-338,339/93-18, documented the progress that had been made with suppressing these surges during testing.

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This was primarily a result of additional vents which were added t

to the system during the most recent outages. Although progress i

has been made, the inspectors questioned the adequacy of the j

system response to an actual SI.

This was based on the fact that prior to each test the system was vented to remove entrained gases and suppress pressure surges. The licensee indicated that as part i

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of long term corrective actions, the interval between venting j

would be determined to assure challenges to the system were i

minimized. The licensee further indicated that recent venting before testing performed on Unit I released only small volumes of j

gas.

Until the interval between venting is established, this is i

identified as IFI 50-338, 339/93-27-02: Adequacy of LHSI Venting i

Interval.

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(Closed) VIO 50-339/92-10-04:

Failure to Meet TS Flow Requirements for ECCS This violation concerned the licensee's failure to meet TS l

requirements for HHSI flow balance and was associated with LER 50-339/92-10 addressed in paragraph 7.b.

The licensee responded to this violation in correspondence dated June-9, 1992.

i This response was acceptable. The inspectors reviewed the violation and verified that licensee's corrective actions had been 2

implemented. After recurrence of this problem, this issue was addressed by actions related to NRC Inspection Report Nos. 50-338, 4

339/93-28.

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c.

(Closed) VIO 50-338,339/92-13-02:

Failure to Limit Personnel l

Working Hours l

This violation concerned licensee management's failure to properly monitor and control overtime which resulted in frequent problems where personnel exceeded requirements for a maximum of 72 working hours in a seven day period. The licensee responded to this j

violation in correspondence dated July 8,1992. This response was j

acceptable. The inspectors routinely monitored licensee management's efforts to monitor and control overtime during the Unit 1 SG replacement outage in the spring of 1993 and the Unit 2 i

refueling outage in the fall of 1993.

Additionally, inspectors monitored QA assessments in this area. The inspectors found management's attention to be effective in correcting the problem.

d.

(Closed) IFI 50-339/92-10-02:

Loop Stop Valve Failure Due to Incorrect Motor Wiring i

l This item was opened to follow the licensee's actions for repair i

of the valve and to review personnel performance issues. Repairs-to the valve were completed under WO 00260544-03 prior to startup from the most recent outage. With regards to personnel performance, this item was reviewed and it was concluded'that fatigue could have played a role in the error as documented in NRC i

Inspection Report Nos. 50-338,339/92-10. Current personnel l

perfonnance during the most recent outage did not identify similar problems.

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(Closed) VIO 50-339/92-18-02:

Inadequate Corrective Maintenance on Airlock Door to Preclude Repetition l

The violation involved repeated containment airlock door test i

failures due to inadequate corrective maintenance. The licent.ee responded to this violation in correspondence dated November 18, 1992. This response was acceptable.

Corrective action included maintenance to align the airlock door during the fall 1993 Unit 2 refueling outage. The inspectors reviewed the completion of this maintenance and subsequent testing. The inspectors found the l

licensee's actions to be adequate.

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(Closed) VI0 50-338/93-18-01:

Inoperable Hydrogen Analyzer j

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The violation involved a hydrogen analyzer which was discovered to be inoperable due to a pressure sensing line being disconnected.

The licensee responded to this violation in correspondence dated 1

i November 18, 1992. This response was acceptable. The cause of i

the event was personnel error with procedural inadequacies as a i

contributing factor. The inspectors verified that the procedures i

for calibrating the hydrogen analyzers were revised to more j

clearly reflect restoration of the hydrogen analyzer and to more clearly define verification steps.

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To address the broader issue of an apparent negative trend in the i

i number of errors during performance of I&C activities, increased i

management attention was placed on the activities.

Overall, licensee management was aggressive in trying to understand the cause for the errors and initiating corrective actions. Actions l

taken by the licenses have also been previously documented in NRC 1

Inspection Report Nos. 50-338,339/93-18.

I&C personnel errors 4

are currently trended by the licensee. The inspectors reviewed the data which indicated zero errors for the months of June -

I September 1993. The inspectors considered that actions to resolve this issue were effective.

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(Closed) IFI 50-339/93-24-01:

Loose Fuel Material in the Transfer Canal y

l This ites involved the finding of several loose fuel pellets in i

the Unit 2 transfer canal during the fall 1993 refueling outage.

Inspectors followed the licensee's recovery of the fuel material

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and its return to a safe storage location in the spent fuel pool (paragraph 3.d).

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9.

Exit (30703) f The inspection scope and findings were summarized on November 24, 1993, with those persons indicated in paragraph 1.

The inspectors described 4

the areas inspected, the findings in the results section of this report l

'and discussed in detail the inspection results listed below. The i

licensee did not identify as proprietary any of the material provided to or reviewed by the inspectors during this inspection.

Otssenting l

comments were not received from the licensee.

3 l

Ites Number Descriotion and Reference

(

i VIO 50-339/93-27-01 Failure to Follow Procedure 2-PT-82H l

(paragraph 3.c) i h

j IFI 50-338, 339/93-27-02 Adequacy of LHSI Venting Interval l

(paragraph 8.a) 4 l

10.

Acronyms and Initialisms i

i AC Alternating Current j

ASME American Society of Mechanical Engineers CCW Component Cooling Water CFR Code of Federal Regulations

)

CR0 Control Room Operator CVCS Chemical and Volume Control System i

DR Deviation Report EAB Exclusion Area Boundary ECCS Emergency Core Cooling System 4

EDG Emergency Diesel Generator i

E0P Emergency Operating Procedure a

i, 12 ESF Engineered Safety Feature FW Feedwater GDC General Design Criteria GPM Gallons Per Minute HHSI High-Head Safety Injection 1&C Instrumentation and Control IFI Inspector Follow-up Item IN Information Notice ISI Inservice Inspection LCO Limiting Condition for Operation LER Licensee Evti.it Report LHSI Low Head Safety Injection LPZ Low-Population Zone MSVH Main Steam Valve House NRC Nuclear Regulatory Commission PCT Peak Centerline Temperature PT Periodic Test QA Quality Assurance SG Steam Generator SI Safety Injection SNSOC Station Nuclear Safety and Operating Committee SRO Senior Reactor Operator TS Technical Specification URI Unresolved Item VIO Violation WO Work Order i

l NOV 3 0 ISS3 l

i Docket No. 50-364 l

License No. NPF-8 N0ED 93-2-007 O

Southern Nuclear Operating papany, Inc.

ATTN: Mr. D. N. Morey Vice President P. O. box 1295

(

Birmingham, AL 35201 Gentlemen

SUBJECT:

NOTICE OF ENFORCEMENT DISCRETION FOR FARLEY UNIT 2 By letters dated November 29, 1993, you requested the U.S. Nuclear Regulatory Commission to exercise discretion not to enforce compliance with Technical Specifications ?.0.4 and 3.6.4.2 to allow changing modes with only one of the two hydrogen recombiners being operable. This discretion would permit startup of Farley Unit 2 while you attempt to obtain parts to restore the 2B hydrogen recombiner to operable status.

I Based on our review of your justification including compensatory measures, we conclude that this course of action involves minimum safety impact, and we are clearly satisfied that this exercise of discretion is warranted from a public health and safety perspective. Therefore, we will not enforce compliance uith T.S. 3.0.4 and 3.6.4.2 for'd period of seven days following the first entry into Mode 2 after November 29, 1993. This discretion was granted verbally by a phone call from E. W. Merschoff, NRC, to D. Morey, Southern Nuclear Operat-ing Company, on November 29, 1993. However, we will consider enforcement action, as appropriate, for the conditions that led to the need for this i

exercise of enforcement discretion, i

Sincerely, Original s'er* "'j' li Luis A.P.c,7 t

i Luis A. Reyes Deputy Regional Administrator l

cc:

(See page 2) in h

230003 l

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NOV 3 0 l93.1 Southern Nuclear Operating Company 2

cc:

B. L. Moore Licensing Manager Southern Nuclear Operating Company, Inc.

P. O. Box 1295 Birmingham, AL 35201-1295 l

R. D. Hill, Jr.

General Manager, Farley Plant Southern Nuclear Operating Compaay, Inc.

P. O. Box 470 Ashford, AL 36312 W. R. Bayne, Supe, visor Safety Audit ani Engineering Review Farley Nuclear Plant P. O. Box 470 Ashford, AL 36312 State Health Officer Alabama Department of Public Health 434 Monroe Street Montgomery, AL 36130-1701 James,H. Miller, !!!, Esq.

Balch and Bingham P. O. Box 306 1710 Sixth Avenue North Birmingham, AL 35201 Chairman Houston County Comission P. O. Box 6406 Dothan, AL 36302 bec:

(See page 3) j,

e 0 GS3 Southern Nuclear Operating Company 3

bec: S. D. Ebneter, RI!

T. E. Murley, NRR L. J. Callan, NRR W. T. Russell, NRR S. A. Varga, NRR S. S. Bajwa, NRR J. Lieberman, OE P. D. Milano, NRR G. R. Jenkins, RII F. S. Cantrell, RI!

T. Ross, RII B. Siegel, NRR M. L. Boyle, NRR Document Control Desk NRC Resident Inspector U.S. Nuclear Regulatory Commission Route 2 Box 24 Columbia, AL 36319 I

v

FOR PRf'110VS CONCURRENCE - SEE ATTACHED COPY ORP/RII DRP/RII EIC ORA /RII ORA /RII

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93 11/,p0/93 II/s,/93 11/ /93 NRR l

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s' p-NOV 3 0 1993 Southern Nuclear Operating Company 3

.3 iL 8,.,C R5 bec: T. E. Murley,, NRR L. J. Callan, NRR W: T. Russell, NRR S. A. Varga, NRR S. S. Bajwa, NRR J. Lieberman, OE P. D. Milano, NRR G. R. Jenkins, RII F. S. Cantrell, RII T. Ross, RII

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L #3 1c 8

7 B. Siegel, NRR Document Control Desk NRC Resident Inspector U.S. Nuclear Regulatory Commission Route 2, Box 24 Columbia, AL 36319

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DRP/RI II EICS/RII ORA /RII ORA /RII P

DVerrelli:vyg schoff GJenkins CEvans LReyes 11/3,/93 i

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UNTTED STATES j

n mas %

NUCLEAR REGULATORY COMMISSION y

REGION 11 h

{'

q 101 MARIETTA STREET. N.W.. SUITE 2500 N

c ATLANTA. GEORGIA 303234190 NO)/ 3 0 1993 I T.

i ' ' $

C" Docket No. 50-364 1"

License No. NPF-8 NOED 93-2-007 Southern Nuclear Operating Company, Inc.

ATTN: Mr. D. N. Morey Vice President P. O. Box 1295 Birmingham, AL 35201 Gentlemen:

SUBJECT:

NOTICE OF ENFORCEMENT DISCRETION FOR FARLEY UNIT 2 By letters dated November 29, 1993, you requested the U.S. Nuclear Regulatory Comunission to exercise discretion not to enforce compliance with Technical Specifications 3.0.4 and 3.6.4.2 to allow changing modes with only one of the two hydrogen recombiners being operable. This discretion would permit startup of Farley Unit 2 while you attempt to obtain parts to restore the 2B hydrogen recombiner to operable status.

Based on our review of your justification including compensatory measures, we conclude that this course of action involves minimum safety impact, and we are clearly satisfied that this exercise of discretion is warranted from a public health and safety perspective. Therefore, we will not enforce compliance with T.S. 3.0.4 and 3.6.4.2 for a period of seven days following the first entry into Mode 2 after November 29, 1993. This discretion was granted verbally by a phone call from E. W. Merschoff, NRC, to D. Morey, Southern Nuclear Operat-ing Company, on November 29, 1993. However, we will consider enforcement action, as appropriate, for the conditions that led to the need for this exercise of enforcement discretion.

Sincerely,

/y,,,

/-

Luis A. Reyes Deputy Regional Administrator cc:

(See page 2) q h

1

Southern Nuclear Operating Company 2

W 3 01993 j

i cc:

B. L. Moore f

l Licensing Manager Southern Nuclear Operating

)

l Company, Inc.

P. O. Box 1295 Birmingham, AL 35201-1295 R. D. Hill, Jr.

General Manager, Farley Plant Southern Nuclear Operating l

Company, Inc.

P. O. Box 470 i

Ashford, AL 36312 W. R. Bayne, Supervisor Safety Audit and Engineering Review Farley Nuclear Plant P. O. Box 470 Ashford, AL 36312 i

State Health Officer Alabama Department of Public Health 434 Monroe Street Montgomery, AL 36130-1701 James H. Miller, III, Esq.

Balch and Bingham P. O. Box 306 1

1710 Sixth Avenue North l

i Birmingham, AL 35201 l

\\

Chairman l

Houston County Commission i

P. O. Box 6406 Dothan, AL 36302 l

l l

UNITED STATES g necoq*,i NUCLEAR REGULATORY COMMISSION nums d

REGION N 3

E 101 MARIETTA STREET, N.W., SUITE 2900 g;

6 u

j ATLANTA. GEORGIA 303230193 JAN 2 71994 Docket Nos.:

50-348, 50-364

\\M License Nos.:

NPF-2, NPF-8 b CL t)

(

Southern Nuclear Operating Company, Inc.

ATTN: Mr. D. N. Morey Executive Vice President Nuclear Operations P. O. Box 1295 Birmingham, AL 35201-1295 Gentlemen:

SUBJECT:

NRC INSPECTION REPORT NOS. 50-348/93-31 AND 50-364/93-31 This refers to the inspection conducted by T.M. Ross of this office on November 22 through December 31, 1993. The inspection included a review of activities authorized for your Farley facility. At the conclusion of the inspection, and at various times during the inspection, the findings were discussed with those members of your staff identified in the enclosed report.

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

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

The enclosed Inspection Report identifies that enforcement discretion action was granted by the Region II NRC office on November 29. We acknowledge that you exited the condition for which the discretion was given in a timely manner and no other action is necessary.

Your attention is invited to an unresolved item identified in the inspection This matter will be pursued during future inspection.

report.

In accordance with Section 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.

Sincer ly,

)

j

)

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Da id M. V relli, Chief R ctor Projects Branch 1 Division of Reactor Projects I

Enclosure:

NRC Inspection Report cc w/ encl:

(See page 2) l

l I

l l

Southern Nuclear Operating 2

JAN 2 71994 l

Company, Inc.

cc w/ encl:

B. L. Moore Licensing Manager Southern Nuclear Operating Company, Inc.

P. O. Box 1295 Birmingham, AL 35201-1295 R. D. Hill, Jr.

General Manager, Farley Plant Southern Nuclear Operating l

Company, Inc.

P. O. Box 470 Ashford, AL 36312 W. R. Bayne, Supervisor Safety Audit and Engineering Review Farley Nuclear Plant P. O. Box 470 Ashford, AL 36312 J. D. Woodard Executive Vice President Southern Nuclear Operating Company, Inc.

P. O. Box 1295 Birmingham, AL 35201 State Health Officer Alabama Department of Public Health 434 Monroe Street Montgomery, AL 36130-1701 James H. Miller, III, Esq.

Balch and Bingham P. O. Box 306 1710 Sixth Avenue North Birmingham, AL 35201 Chairman Houston County Cosmiission P. O. Box 6406 Dothan, AL 36302

i UNrTED STATES

[c# "%,'a.,

i NUCLEAR REGULATORY COMMISSION nEmoN N o

5 y

101.MAnseTTA STREET, N.W., SUfTE 2500 ATLANTA. GEonGlA 3033-0199 p

4 t,-...../

l Report Nos.: 50-348/93-31 and 50-364/93-31 i

Licensee:

Southern Nuclear Operating Company, Inc.

P. O. Box 1295 i

Birmingham, AL 35201-1295 Docket Nos.: 50-348 and 50-364 License Nos.: NPF-2 and NPF-8 l

j Facility Name: Farley I and 2 1

Inspection Conducted: November 22 - December 31, 1993 M N[2uh I!M!M Inspectors:

T.M.Ross,SeniorRfsidentInspector Date Signed i

(V 4% TLd=

nInhy-

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l M. A. Scott, Resident pspector Date 51gned

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M. J. Morgan, Resident lijspector Date Signed 91J.wO#r i/u/w.

i R.W. Wright,Proj$tEngineer Date Signed I!

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M

/k/ff Approved by:

n D4te Signed 5

FToyd 5(Cantrell, Chief Reactor Projects Section IB l

Division of Reactor Projects J

r 1

i SUltiARY I

l Scope:

?

}

This routine resident inspection was conducted onsite in the areas of plant j

operations review, maintenance / surveillance observations, safety system j

inspection, review of special reports and nonroutine events, engineering i

attributes, technical support, and follow-up of previous inspection findings.

Deep backshifts were performed November 21, and December 3, 4, 5, and 29.

5 4

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I Results:

1

)

Operations

,t Corrective actions performed in response to the Unit 2 trip of December 2 and i

the forced shutdown of December 20, 1993, were adequate and proper.

Post-outage restart preparations and testing were adequate and well conceived.

Low i

power physics testing was well controlled.

Results.cf inspections in the operations area indicate that operations personnel conducted assigned activities in accordance with applicable plant procedures and in compliance l

with technical specifications. An unresolved item was identified regarding 1

l licensee implementation of unit and site operating procedures, paragraph j

3.b.9.

No violations or deviations were identified in this area.

]

Mgittenance and Survfillance l

Inspuetion results indicate that licensee personnel conducted assigned maintenance and surveillance activities in accordance with applicable

]

procedures.

Furthermore, responsible personnel demonstrated a high degree of knowledge and craft skill in their activities.

No violations or deviations f

I were identified in this area.

i j

Enaineerina and Technical Suonort 1

Engineering and technical support was timely and thorough during licensee i

l request for enforcement discretion, Kerotest valve modification, and evaluation of service water system performance. No violations or deviations l;

were identified in this area.

l Plant Suonort l

Cold weather preparations performed by the licensee appeared to be effective.

Health physics personnel provided exemplary support of operational and maintenance related activities. Security personnel were consistently alert l

l and appeared to be implementing the plant's security plan appropriately.

No violations or deviations were identified in the areas of radiation protection, security, fire protection and emergency preparedness.

i l

9 i

i i

1 i

i

.i

{-

i REPORT DETAILS 1.

Persons Contacted l

Licensee Employees

]

W. Bayne, Supervisor Safety Audit and Engineering Review

C. Buck, Technical Manager i

P. Crone, Superintendent, Operations Support

L. Enfinger, Administrative Manager i

i

R. Hill, General Manager - Farley Nuclear-piant i

C. Nesbitt, Operations Manager

{

J. Osterholtz, Assistant General Manager - Plant Support l

L. Stinson, Assistant General Manager - Plant Operations j

J. Taosas, Maintenance Manager

B. Yance, Systems Performance Manager j

J. Powell, Superintendent Unit Operations

J. Odos, Superintendent Unit Operations

R. Coleman, PlO Manager NRC Personnel 1

j

T. Ross, Senior Resident Inspector j

M. Scott, Resident Inspector j

M. Morgan, Resident Inspecter R. Wright, Project Engineer j

Attended the exit interview i

j Other licensee employees contacted included, technicians, operations l

personnel, security, maintenance, I&C and office personnel.

1 i

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

i 2.

Plant Status and Activitter

)

a.

Unit I began and ended the inspection period at full power.

b.

Unit 2 began the inspection period in a shutdown condition, while in the final phases of a planned refueling outage. The reactor j

was returned to power (critical) November 30 at 1:28 a.m. and low j

power physics testing was performed.

On December 2 at 12:16 a.m.

i the unit entered Mode 1 (power >5%) power operation. However, on the same day the unit experienced an automatic reactor trip from j

5% power due to a feedwater (FW) transient. The unit was returned to the grid on December 3.

On December 21, Unit 2 entered into a short forced outage due to abnormal steam leakaos and noises associated with the number 2 low pressure turbins. After completing repairs, Unit 2 was returned to the grid on December 2g and achieved full power operation by the end of the inspection period.

j 2

L c.

NRC/ Licensee Meetings and Inspections j

l On November 23, S. D. Ebneter, Region II Administrator presented SALP findings at a public meeting to licensee management, plant l

i

}

personnel and local officials (Report 50-348,364/93-14).

l l

On November 22 and 23, the responsible Region II, DRP Section Chief and NRR Project Manager were onsite to meet with resident j,

inspectors and attend the SALP presentation.

l During the week of December 6, Region II Radiological Effluents /

Chemistry personnel conducted an inspection of the plant's post-accident sampling system and documentation of off-site releases j

(Report 50-348,364/93-30).

l During the week of December 6, Region II Emergency Preparedness personnel conducted a routine inspection of the licensee's annual

{

Emergency Plan exercise (Report 50-348,364/93-29).

i j

On December 27 thru 29, the Region II Farley Project Engineer, assisted the resident inspection staff by providing onsite i

coverage.

3.

Review of Plant Operations (71707), Refueling (60710), and Control Rod j

Worth Measurement (61710) j a.

Plant Tours i

Routine plant tours, particularly of the control room and the l

auxiliary building, were performed to verify that operating license and regulatory requirements were being met. These tours i

included review of site doctamentation and interviews with plant personnel.

Tours were conducted both on dayshift and backshifts.

1)

Walkdowns of Safety-related Equipment / Areas Limited walkdowns of the accessible portions of the l

following safety-related systems and surrounding areas were i

also perforund:

I j

u Unit 2 main steam isolation valves 4

i e Diesel generators e Unit 1 CCW heat exchangers and pumps i

e Unit 2 RHR heat exchangers and pumps 1

m Unit I and 2 DC switchgear and batteries i-a Unit I and 2 SW pumps j

u Unit 1 and 2 containment penetration rooms i

l i

E

I'.

i

- l j.

I 3

l Breaker / switch, valve line-ups, equipment conditions, and l

housekeeping were examined both locally and in the control l

room. System lineups were verified to be in accordance with operability requirements.

Safety-related equipment material conditions and area housekeeping were considered acceptable.

2)

Tagouts During the inspection period, the following j

tagouts/ clearances were verified:

4 i

n 93-3284-2 Normal Unit 2 Letdown (L/D) System (hung November 30 and returned to service on December 1 after L/D relief valve

/

replacement) a 93-3298-2 2A C1R pump breaker (hung December 1 in order

)

to fill the L/D system; returned during i

shift in order to exit an LCO) i I

e 93-3513-1 IB D/G (hung December 20 in order to perform preventive maintenance and for jockey pump / air receiver compressor replacement) l4 l

3)

Inspection Tours Prior To Unit 2 Startup i

j At the beginning of the inspection period, FNP prepared for i

the 108th startup of Uni! 2 following completion of the 9th j

j refueling outage. The insp.ection staff toured the auxiliary i

building and concainment areas prior to and immediately after entry into Mode 4 ope ~ation. During these tours, i

nothing was observed that would cause the delay ef any mode i

changes or create concern about safety system peri'orsance.

l However, a number of minor equipment problems and j

housekeeping deficiencies were identified.

These insoector findings were brought to the attention of the responsible shift supervisor for action.

Subsequent, inspector tours j

confirmed that the licensee had addressed the findings.

4)

Unit 2 Containment Tour After Startup On December 22, 1993, an inspector toured all levels inside the Unit T. containment while the unit was being maintained i

]

in mode L.

Unit 2 was shutdown the previous day to support a forced outage on the secondary side of the plant, which 3

~

included repairs to the number two low pressure turbine diaphragm.

During this tour the inspector did not identify i

ar.y significant equipment problems. However, a number of

(

minor equipment and component leaks were observed (many of which had already been identified by plant personnel).

Leaks notwithstanding, housekeeping inside containment was l

i 2

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4 very good.

The amount of loose debris was extremely small and insignificant.

It was apparsat that containment cleanup efforts and walkthrough inspections by plant personnel following the Unit 2 refueling outage have been, and continue to be, effective. Upon exiting the Unit 2 containment, the inspector reported his findings to the Unit 2 shift supervisor.

These findings were subsequently added to the SNC's list of containment work items and boron leaks attached as part of the "Farley Unit 2 Morning Report."

b.

Routine Plant Operations Review 1)

Performance of a Unit 2 Loss of Site Power (LOSP)

Surveillance On November 24, SNC performed a "B" train LOSP in accordance with STP-80.5, Diesel Generator "B" Train Loss of Offsite Power Test. The inspectors monitored this surveillance activity, with particular attention to acceptance criteria conformance, and operator / test coordinator command and control. Prior to the test, the operators and the relevant test personnel were briefed in accordance with AP-92,, " Checklist for Conduct of Infrequently Performed Tests and Evolutions". The brief included, expectations, "run-through" of test steps, expected individual actions, and unexpected / expected test results.

The brief was thorough and clear to all personnel.

Offsite power was removed from the "B" train 4160 volt motor center controls (MCCs) to start the test. All components started as required with the exception of the 2E SW pump motor. A 2E SW pump motor breaker relay, which had performed satisfactorily during previous post-outage use/ testings, had failed.

A second portion of the test involved a simulated " station black-out" (580) condition start of the 2C D/G. This D/G and associated circuitry had been recently modified to be a cross-unit tie emergency power supply. The electrical / control modifications were tested by this procedure. The 2B D/G was placed into " mode three" (i.e.,

would not start on loss of "B" train normal power) and the normal power supply to the "B" train was interrupted.

The 2C D/G was loaded onto the bus and loads were then sequenced on without failures. The 2C SW pump, - which could be aligned to the "B" train sequencer in lieu of the 2E SW pump (see above) - was incorporated into the test in order to test that portion of sequencer logic. The test was completed in a satisfactory manner with the 2C D/G carrying all required test loads at slightly less than 2.5 MW.

I I

i-j.

S 2)

NRC Discretionary Enforcement - Unit 2 Hydrogen Recombiners l

During preparations for entry into Mode 2 on November 29, j

the licensee discovered that a circuit board for the 2B 1

hydrogen recombiner had failed.

TS 3.6.4.2 requires both i

trains of recombiners to be operable during operation in 4

Modes 1 and 2.

At the time, there were no available replacement parts onsite and the vendor was having i

difficulty locating any spares.

The licensee was planning to enter Mode 2 in order to complete system tests and

(

conduct low power physics testing.

Such testing is J

accomplished at or near zero percent power.

t On November 29, the licensee forinally requested relief from j

TS 3.6.4.2 based upon the detemination that one recombiner j

was capable of controlling the quantity of hydrogen j

generated during an accident while in Modes 1 or 2.

After a telephone discussion between the licensee, NRR and Region II j

representatives, permission was verbally granted to allow j

entry into Mode 2 for up to 7 days, for testing, with only one operable hydrogen recombiner. A written confimation was made by NRC letter dated November 30, 1993.

I On December 1, after parts were obtained, the 2B hydrogen i

recombiner was repaired and declared operable.

SNC i

subsequently ordered additional spare circuit boards.

Engineering support for this enforcement discretion was j

prompt and thorough.

3)

Unit 2 Reactor Start-up and Low Power Physics Testing After enforcement discretion was approved on November 29, licensed operators commenced a reactor startup in accordance with UOP-1.2, Startup from Hot Standby to Minimum Load and l

initiated low power physics testing. The inspector observed control rod withdrawal and subsequent initial criticality i

for fuel cycle 10.

i l

With the inspectors present, unit operators were briefed by reactor engineers, per AP-92, on expectations for criticality and low power testiag. Testing was in 1

accordance with FNP-2-ETP-3601, the Zero Power Reactor Physics Test procedure. This testing was conducted with j) only one minor problem - the reactivity computer experienced j

a slight drift. This drift was " caught" by the reactor j

engineers and was properly corrected.

Based on the drift

?

experienced, SNC decided to increase the frequency of their calibration checks. The inspectors observed several rod worth critical measurements taken by SNC's reactor i

engineers. The raw data and evaluated data reviewed revealed core / rod responses were very close to the design j

and/or predicted values.

1 4

i i

1 i

t-i l.

1 6

j Throughout these evolutions, operator actions were j

controlled and their demeanor was relaxed but attentive, j

They displayed a good " questioning attitude" and were well i

i aware of the reactor's expected positive MTC characteristics j

at beginning of core life and possible effects at low power.

The reactor went critical very close to the expected rod j

position and boron dilution values.

i i

Inspector observation partially satisfied completion of NRC

]

inspection module 61710 (TS 3.1.1.1 & 3.1.1.3 - Shutdown margin and MTC measurement). Special test exception of TS j

3/4.10 was in effect for portions of the testing.

1 4)

Post-Outage Mode 1 Reactor Operation / Start-up - Unit 2 6

l On December 2. Unit 2 entered Mode 1 (reactor power greater than five percent) operation at 12:56 a.m.

The reactor was brought up to about 20 percent power in accordance with UDP-1.2.

The inspection staff observed part of the power increase. The operators did not experience any "at-the-3 i

controls" difficulties during start-up; although, one feed i

l flow transmitter failed low which, in turn, required repair l

(see below). During the power increase, the main turbine 4

was brought on-line smoothly and exhibited low vibration values. The only problem occurred during main turbine roll-up when two of the EHC system position controlling Moori i

valves for the number 2 and 4 main turbine governor valves required replacement.

Although Moog valve replacement is not an uncommon maintenance item during plant startup, the main turbine vendor was requested to examine the failed valves.

j-5)

Automatic Reactor Trip of Unit 2 Due To A FW Transient On December 2, at 10:33 p.m., while attempting to establish plant conditions for a main turbine trip test, Unit 2 reactor tripped automatically during a FW transient due to j

low SG water level. SNC subsequently generated an incident i

report (#2-93-295) and issued a licensee event report (LER l

93-004).

\\

i Prior to this event, reactor power was at 20 % and the main l

turbine / generator was being ramped down in preparation for a f

main turbine trip test in accordance with UDP-3.1, Power Operation, Appendix 4 - Turbine Overspeed Trip Testing.

Just before taking the main generator off-line, the main FW regulating bypass valves were placed in manual to allow

]

operators to maintain S/G 1evels high in their operating j

band. High S/G levels were desired to reduce the likelihood of tripping the reactor on a 2B S/G low level condition j

while FT-497 was "in test". With the FW flow transmitter "in test", and the bi-stable tripped, the likelihood of a 3

e

l 1

l-I 7

6 j

trip ine:reases due to a higher B S/G low-low level setpoint 1

(i.e., 25 percent).

Without the channel "in-test", the 1

setpoint would have been at 17 percent.

4 l

When the main generator was removed from the grid, S/G water levels began to fluctuate. With S/G 1evels already high in l

the band, these level fluctuations resulted in FW isolation i

and main turbine trip.

As a consequence of FW isolation and

{

main FW pump trip, the S/Gs began losing inventory. The 2C S/G was the first to boil down to the low-low level, causing i

a reactor trip. Although operators were injecting auxiliary j

FW at the maximum rate, and rods were driven in toward the j

latter part of the transient, these actions were unable to l

arrest S/G level loss.

j After the trip, the plant responded in a normal fashion and i

the unit operators entered.the appropriate emergency i

procedures.

Proper notifications were made and the resident j

inspector was called at about 11:07 p.m.

I During the initial event review, SE identified a procedural l

problem that contributed to the transient.

One of the procedures used for the turbine overspeed test directed operators to ramp generator power to 40 W prior to taking j

the generator off line.

The operators used the W power i

value as indicated on the turbine EHC console CRT. This i

value was not the actual MW value, but represented a main i

turbine valve demand value.

Procedural instructiors did not l

recognize this difference. Consequently, the main generator was removed from the grid at about 60 - 70 W in real terms j

while the indicated W was reading 40 W.

This condition i

caused the steam bypass valves to rapidly adjust to a i

greater than anticipated steam / power value and created j

larger than expected S/G level oscillations.

Coupled with already high S/G levels, this initiated the transient.

SNC plans to correct the procedural deficiency.

Furthermore, during the transient, the operator did not initially drive rods in due to an assumption that this would be contrary to information received during prior training on 4

positive MTC start-ups.

This training was performed in i

preparation for low power physics testing. The operator was instructed to not change rod position unless intermediate range power indication had changed.

Since reactor power was constant throughout the transient no rods were moved until late in the transient.

This delay in rod movement contributed to the overall effect of the FW transient.

Corrective actions prior to restart included:

m Discussion of the previous event a

Explanation of actual reactor MTC conditions

i i

i 8

l e

Repair of the FW flow transmitter a

Assurance that " actual" MW values would be used prior j

to taking the generator off the grid i

a Confirm that the FW station operator had been recently I

trained in that position With the inspector present during a reactor power increase d

l for a second turbine trip test, FW controls did not operate smoothly during the turbine speed " roll up" from zero to l

1800 RPM and S/G levels proved exceptionally difficult to j

maintain.

4 l

The licensee could not identify a problem and, rubsequently, 1

stopped the evolution at 1800 RPM speed on the turbine. An 3

emergency work order, 276429, was generated, to perfora troubleshooting activities which determined that the FW d

i master control cabinet card, "C8-225" had failed.

Maintenance activities were promptly and efficiently performed with minimal threat to the plant. The failed card that was causing erratic feeding of the S/Gs was replaced.

After the card was replaced, FW control was very smooth, i

The card problem was not obvious during the previous i

transient / trip although it was probably present. The licensee concluded that the failed card was the principal j

cause of the previous reactor trip.

The licensee recognized, that the above trip was similar to i

a previous Unit 2 transient (LER 92-005). However, the 1992 transient started with a main generator neutral overcurrent i

induced turbine trip and a load rejection rather than the i

above trip test. Similarities existed, such as the load I

rejection, S/G 1evel. and FW oscillations, a FW transmitter 3

in test, and an initially positive reactor MTC existed.

In i

1992, SNC attributed the problem to personnel error for i

failure to dampen the FW oscillations, in light of existing j

plant conditions.

j SNC realized, after this most recent event, that MTC conditions in both the 1993 and 1992 events were not fully i

understood. This finding was a good observation by SNC's i

root cause evaluation team. Additionally, SNC recognized j

the difference in " indicated" versus "real" MW with their j

turbine EHC control indication and the resultant difficulties when the load rejection was higher than 4

j expected.

)

In conclusion, the master FW equipment control card problem j

became apparent as the principal cause only after the licensee addressed the other contributing factors.

The inspector recognizes the insidious nature of some circuit controller card failures and that low power operations are i

particularly vulnerable to FW-related transients.

In this i

i i

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context, the inspector concluded that SNC's original j

incident investigation was sufficiently thorough at the time j

to justify continued plant operation and testing.

i Review of the LER and followup of longterm corrective actions will be documented in another inspection report.

i l

6)

Unit 2 Main Turbine Trip Test

.)

With the inspectors present, plant management provided a j

thorough shift briefing using lessons learned from prior attempts, before allowing further power changes or turbine i

i manipulations.

Late on December 3, with the inspector present, the second trip test was satisfactorily performed.

1 When the generator was taken off-line, at a real 40 MW, the j

automatic FW and steam bypass controls changed very little.

l Compared to the operator response observed by the inspector l

prior to the main FW controller card repair, minimal 1

l operator action was required to maintain stable plant i

conditions. The turbine mechanically tripped at 1937 to 1939 RPM which was below the maximum allowed. Operators l

properly exited the test, synchronized the turbine, j

commenced generator / reactor power increase to 27 percent.

i At 27 percent, power was held for chemistry adjustment and NI calibrations.

)

i 7)

Abnormal Noise And High Vibrations In The Unit 2 Main J

Turbine On December 20, FNP experienced a main turbine problem. At i

about 5:30 a.m., " moaning / steam leak-type" sounds were heard j

in the area of the #2 low pressure turbine housing.

1 Approximately two hours later, high turbine vibration alarms were received which prompted operator action.

Power was imediately reduced to around 80 percent, at which point the noise and vibration stopped.

l Subsequent testing / evaluation revealed that an inner l

cylinder ring diaphragm (gasket) to the 't ?ow pressure turbine had partially failed allowing sont yteam to bypass j

normal flow in the turbine.

i i

By not passing steam through the designed pathway of the j

turbine, turb'Jlent (and otherwise uneven) steam flows and a slight imbalancing of the turbine rotor were created. This, in turn, produced higher than expected vibration levels at i

higher powe.

i k

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10 I

j The unit was shutdown and put in hot standby (i.e., Mode 3) i for repairs / replacements on December 21 at about 9:00 p.m..

i i

During the diaphragm replacement activities, FNP and vendor maintenance personnel also discovered a damaged / missing heat

shield,

/

i Subsequent disassembly and inspection confirmed a failed diaphragm and a section of missing heat shield i

j (approximately 8 X 15 inches) that was replaced. The j

inspectors observed various stages of the repair activities

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and the unit's return to power operation.

i l

Repairs and diaphragm / gasket replacements were I

satisfactorily performed, startup activities commenced at about 3:30 a.m. on December 29, critically was achieved at l

about 4:12 a.m. and the unit was synchronized to the grid and returned to full power operation at about 5:31 p.m., on December 29. Startup activities were perfonned in accordance with CNP-2-UOP-1.2, Revision 26, Startup Of Unit 4

From Hot Standby To Maximum Load.

i 8)

Technical Specification Compliance l

FNP compliance with selected TS LCOs were verified i

throughout the inspection report period by the inspection j

staff. As part of this effort the following specific.

observations were made:

i a

On November 30, the IB PRF fan was taken out due to a j

breaker relay failure during an attempted start of the fan. This fan was returned to service on December 1 l

which was well before the specified/ allotted LC0 Action time limit.

i m

On December 1, FNP entered the LCO for TS 3/4.5.2 l

after taking the 2A RHR pump out of service as a g

i conservative action. The racking out of the pump i

motor breaker was performed to prevent inadvertent l

filling of the letdown (L/D) system, (upon the potential receipt of an SI signal), during gravity refill of the L/D system.

Entry into and out of the j

LC0 was appropriately tracked and within required j

Action statement time limits.

i e

On December 20, the IB D/G was removed from service for maintenance.

Entry into and out of the applicable LCOs were appropriately tracked and within required Action statement time limits.

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9)

Proc 9 dural Control During Unit 2 Startup During the return to service of Unit 2 from its ninth i

refueling outage, an inspector examined the licensee's implementation of unit operating procedures (UOP) and site operating procedures (SOP). These procedures provide the step-by-step instructions and/or guidance for returning i

primary and secondary plant systems to service following i

core reload. Written operating procedures (e.g., UOPs and SOPS) are required by TS 6.8.1.

In the scope of this inspection, the inspector conducted a general review of a broad number of UOPs employed during the Unit 2 startup. Most of these procedures were already complate by the time of the inspectors review.

In addition, the inspector conducted a detailed examination of the following procedures:

)

a FNP-0-SOP-103, Return to Service Checklist and Return i

to Service Systems Lineup i

I a

FNP-2-UOP-1.1, Startup of Unit from Cold Shutdown to j

Hot Standby I

m FNP-2-UOP-1.1A, Mode 4 Surveillance Checklist After the aforementioned reviews and examination, the

]

inspector concluded that Operations management and shift personnel were, in general, implementing UOPs/ SOPS in an acceptable manner.

However, a few notable exceptions were j

identified, as discussed below.

l Two weeks after the completion of 00P 1.1, procedure steps 5.31.2 (Turbine / Generator preparations), 5.31.3 (SGFP pre-i start test), 5.31.7 (Condenser nitrogen purge), and 5.31.8 i

(Start 2A Cooling Tower Fans) were still not initialed as having been performed.

Shift Supervisor completion signoff of UDP 1.1 was not made.

The inspector examined 50P-103 while Unit 2 was exceeding j

the 80% power plateau and found that: 1) Operations Manager i

review and signoff of several prerequisites required for i

exceeding 50% power had not been accomplished, 2) List of outstanding material exceptions inside containment was not documented as closed out prior to containment closure, and i

3) Many of the verification signoffs of required mode transition and power level prerequisites were not performed l

by those managers with designated authority.

The Operations manager was infomed of the above findings i

and promptly initiated corrective ;ctions.

The inspectors will continue to review additional Unit 2 UOPs and followup 4

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)L 12 j

on the licensee's corrective action efforts. This is considered to be unresolved item (URI) 50-364/93-31-01, a

j

" Inadequate Implementation of Operating Procedures."

I No violations or deviations were identified in this area. Corrective i

actions performed, in response to the Unit 2 trip of December 2 and the l

forced shutdown of December 20 were adequate and proper.

Post-outage j

restart testing / preparations were also adequate and well conceived. Low l

power physics testing was well controlled.

Results of inspections in i

the operations area indicate that operations personnel conducted

]

assigned activities in accordance with applicable plant procedures.

j However, an unresolved ites (93-31-01) was identified regarding licensee implementation of unit and site operating procedures.

4.

Maintenance Observation (62703) i i

The inspectors observed / reviewed portions of various licensee preventative and corrective maintenance activities, to determine i

conformance with facility procedures, work requests and NRC regulatory l

requirements. Work requests and instructions were also evaluated to determine the status of outstanding jobs and to ensure that proper j

j priority was assigned to safety-related equipment.

a.

MWR-257529, Install threaded cap on root valve Q2NilV0268 4

The 28 S/G level transmitter root valve (Q2N11V026B) had exhibited some body-to-yoke leakage. This Kerotest valve was intended to be i

capped and an associated PCN (B93-2-8683) provided instruction for installation of the cap.

l Corrections made by the PCN stopped the leakage. The inspector i

reviewed the work package, observed the clearance / operational j

controls associated with the repair and the valve's return to

)

i service. Work performed was satisfactory and consistent with guidance contained in the MWR and PCN.

I b.

MWR-276429, Repair of the Main FW Master Controller See paragraph 3.b.5 of this report.

I c.

MWR-285648, Repair of the IB D/G Electric-Driven Air Start i

Compressor 4

j The compressor had oil in the cylinder. The unit was replaced with a rebuilt compressor and work performed was appropriate, conducted in a controlled manner and within the scheduled window l

of the D/G maintenance outage. The work area and unit were left in good condition. Work performed was satisfactory and followed 5

guidance contained in the MWR and the D/G air compressor technical manual.

3 i

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1 d.

MWR-276327, L/D 45 GPM Orifice Isolation Valve Q1E21HV8149A Drifted Closed - Investigate and Repair This "in containment" valve repair was well controlled by J

operations and health physics personnel.

I&C technicians entered

)

the Unit I containment at power to perform the repair. The air j

operated valve had two minor air leaks and a loose limit switch..

i Bolts for the operating diaphragm housing and a fitting between i

the air regulator and air line required tightening. Both of these i

leaks were described as " minor weepages". The loose limit switch j

caused the valve drift problem.

f Since the repairs was perfomed without benefit of a tagout, the inspector observed strict operations and health physics control of repair activities and monitored coordination of in-process activities. Closure of the valve, without appropriate operator actions, could have caused perturbations in the plant. The shift 4

j supervisor and I&C technicians stayed in close communication throughout the repairs and testing activities. During repair of the air line fitting, I&C technicians questioned the use of teflon j

tape, and called out to I&C management via control personnel for clarifying instructions. Management had the appropriate sealant j

sent into the containment for use on the air line fitting.

The valve was satisfactorily stroke tested after the repairs in j

accordance with STP-45.1, CVCS Cold Shutdown Valve Inservice Test.

j Follow-up tours indicated no further problems with the valve.

i e.

MWR-280614 and 280618, #1 Diesel Driven Fire Pump - Repair j

l The #1 Diesel Driven Fire Pump (DDFP) failed to start in the i

manual B position during perfomance of test procedure FSP-201.1.

t Additionally, the subject DDFP did not automatically start in response to a low system pressure of about 30 psig. Efforts to investigate and troubleshoot the problems disclosed that the B l

battery bank was defective and needed replacement. Bench testing I

of Agastat relays ITR, 2TR and 3TR further revealed that these i

relays failed to " pick-up" when needed.

The inspector observed battery bank B replacement and subsequent successful manual "B" position post-maintenance test. Agastat relay replacement work and post-maintenance testing of the auto start system were still scheduled for completion.

All work observed was performed per applicable work instructions j

and procedures.

Electricians involved displayed a good working knowledge of their assigned tasks.

Resident inspectors will

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followup on scheduled DDFP repairs.

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MWR-276742, Inspection of 1A CCW Pump 4160V Supply Breaker Hinge j

Pin and Set Screw i

t During the previous monthly inspection period (50-348,364/93-28, j

Paragraph 4.b.), the inspectors reported on the licensee's corrective actions regarding problems with hinge pins in Siemens j

type MA-350C Air Magnetic circuit breakers that were vibrating out f

of position. Since then, the licensee has expanded their i

inspection efforts to cover all Unit 1 and 2 Siemens type MA-350C j

Air Magnetic circuit breakers.

By the end of this inspection l

j~

report period, 69 of 71 Unit 2 Siemens breakers and 10 of 73 i

Unit I breakers had been inspected.

Resident inspectors will j

continue to followup on the licensee's hinge pin inspection 4

efforts.

4 i

An inspector observed electrical maintenance activities during

}

inspection of the hinge pin and set screw position on the 1A CCW i

pump breaker (DG-04). Along with assigned electricians, the i

inspector visually verified that the allen set screw was properly j

engaged to prevent undesired hinge pin travel. The inspector also observed the replacement of both breaker " prop latch" springs per i

j work sequence instructions.

Breaker DG-04 was then lubricated, i

exercised several times, and racked back into its cubicle after appropriate coordination with control room personnel.

Craft skill i

and understanding of established work controls were evident f

throughout this maintenance evolution.

The work performed was satisfactory and followed guidance contained in the MWR.

1 No violations or deviations were identified in this area. The results of inspections in the maintenance area indicate that maintenance personnel j

conducted assigned activities in accordance with applicable procedures.

Mechanics demonstrated familiarity with administrative and radiological l

controls, and good craft skills.

i 5.

Surveillance Observation (61726)

Inspectors witnessed surveillance test activities performed on safety-l related systems and components, in order to verify that such activities l

were performed in accordance with facility procedures and NRC regulatory and licensee technical specification requirements.

Portions of the following surveillance test (s) were observed:

i a.

STP-1.0 (Units 1 and 2), Shift Surveillance Requirements Modes 1-4 Inspectors routinely observed operator activities while parameters were monitored, documented and evaluated.

l b.

STP-9.0 (Units 1 and 2), RCS Leakage Test 1

1 The observed RCS leakage tests were performed in accordance with the procedure requirements and demonstrated acceptable identified and unidentified leakage rates per TS 3.4.7.2.

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15 c.

STP-152.1 (Unit 2), Main FW Turbine Overspeed Turbine Test j

This test verifies operability of the overspeed mechanism on the 28 main FW pump turbine driver.

The turbine initially tripped at 5510 RPM which was below values that operation personnel had seen previously. The test procedure was modified to incorporate the vendor's comments (via temporary change notice (TCN) 5A] and the test was re-run. This test produced a turbine trip at 5554 RPM i

which was satisfactory and met the intent of the vendor letter WFNP-GWP-93-094, dated November 30, 1993.

I d.

STP-80.5 (Unit 2), Diesel Generator "B" Train LOSP Test l

The test was satisfactorily completed as indicated in paragraph j

3.b.1 of this repot t.

l e.

STP-45.7 (Unit 2), M51V & Bypass Valve Cold Shutdown Valve Inservice Test j

l This test was run in conjunction with 2-STP-21.1, MSIV Inservice Test and both tests were satisfactorily performed. The tests were

{

observed, by the insr,ector, in the main steam valve room with the plant hot and steam pressure in the main steam lines. The only 4

i problem noted during test perfor1sance was that a valve had a stuck j

limit switch. The problem was resolved by the I&C department on

~

the same shift. During the test period, the inspector and a licensee SRO, walked down all the steam lines in the space and observed no real mechanical problems; however, a small leak was noted at the "A" train AFW injection line flow instrumentation i

root valve and a snubber on the "A" main steam line had contracted j

under steam line expansion and forced out approximately one pint i

of oil.

i l

Both issues were presented to the licensee for further evaluation.

l A mechanical engineer was immediately assigned and the inspector directed the engineer to the items in question.

f.

STP-24.2 (Unit 1), Service Water Pumps 10, IE, and it Inservice j

Test i

The test was (and is normally) performed in groups of two pumps.

j However, any combination of two running pumps, that included the j-IC pump (i.e., the 10 with the 1C and the IE with the IC), failed the test on "high flow", as indicated by the " required action range" of FNP's ASME Code pump and valve program. The IC pump had i

been recently rebuilt and previously exhibited an acceptable code l

performance run.

j Upon reviewing the raw data, operations personnel decided to i

shutdown the IC pump until the problem could be resolved. This action was conservative and one taken as an administrative rather 4

j than an actual equipment concern.

Inspector reviews, along with

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the operations personnel, of the raw data and other parametric i

information indicated that the pump was performing satisfactorily.

l However, the flow measuring devices were not providing j

consistently accurate results.

I Flow measuring devices were previously addressed in NRC Inspection i

Report 50-348,364/ 93-13.

This report documented NRC concerns regarding the inaccuracies and erratic results of these devices, which have led the licensee to investigate new equipment and to contact consultants. SNC is in the process of validating new j

i measuring equipment and processes, but until such validation is I

completed, sometime in the spring of 1994, licensee engineers are i

conducting evaluations on a case-by-case basis. An evaluation of j

the IC pump's functionality was conducted on the day of test. The inspector discussed the evaluation results with the licensee, and j

considered them acceptable.

g.

1-STP-43.0, Spent Fuel Pool Ventilation Radiation Monitor System I

Functional Tests [TS 4.3.3.1]

l During test performance, a test signal caused the proper / correct i

equipment to actuate; however, during the return of equipment to normal alignment, one damper failed to open. The damper, NV 3991, j

failed in a safe position.

Operations took appropriate steps to l

check out the situation and generated a work order, MWR-275830.

h.

1-STP-228.6, NI Power Range N42 Calibration and Functional Test j

NI power range channel N42 was re-scaled in accordance with FNP t IMP-228.9, "NIS Power Range Channel N42 Current Rescale," to match

}

upper and lower detector output currents with recently revised i

values contained in the Plant Core Physics Curve Book. An 3

inspector observed portions of the subsequent calibration and j

functional testing.

4 i

The conduct of I&C technicians and performance of NIS channel N42

]

were monitored during functional testing of bistables for the P-8, P-9, and P-10 permissives, high/ low power range trips, overpower rod stop, and the positive rate trip. All "as-found" data for i

bistable actuation and reset were confirmed to be acceptable.

I Appropriate alarms and indications were verified on the main l

control board, plant computer, and local power range cabinet.

j Satisfactory functional checks of the upper and lower detector trend and overpower flux recorders were also performed. Test equipment used by the 15r technicians was within calibration and data sheets and instructions were rigorously followed. The i

technicians demonstrated a high degree of system knowledge and j

procedural familiarity.

t j

The only anomalous condition noted during this surveillance j

evolution was that all four NIS Detector Current Trend Recorders j

were offscale (i.e., greater than 120).

However, once the i

i 1

J

17 licensee had completed rescaling and testing all four NIS power i

range channeli, all upper and lower detector currents were trending at 100 (with Unit I at 100% power).

Although these recorders do not appear to perform any safety-related function, the inspector called to SNC management's attention the apparent poor practice of operating this equipment in a dysfunctional i

condition for extended periods.

Licensee management is currently l

investigating the purpose of these trend recorders.

l i.

2-STP-33.08, SSPS Train B Operability Test and 2-STP-33.1B, j

Safeguards Test Cabinet Train B Functional Test i

The inspectors observed licensed operators conducting selected i

portions of these surveillance tests and noted that the operators followed procedural instructions step-by-step. Tested equipment performed as expected and met required acceptance criteria. Close communication with the control room was maintained throughout the j

surveillance.

l{

No violations and no deviations were identified in this area. The results of inspections in this surveillance area indicate that personnel j

conducted assigned activities in accordance with applicable procedures.

i Furthermore, responsible personnel were knowledgeable and skilled in i

their surveillance activities.

i 6.

Cold Weather Preparations (71714)

In previous years, the licensee handled cold weather preparations via i

menos from Operations and electrical department PMs. The inspectors reviewed work authorization packages, 83017 and 83018, and noted that the packages contained completed procedures 1 and 2-EMP-1383.01, Freeze i

Protection Inspection. On separate occasions, operations personnel j

conducted inspections of areas around the site, including fire protection features and plastic tents in certain areas of the site, as i

directed by plant menos. During the week of December 20, Operations

]

issued a new revision to A0P-Z1.0, (revision 4), Severe Weather. This i

revision incorporated the activities previously directed by plant memos j

into one procedure.

Inspectors reviewed this revision and found the 4

consolidation laudable.

i i

The inspectors toured outside areas and exposed portions of the plant.

Licensee progress was also monitored until the plant eventually 4

established suitable cold weather protection prior to the onset of i

i freezing temperatures.

Licensee efforts were readily apparent by the repair of heat stripping around critical points and the temporary j

application of heavy plastic sheeting to the outside of the Unit I and 2 main steam valve rooms. Repair and replacement of this sheeting is a continuing activity due to damage by the wind. These activities l

appeared to be properly executed.

1 i

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l 7.

Plant Support 1

j a.

Fire Protection Review (64704) a 1

During the course of their nomal tours, the inspectors routinely i

examined facets of the Fire Protection Program. The inspectors i

i reviewed transient fire loads, flammable materials storage, housekeeping, control hazardous chemicals, ignition source / fire risk reduction efforts, and fire barriers.

1 j

No adverse situations or poor housekeeping was noted. A drip tray was under a portion of the fire header control system in the f

Unit 2 CCW space. This had been left there since the first of the i

refueling outage. When pointed out to the licensee it was

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removed.

b.

Physical Protection (81054)

The inspectors verified by observation during routine activities j

that security program plans were being implemented as evidenced j

by: proper display of picture badges; tours and stationing of security personnel; searching of packages and personnel at the plant entrance; and vital area portals being locked and alarmed.

i Licensee activities observed during the inspection period appeared adequate to ensure physical protection of the plant. Guards were 4

alert and particularly attentive to open doors.

Postings of

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guards were appropriate and well manned with frequent relief.

t c.

Health Physics Health physics technicians were consistently vigilant and their

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actions made a positive contribution to the safety of plant personnel during the inspection period.

Licensee response to an injured man in the RCA was partially observed. Appropriate radiological controls were employed while providing aid, considering the urgency and conditions involved.

During the j

inspectors tours of the containment, HP personnel were helpful and i

exhibited a high level of expertise.

2 d.

Emergency Preparedness (EP) Exercise (82206) i j

On December 8, 1993, an inspector observed licensee activities during its annual exercise of the FNP emergency plan and a

subsequent critiques. This particular annual exercise included

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full participation by officials from Early and Houston county, Alabama, and Georgia.

z 3

The performance of SNC emergency response equipment and personnel were evaluated by a team of NRC inspectors from Region II and NRR.

The results of this evaluation are documented in NRC EP Inspection Report 50-348,364/93-29.

i 1

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l 19 8.

Engineering and Technical Support j

a.

Modifications j

PCN B93-2-8683 was installed as indicated in paragraph 4.r..

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Engineering support of the job was effective.

Revisions to the j

package were made to support mechanical maintenance's work and i

reactor startup.

j b.

Tachnical Evaluations

)

Engineering provided an evaluation of the IC SW inservice test, j

see paragraph 5.g.. This evaluation was timely in its support of i

operatianal conditions.

1

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As noted in paragraph 3.b.2, engineering support of the licensee's i

request for enforcement discretion was prompt and thorough.

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9.

Exit Interview

)

Inspection scope / findings were summarized during management interviews throughout the report period and on January 6, with the plant manager j

and selected members of his staff. The inspection findings were i

discussed in detail and the licensee acknowledged the inspection I

findings. They did not identify as proprietary any material reviewed by l

the inspectors during this inspection.

l ITEM NUMBER DESCRIPTION AND REFERENCE i

50-364/93-31-01 (URI)

Inadequate Implementation of Operating Procedures 10.

Acronyms and Abbreviations j

AFW Auxiliary Feedwater Administrative Procedure AP American Society of Mechanical Engineers (construction Code)

]

ASME Component Cooling Water a

CCW l

CR Control Room i

CRT Cathode Ray Tube D/G Emergency Diesel Generator Division of Reactor Projects DRP Division of Reactor Safety l

DRS Division of Reactor Safeguards and Security DRSS Emergency Core Cooling System ECCS Electro-hydraulic Control System l

EHC Engineered Safety Features

]

ESF Fuel Handling Procedure i

FHP l

FNP Farley Nuclear Plant FP Fire Protection 4

Feedwater FW General Maintenance Procedure j

GMP i

i

4 1

1 l'

20 i

HP Health Physics ISI In-service Inspection I&C Instrumentation and Control KW Kilowatt LCO Limiting Condition for Operation LER Licensee Event Report L/D Letdown LOSP Loss of Offsite Power MCC Motor Control Center MOV Motor-Operated Valve i

MSIV Main Steam Isolation Valve MTC Moderator Temperature Coefficient MW Megawatt MWR Maintenance Work Request i

NDE Non-Destructive Examination l

NI Nuclear Instrument or NIS (system) j 005 Out Of Service PCN Plant Change Notice PM Preventive Maintenance i

PRF Penetration Room Filtration System psig pounds per square inch l

RCS i

Reactor Coolant System RHR Residual Heat Removal RWT Reactor Water Storage Tank i

SB0 Station Blackout SFI Shift Foreman Inspecting SFO Shift Foreman Operating i

SFP Spent Fuel Pool S/G Steam Generator SGFP Steam Generator Feedwater Pump j

SNC Southern Nuclear Operating Company 1

S0 Systems Operator

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SOP System Operating Procedure SS Shift Supervisor l

STAR -

"Stop", "Think", "Act", " Review" j

STP Surveillance Test Procedure i

SW Service Water System l

Tavg Temperature (average) in the RCS TCN Temporary Change Notice i

UDP Unit Operating Procedure URI Unresolved Issue i

I i

I j

e UNITED STATES

. [na nee,%,

NUCt. EAR REGUI.ATORY COMMISSION uv I

I

-d REGION ll

/

I S

101 MARIETTA STREET. N.W., SUITE 2000 E

ATLANTA. GEORGIA 3(D23-0199 N..../

DEC 191993 Docket No.:

50-281 License No.: DPR-37 NOED 93-2-008 P

Virginia Electric and Power Company 4

ATTN:

Mr. W. L. Stewart Senior Vice President - Nuclear 5000 Dominion Boulevard Glen Allen, VA 23060 Gentlemen:

SUBJECT:

NOTICE OF ENFORCEMENT DISCRETION FOR VIRGINIA ELECTRIC AND POWER COMPANY REGARDING SURRY UNIT 2 By letter dated December 15, 1993, you referred to your request for the U. S.

Nuclear Regulatory Commission (NRC) to exercise its discretion not to enforce compliance with the required actions in Technical Specification (TS) 3.12.C.3 which required inoperable control rod assemblies to be restored to operable status within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months or be in Hot Shutdown within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months . The discretion would pemit continued operation of Surry Unit 2 in POWER OPERATION for an additional 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months over the the 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months specified in TS 3.12.C.3 to effect troubleshooting and repairs to the Control Rod Drive System. By a telephone call on December 15, 1993, at 11:00 a.m., you informed the NRC that Surry Unit 2 would not be in compliance with TS 3.12.C.3 which requires the plant to be in Hot Shutdown by 4:37 p.m. on December 15, 1993.

You provided as justification for continued operation that the affected control rod assemblies, which were inmiovable on demand from the control Rod Drive System, were trippable. Hence, the faulted condition did not affect the ability of the control rod assemblies to perfom their intended safety function when a safety system setting is reached.

In addition, existing analyses established that power and peaking distributions used in the safety analysis were unaffected with any bank of control rod assemblies inserted up to 18 steps.

This bounds the present configuration, i.e., Shutdown Bank A Group 2 control rod assemblies inserted 3 steps. As a compensatory action, you indicated that the power level would be maintained stable during the troublesHboting and repair activities.

Based on our review of your justification, including the compensatory measure identified above, we have concluded that this course of action involves minimum or no safety impact, and we are clearly satisfied that this exercise of enforcement discretion is warranted from a public health and safety perspective. Therefore, we will not enforce compliance with TS 3.12.C 3 for the period from 10:37 a.m. on December 15. 1991,to 10:37 a.m. on December 16, 1993. This discretion was granted by the Deputy Regional Administrator and verbally conveyed to D. A. Sommers, Virginia Electric and Power Company, by G. A. Belisle, NRC, on December 15, 1993.

It is our understanding that you resolved the problem and exited the TS 3.12.C.3 action statement at 3:06 p.m.

W.AtDIGXfs$ h)

DEC161993 Vi nia E ectric and 2

on December 15, 1993. Therefore, this discretion has been terminated.

However, we will consider enforcement action, as appropriate, for the conditions that led to the need for this exercise of enforcement discretion.

Sinc ely,

~

/u Stewart D. Ebnat

,/

Regional Admini rator cc:

M. L. Bowling, Jr., Manager Nuclear Licensing 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 Ray D. Peace, Chairman i

Surry County Board of Supervisors P. O. Box 130 Dendron, VA 23839 Dr. W. T. Lough Virginia State Corporation Cosmiission Division of Energy Regulation P. O. Box 1197 Richmond, VA 23209 Michael W. Maupin Hunton and Williams Riverfront Plaza, East Tower 951 E. Byrd Street Richmond, VA 23219 Robert B. Strobe, M.D., M.P.H.

State Health Cosmiissioner Office of the Comeissioner i

Virginia Department of Health i

P. O. Box 2448 Richmond, VA 23218 i

cc:

Cont'd see page 3 I

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Virginia Electric and 3

Power Company cc:

Cont'd Attorney General Supreme Court Building 101 North 8th Street Richmond, VA 23219 1

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UNITED STATES 88e cq*.t NUCLEAR REGULATORY COMMISSION neWoM N

.A, O di 1

l JAN 271994 rrn N

Docket Nos. 50-280, 50-281 License Nos. DPR-32, DPR-37 L

Virginia Electric and Power Company ATTN: Mr. W. L. Stewart Senior Vice President - Nuclear 5000 Dominion Boulevard Glen Allen, VA 23060 Gentlemen:

SUBJECT:

NRC INSPECTION REPORT N05. 50-280/93-30 AND 50-281/93-30 This refers to the Nuclear Regulatory Commission (NRC) inspection conducted by Mr. M. Branch of this office on December 5, 1993, through January 1, 1994.

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 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.

Within the scope of the inspection, no violations or deviations were identified.

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

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

Sincerely, h

'_*d Marvin V. Sinkule, Chief Reactor Projects Branch 2 Division of Reactor Projects

Enclosure:

NRC Inspection Report cc w/ enc 1:

(See page 2)

CstdCS%i g)

' A Op Virginia Electric & Power Company,

2 ggg cc w/ enc 1:

M. L. Bowling, Jr., Manager Nuclear Licensing 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 Ray D. Peace, Chairman Surry County Board of Supervisors P. O. Box 130 Dendron, VA 23839 Dr. W. T. Lough Virginia State Corporation Commission Division of Energy Regulation P. O. Box 1197 Richmond, VA 23209 i

Michael W. Maupin Hunton and Williams Riverfront Plaza, East Tower 951 E. Byrd Street Richmond, VA 23219 Robert B. Strobe, M.D., M.P.H.

State Health Commissioner Office of the Cosmiissioner Virginia Department of Health P. O. 1 x 2448 Richmond, VA 23218 Attorney General Supreme Court Building 101 North 8th Street Richmond, VA 23219

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UNITED STATES l

ma as,%,&

NUCLEAR REGULATORY COMMISSION REGION 11 4

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101 MARIETTA STREET, N.W., SUITE 2000 ATLANTA. GEORGIA 3G34198 j

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Report Nos.: 50-280/93-30 and 50-281/93-30 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 j

Inspection Conducted: December 5, 1993 through January 1, 1994 Inspectors:

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//)G/H M. W. granch, Senior Resident D&te Signed Inspector 8-w N-

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//)&/fY J. W. Vbrk, Resident Inspector Date Signed Y

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/.s4JfY S. G. Tpngen, Resident Inspector a e 5fyited

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Approved by:

G. A. Belisler, Section Chief D&te Signed Division of Reactor Projects SupMARY i

Scope:

This routine resident inspection was conducted on site in the areas of plant status, operational safety verification, maintenance inspections, balance of plant inspections, review of plant modifications, and action on previous inspection items.

While performing this inspection, the resident inspectors conducted reviews of the licensee's backshifts, holidt.y or weekend operations on December 10, 12, 19, 22, and 28, 1993.

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Results:

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Operations functional area:

l Adequate implementation of the freeze protection program was noted j

(paragraph 3.b).

l, Maintenance functional area:

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Repetitive process vent Kaman radiation monitor problems continued to occur j

throughout 1993. The licensee's trending programs have identified this as a i

recurring problem. Corrective actions have been implemented and plans to j

implement additional corrective action were ongo4ng (paragraph 4.a).

I Enaineerina functional area:

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Station Nuclear Safety Operating Ceamittee review of a safety evaluation j

identified an area that required additional engineering analysis. This j

analysis resulted-in a procedural change for injecting temporary leak sealant into the packing of the Unit 2 loop fill control valve (paragraph 4.b).

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An unresolved item was identified associated with the fire barrier adequacy (i.e., MER-5 chiller cable protection), pending demonstration by the licensee l

that the installation and design meets commitments to and regulatory i

requirements of 10 CFR, Part 50, Appendix R (paragraph 6).

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' REPORT DETAILS 1.

Person Contacted Licensee Emoloyees

W. Benthall, Supervisor, Licensing

R. Bilyeu, Licensing Engineer H. Blake, Jr., Superintendent of Nuclear Site Services j

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R. Blount, Superintendent of Maintenance i

D. Christian, Assistant Station Manager J. Costello, Station Coordinator, Emergency Preparedness

J. Downs, Superintendent of Outage and Planning D. Erickson, Superintendent of Radiation Protection A. Friedman, Superintendent of Nuclear Training j

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B. Hayas, Supervisor, Quality Assurance

M. Kansler, Station Manager

'l C. Luffman, Superintendent, Security J. McCarthy, Superintendent of Operations l

A. Price, Assistant Station Manager l

R. Saunders, Assistant Vice Presid6at, Nuclear Operations E. Smith, Site Quality Assurar.ce Manager

T. Sowers, Superintendent of Engineering j

J. Swientoniewski, Supervisor, Station Nuclear Safety j

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G. Woodzell, Nuclear Training

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l NRC Personnel I

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M. Branch, Senior Resident Inspector

S. Tingen, Resident Inspector l

J. York, Resident Inspector a

Attended Exit Interview i

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

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

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2.

Plant Status i

i Ur.it 1 beg u the reporting period at 805 power on day 31 of the power coastdown Mr refueling. On December 21, power was reduced from 72% to approximately 62% in order to remove one tandem drive motor from one of l

the two main feedwater pumps for use on Unit 2.

The unit operated at

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rit5 power for the remaining period, limited by only one MFWP. The refueling outage is still scheduled to commence on January 21, 1994.

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Unit 2 began the reporting period at 100% power. On December 22, power was reduced to approximately 60% in order to replace a main feedwater e

j pe;p motor that was experiencing vibration problems. After the Unit 1 stator was installed in Unit 2, the unit was returned to 100% power on l

December 25.

3.

Operational Safety Verification (71707, 42700) j The inspectors conducted frequent tours of the control room to verify

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proper staffing, operator attentiveness and adherence to approved i

procedures. The inspectors attended plant :,tatus meetings and reviewed j

operator logs on a daily basis to verify operational safety and compliance with TSs and to maintain overall facility operational awareness.

Instrumentation and ECCS lineups were periodically reviewed j

from control rvse indication to assess operability.

Frequent plant l

tours were conducted to observe equipment status, fire protection programs, radiological work practices, plant security programs and i

housekeeping. Deviation reports were reviewed to assure that potential

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safety concerns were properly addressed and reported.

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Unit 2 Control Rod Drive System Urgent Failure Alarm and NDED 1

On December 15, at 8:37 a.m., a rod control system urgent failure occurred on Unit 2 during scheduled control rod exercising. The urgent failure rendered group 1 rods powered from cabinet (2-RC-i CAB-1AC) immovable (TS inoperable). The rods affected included i

group 1 rods in SDB "A" as well as CB "A" and "C".

In SDB "A",

l the first bank tested, the four group 2 rods had inserted three steps into the core while the four group 1 rods that were also selected remained fully withdrawn. At 8:37 a.m., a LC0 was entered in accordance with TS 3.12.C.3.

TS 3.12.C.3 required that j

inoperable control rod assemblies be restored to operable status i

within two hours or that the plant be put into a hot shutdown I

condition within the next six hours.

h Initial troubleshring began immediately and was witnessed by the j

inspectors. This kMleshooting involved looking for lit i

indicator lamps or Man fuses as well as taking electrical e

i reading at test points inside the rod control cabinet. There were

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no lit indicator lights or indication of blown fuses and the

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electrical readings appeared nomal. The K-2 failure detector card appeared loose (i.e., about 1/8-inch from fully seated).

j This card was removed, reinstalled, and additional electrical j

measurements made with no change in readings noted. The K-2 caWI was replaced and again there was no noted change in electrical 4

j readings. The old card was reinstalled. However, when the I-2 i

card, removed to ensure the gripper coils would stay de-energized i

during trcAleshooting, was reinserted, I&C personnel noted that i

lights on the J-1 failure detector card began flashing. The J-1 i

card was replaced and the urgent failure reset. After realigning l

the 508 "A" rods to fully withdrawn per a tamporary change to the l

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j rod realignment procedure, the operators attempted to again perform the rod exercise PT.

The rod urgent failure reoccurred.

j After determining that further troubleshooting and repairs could I

j not be completed within the action time of the TS, the licensee requested enforcement discretion.

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The NRC verbally granted enforcement discretion from TS 3.12.C.3 for Unit 2 only during a telephone conference on December 15, Written enforcement discretion was issued the next day.

1993.

The discretion permitted continued operation of Unit 2 at power l

for a period of 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months versus the two hours specified in TS j

3.12.C.3.

The additional time was projected to allow troubleshooting and repairs to the Control Rod Drive System.

i Although the control rod assemblies were immovable on demand from the Control Rod Drive System, the ability of the control rod

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assemblies to perform their intended safety function (trip into j-1 the core) when a safety system setting was reached was not i

affected.

t Additional troubleshooting after the second urgent failure j

revealed that the removed J-1 failure detection card had two loose capacitors that were not correctly soldered. This defective J-1 l

card had masked the problem that caused the first urgent failure.

The second urgent failure resulted in the J-1 card indicating that the failure occurred in the phase "C" stationary gripper circuitry. Both the phase control and firing cards for this circuit were replaced and the control rods were realigned and satisfactorily tested in accordance with periodic test 2-PT-6, i

Control Rod Assembly Partial Movement. The Control Rod Drive System was returned to service and the LCO terminated at 3:06 p.m.

on the December 15. This N0E0 is considered closed.

The inspectors noted that these rod equipment failures were further examples of continuing equipment malfunctions associated i

with the Control Rod Drive System. The inspectors discussed their concerns with the Station Manager who indicated that a Station Level 1 priority had been opened for engineering to review past failures and make recommendations for improvements. The j

licensee's current schedule for this project indicates that the f

review should be completed in time to allow for the implementing improvements during the upcoming (January 1994) Unit 1 RF0. Unit i

2 improvements should be factored into the next RF0, scheduled for i

September 1994.

b.

Cold Weather Protection (71714) 1 During a clant tour on December 12, the inspectors noted that the j

licensee was perforsing operations check list procedure no. OC-21, j

Severe Weather OC, daicd September 7, 1993. This procedure covers the following forecast weather conditions: high winds and/or heavy i

j rains, extreme cold and/or heavy snow, and severe hot weather.

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High winds and freezing weather had been forecast for this period i

of time. High winds and below freezing temperatures were expected i

in the area and operations, maintenance, etc., used this procedure to ensure that proper preparations have been made for the expected inclement weather.

In addition, the inspectors discussed the normal freeze protection program with the licensee. This program was implemented by monthly performance (October through March) of STP-52, Cold Weather Protection, dated April 3, 1992. This procedure contained a detailed checklist of areas and components that need to be i

routinely inspected to ensure that there was adequate protection to prevent freezing. This procedure, STP-52, was performed by both operations and maintenance personnel. Deficiencies that were noted while performing STP-52 were documented and discrepancy i

reports / work requests were written to schedule corrective action.

j On December 20, the inspectors reviewed the latest deficiency list j

and noted that they were either complete, being worked, or 1

scheduled. Walkdowns of exposcd areas susceptible to freezing was

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conducted by the inspectors. No discrepancies were identified that would indicate that the program was not being adequately 2

implemented.

Within the areas inspected, no violations were identified.

j 4.

Maintenance Inspections (62703, 42700) f During the reporting period, the inspectors reviewed the following maintenance activities to assure compliance with the appropriate y

i procedures.

a.

Process Vent Radiation Monitor l

During this inspection period the inspectors reviewed the reliability of the Kaman process vent high range effluent j

monitors.

Previous irs have addressed recurring problems with the i

i Kaman radiation monitors. Most recently, IR 93-23 addressed j

spiking on the Kaman ventilation vent affluent monitor 1-VG-RI-1 (TS Table 3.7.6 Item 12).

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TS Table 3.7.6, specified operability requirements for accident j

monitoring instrumentation.

Item 11 of this table specified j

operability requirements for the process vent high range effluent i

i radiation monitors. Kaman radiation monitors 1-GW-RM-130-1/2 i

fulfill this requirement. Whenever these radiation monitors are declared inoperable, an alternate method for monitoring the process vent effluent was implemented in accordance with TSs.

The process vent Kaman radiation monitors have a history of operational problems.

In 1991, approximately 11 DRs were written 2

j due to operational problems. Ten DRs were written in 1992.

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Twenty DRs were written in 1993. Recurring problems associated with these radiation monitors involved defaulting setpoints, the iodine / particulate sample becoming saturated with water, check i

source failures, and miscellaneous other problems. The licensee's i

trending programs have identified this as a recurring problem.

l f orrective actions have been implemented and plans to implement I

additional corrective action are ongoing. The inspectors will l

continue to monitor the performance of the process vent Kaman radiation monitors in order to evaluate the corrective action's j

i effectiveness, i

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Valve Packing Repair with Temporary Leak Sealant e

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TS 4.11.A.4 and 3.3.A.12 specify that total system uncollected i

leakage from SI system valves, flanges, and pumps located outside j

of containment not neeed 3836 cc/hr. The SI system leakage is monitored by perfor. ing periodic testing and walkdowns.

System i

leakage measurements are recorded and tracked in accordance with procedure 2-NPT-IZ-001, Quantifying of System External Leakage.

j While performing e system leakage inspection on December.23, operators identifie" a significant leak rate coolant increase from 2

the packing of the ait 2 loop fill control valve, 2-CH-FCV-2160.

i The packing leak rsta which was previously identified as 6 cc/hr had increased to I'dO0 cc/hr. On December 27, the coolant leak rate from the packing increased to 3120 cc/hr.

Leakage from the remaining components in the SI system was very low and therefore j

the system's total leakage rate remained below the TS maximum value of 3836 cc/hr.

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I On December 31, the loop fill control valve packing leak was stopped by injecting a temporary leak sealant into the packing area. This maintenance was accomplished by WO 260090-3 and procedure 0-MCM-1918-01, On Line Repairs. The inspectors reviewed i

the procedure and verified that there were provisions for limiting the amount of leak sealant injected into the packing area and restricting the leak sealant injection pressure. The inspectors also reviewed the work history dating back to 1991 for the Unit 2 loop fill control valve and verified that the valve had not

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previously been injected with a temporary leak sealant. The valve l

was repacked during the previous Unit 2 1993 RF0. The inspectors i

also verified that there was a WR initiated to return the valve to 1

it's original condition.

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i The loop fill control valve is a containment isolation valve that j

is normally closed and not repositioned while the plant is operating.

Injecting temporary leak sealant into the packing area precluded further va ve operation. SE 93-246, dated December 30, was prepared to evaluate operating the unit with the loop fill j

control valve permanently shut. The SC concluded that it was i

acceptable to operate the unit in thf 4 condition until the next

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RFO. The inspectors reviewed SE 93-246 and attended the initial SNSOC meetings that reviewed the SE. The inspectors noted that l

the SE was not initially approved by SNSOC. SNSOC had questioned j

j if the design pressure rating of the packing leak off piping was evaluated when determining the maximum temporary leak sealant i

injection pressure. The packing leak off piping was the injection point for the temporary leak sealant and the design pressure of this piping was not originally evaluated. As a result of SNSOC

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questioning, the maximum temporary leak sealant injection pressure was reevaluated and lowered. The SE was subsequently approved by i

SNSOC. The inspectors concluded that the initial engineering J

review for the temporary leak repair was incomplete. However, the

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SNSOC review and approval added value to the leak repair process, resulting in an acceptable temporary repair.

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l Within the areas inspected, no violations were identified.

5.

BOP Inspection (71500)

The inspectors conducted tours of selected T3 and other plant areas susceptible to flooding. During these tours, the inspectors verified the availability of the non-safety relater.s TB sump pumps which the licensee relies upon to mitigate certain flooding scenarios.

Additionally, the inspectors were sensitive to any work activities that j

would increase the possibility of TB flooding such as cpenings in the condenser waterboxes or piping systems.

On December 29, the inspectors witnessed the licensee performing l

maintenance associated with replacing TB sump pump 1-PL-P-2F discharge j

isolation valve 1-PL-12. This maintenance was accomplished in i

accordance with WO 279713-04.

In order to accomplish this maintenance,

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the power supplies to G ree of the nine TB sump pumps were danger tagged in the off position. The three TB sump pumps were inoperable for approximately 2.5 hours5.787037e-5 days 0.00139 hours 8.267196e-6 weeks 1.9025e-6 months while the maintenance was performed.

Previous licensee commitments to the NRC stated that at least seven of 1

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the nine TB sump pumps would be operable. The lic.ensee reevaluated the IPE calculations and concluded that for short periods of time it was t

l acceptable to have at least six T8 sump pumps operable.

Installing improved SW expansion joint spray shields was one of the contributors in reducing the critical flood flow rate which allowed operating with six TB vaip pumps. The licensee was drafting a letter to the NRC revising the'er cosmiitment.

l 1he inspectors concluded that 1-PL-12 replacement was accomplished in accordance with the licensee's procedures for minimizing the impact of j

flooding in the TE.

Within the areas inspected, no violations were identified.

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Review of Plant Modifications (37828)

The inspectors 'iave beer, closely monitoring the plant modification to improve the reliability of the control room and emergency switchgear room chillers. This project is commonly referred to as the MER-5 modification. The modification basically consisted of constructing a seismic structure to contain two additional chiller units with their support systems. Additionally, the modification added flexibility to the power supplies for the two new and the three existing chiller units.

0,. December 28, the inspectors witnessed / reviewed two activities associated with the MER-5 modification. The first involved a freeze seal to allow valve replacement and tying chill water to one of the three existing chillers. The second involved installing 3-M fire wrap over cables and conduit in order to establish fire separation between the two electrical trains that power the chiller units.

The freeze seal was installed using WO 262059-08 and was controlled by procedure 0-MCM-1918-03 revision 0, Freeze Seal of Piping. The procedure required that a SE be perfomed and approved by SNSOC. The inspectors reviewed the SE (93-239A) and found it acceptable. The piping being frozen was 3-inch diameter carbon steel piping. The inspectors noted that the piping surface in the freeze seal vicinity was very rusty and would be difficult to perform the NDE required prior to j

freeze seal installation. The Site Services personnel working the job a

showed the inspectors IPR 93-431 that documented the surface condition j

and provided the engineering disposition of the concern prior to the freeze seal installation. Specifically, surface grinding to samoth the area being frozen was performed followed by a successful NDE of the area.

The conduit fire wrap was being installed per DCP 90-07. The fire l

barrier being installed on the conduit that housed "H" bus power supply l

cables was necessary since the "H" bus conduit was routed through the "J" bus switchgear room within approximately 1-2 feet of the switchgear.

l 10 CFR 50, Appendix R requires that train (bus) separation be estabitshed by physical distance (20 feet), or by 3-or 1-hour fire barriers depending on the specific circumstances. The stated purpose of the modification was to provide a 1-hour fire barrier between the two electrical power trains.

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The inspectors reviewed the work package at the job site and noted that l

the 3-M installation / qualification instructions discussed a configuration that was different from that being installed. The 3-M r

i qualification for a 1-hour fire rating described a three wrap system for

< 5 inch aluminum conduit, consisting of two wraps of E-53 and one wrap of E-54. The system being installed consisted of three wraps of E-54 which was described by the licensee and their contractor as thicker l

material than the E-53 wrap. The inspectors requested verificaties that the actual installation configuration of 3 wraps of 3-M E-54 was bounded j

by test reports from the vendor, i

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The inspectors were provided a copy of a memorandum from the corporate i

fire protection engineer to Site Engineering. This memorandum contained the engineering evaluation for qualifying three wraps of E-54 material.

The basis for the fire wrap qualification configuration being installed was stated to be several 3-M test reports. However, fire test report I

no. 3MFT87-11, which was described as the closest to the actual

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installation, in a memorandum from PROMATEC, the licensee's contractor, 1

was not referenced. The inspectors requested a copy of fire test report j.

no. 3MFT87-11 for review.

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The above referanced memorandum also contained engineering evaluation no. 25 titled, " Evaluation of Lack of an Automatic Fire Suppression l

System in Unit 2 Emergency Switchgear Room Surry Power Station". -The j

evaluation's purpose was to allow using 1-hour fire barrier (i.e., 3 layer fire wrap on power supply cables for the chiller units). The j

original design had specified a 3-hour fire barrier (i.e., 5 wraps of 3-M material) for the cables in question but, because of space considerations, only 3 wraps could be installed.

The evaluation i

referenced 10 CFR 50, Appendix R, section III.G.2.c requirement that stated that two trains of safe shutdown cables could be separated by a 1

1-hour rated fire barrier, with fire detection and an automatic fire j

suppression system installed in the area. The licensee's evaluation was i

addressing the fact that the emergency switchgear room, where the cables in question were located, was equipped with a manual not automatic fire d

suppression Halon system.

10 CFR 50, Appendix R, section III.G.2.c

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would require a 3-hour barrier for this area and an exemption would be j

necessary.

I During subsequent discussions, the licensee produced a Surry Appendix R j

Report that states that the emergency switchgear rooms for Units 1 and 2 i

(fire zones 3 and 4) only had to meet the requirements of 10 CFR 50, I

Appendix R, section III.G.3 in lieu of III.G.2.c since remote shutdown capability existed.

Section III.G.3 only required a fixed suppression system and did not require it to be automatic. Additionally, train l

separation was not specified. Based on the conflicting data, it was j

unclear as to the fire protection and cable protection design requirements for this area. The fire protection design engineer stated l

that for new installations, III.G.2.c requirements were desired. Since-i the control room and emergency switchgear room chiller system were cosmon to both units, the inspectors questioned the licensee as to f

whether the system would be needed to cool equipment that was relied upon for remote / alter.h shutdown. Thereby, it would be required to i

meet the requirementt of III.G.2.c (i.e., protected by a 3-hour barrier 1

or 1-hour barrier with automatic fire detection and suppression).

The inspectors requested additional information and historical correspondence as to the design requirements for protecting the cable in question. This item is identified as URI 50-280, 281/g3-30-01, IER-5 i

Power Supply Cables Fire Barrier Adequacy, pending demonstration by the i

i licensee that the installation and design meets commitments to and l

regulatory requirements of 10 CFR 50, Appendix R.

Additionally, 3-M i

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9 fire test report 3MFT87-11 has not been provided by the licensee or reviewed by inspectors. The licensee has elected to maintain a fire watch in the area until this issue is resolved.

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Within the areas inspected, no violations were identified.

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7.

Action on Previous Inspection Items (92701, 92702) a.

Closed VIO 50-280,2Pl/92-07-03, Failure To Prevent Foreign j

Material From Entering SW System. When flow. testing the Unit 1 j

RSHXs during the 1992 Spring RF0, it was identified that the flow j

rate through RSHX '-RS-E-1B was low.

Inspection of the heat i

exchanger revealed that a rain jacket and rain pants were present i

in the tubesheet area which restricted the flow of SW.

It was j

concluded that the rain gear was inadvertently left in the system i

during maintenance that was performed during the previous fall 1990 RFO.

In a letter dated May 29, 1992, the licensee responded j

to this violation. The cause of this event was attributed to inadequate implementation of FME controls during the maintenance j

performed on the RSHX system during the 1990 RF0. As corrective action VPAP-1302, Foreign Material Exclusion Program, was i

implemented after the Fall,1990, Unit 1 RF0 to establish station j

wide FME controls.

In addition, VPAP-1302 was revised following rain gear identification to further enhance the FME program by 4

l requiring additional requirements for documenting closecut inspection results. The inspectors reviewed VPAP-1302, revision 1

3, and verified that the corrective actions in response to violation were implemented.

l b.

Closed VIO.50-280, 281/92-13-01, Failure to Perforu Safety l

Evaluations for Procedures That Were Used to Operate Plant Systems i

Differently Than Described in the UFSAR. This issue involved three examples in which the licensee operated plant systems in a different manner than described in the UFSAR but had not first prepared written safety evaluations pursuant to 10 CFR 50.59. The licensee responded to this violation in a letter dated July 31, 1992. As corrective action, safety evaluations were prepared for each of the examples identified. The inspectors reviewed SEs 92-126, dated June 4, 1992,92-127, dated June 4, 1992 and 92-171, l

dated July 22, 1992. SEs 92-171 and 92-127 identified that i

additional procedural controls were necessary. The inspectors t

reviewed procedures 2-0P-49.7, Filling and Draining RSHX Service Water Supply Piping, revision 2 and 0-0PT-FP-005, Fire Protection Water Pumps, revisir.n 1 and verified that the additional procedural controls were properly incorporated.

Within the areas inspected, no violations were identified.

i 3

}

i

b L

i 10 B.

Exit Interview The inspection scope and findings were summarized on January 4,1994, with those persons indicated in paragraph 1.

The inspectors described the areas inspected and discussed in detail the inspection results listed in the front of the report and those listed below.

Description Item Number Status (Paraaraoh No.)

URI 50-280, 281/93-30-01 Open MER-5 Power Supply Cable Fire Barrier Adequacy (paragraph 6).

i VIO 50-280, 281/92-07-03 Closed Failure To Prevent Foreign Material From Entering SW System (paragraph 7.a).

VIO 50-280, 281/92-13-01 Closed Failure to Perform Safety Evaluations for Procedures That Were Used to Operate Plant Systems Differently Than Described in the UFSAR (paragraph 7.b).

Dissenting comments were not received from the licensee.

Proprietary information is not contained in this report.

9.

Index of Acronyms and Initialisms i

BALANCE OF PLANT B0P CONTROL BANK CB CC/HR -

CUBIC CENTIMETERS PER HOUR DESIGN CHANGE PACKAGE DCP DEFICIENCY REPORT DR EMERGENCY CORE COOLING SYSTEM ECCS FOREIGN MATERIAL EXCLUSION FME INSTRUMENTATION A E CALIRRATION I&C INDIVIDUAL PLANT EXAMINATION IPE INSTALLATION PROBLEM REPORT IPR INSPECTION REPORT i

IR LIMITING CONDITIONS OF OPERATION j

LCO MECHANICAL EQUIPMENT ROOM MER 4

MAIN FEED WATER PLMP j

MFWP NONUESTRUCTIVE EXAMINATION i

NDE NOTICE OF ENFORCEMENT DISCRETION N0ED NUCLEAR REGULATORY CC4tISSION j

NRC OPERATIONS CHECKLIST j

OC PERIODIC TEST i

PT REFUELING OUTAP,E l

RF0 RECIRCULATION SPRAY i

RS I

1 1

i 11

~

RSHX -

IRCULATION SPRAY HEAT EXCHANGER

..JT DOWN BANK SDB SAFETY EVALUATION SE SI SAFETY INJECTION SNSOC -

STATION NUCLEAR SAFETY AND OPERATING COMNITTEE SW SERVICE 1TER TURBINE BUILDING TB TS TECHNICAL SPECIFICATION UFSAR -

UPDATED FINAL SAFETY ANALYSIS REPORT UNRESOLVED ITEM URI VIOLATION VIO WO WORK ORDER WORK REQUEST WR i

l J

~

.

v t e Letter Sequence Other
TAC:M86762, (Open)
Initiation Acceptance... Administration Questions Answers Results Approval... Other: ML20079R505
MONTHYEAR1993-10-06 [Table View]

ML20079R505

Text

SUBJECT:

SUBJECT:

SUBJECT:

SUBJECT:

Enclosure:

Dear Nr. Stewart:

SUBJECT:

Enclosure:

SUBJECT:

Enclosures:

SUBJECT:

SUBJECT:

SUBJECT:

Enclosure:

SUBJECT:

SUBJECT:

Enclosure:

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