Difference between revisions of "ML20133H019"

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Insp Repts 50-369/85-06 & 50-370/85-06 on 850120-0320. Noncompliance Noted:Inadequate Separation Criteria, Inadequate Diesel Generator Surveillance Interval & Failure to Follow Procedures & to Take Prompt Corrective Action
ML20133H019
Person / Time
Site: McGuire Duke energy icon.png
Issue date: 06/21/1985
From: Dance H, William Orders, Pierson R, Skinner P
NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:
Shared Package
ML20133H000 List:
References
Download: ML20133H019 (16)


See also: IR 05000369/1985006

Text

.

. UNITED STATES

D Cfog% NUCLEAR REGULATORY COMMISSION

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[' n REGloN 11

g .j 101 MARIETTA STREET, N.W.

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Report Nos.: 50-369/85-06 and 50-370/85-06

Licensee: Duke Power Company

422 South Church Street

Charlotte, NC 28242

Docket Nos.: 50-369 and 50-370 License Nos.: NPF-9 and NPF-17

Facility Name: McGuire 1 and 2

Inspection Conducted: J ary 20 - March 20, 1985

"

Inspectors: a h /g' // f0

W. rder Upte'S'gne

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P. M ne k ar tr and -- ,1985)

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ate igned

Approved by: I t Gt. O M'L{A y 2-( hy

H.'Uancg,SectionChief Date S1'gned

Division of Reactor Projects

SUMMARY

Scope: This routine, unannounced inspection entailed 470 inspector-hours on site

in the areas of operations, safety verification, surveillance testing,

maintenance activities and refueling activities.

Results: Of the four areas inspected, four items of noncompliance were found in

three areas (Violation of 10 CFR 50, Appendix B, Criterion III for inadequate

separation criteria; Violation of Technical Specification (TS) 6.8.1 for failure

to follow procedures; Violation of TS 4.8.1.1.2a for inadequate diesel generator

surveillance interval and Violation of 10 CFR, Appendix B, Criterion XVI for

failure to take prompt corrective action).

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8508090150 050628

PDR ADOCK 05000369

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REPORT DETAILS

1. Licensee Employees Contacted

T. McConnell, Station Manager

  • D. Rains, Superintendent of Maintenance
  • G. Cage. Superintendent of Operations
  • L. Weaver, Superintendent of Station Services

N. McCraw, Licensing Engineer

  • J. Foster, Station Health Physicist
  • M. Birch, System /Radwaste Engineer General Office
  • R. Michaels, Station Chemist
  • B. Hasty, McGuire Nuclear Station - QA
  • P. Roberson, Associate Engineer - Performance

Other licensee employees contacted included teci.nicians, operators,

mechanics, security force members, and office personnei.

  • Attended exit interview

2. Exit Interview

The inspection scope and findings were summarized on March 29, 1985, with

those persons indicated in paragraph I above. The licensee acknowledged

understanding of the violations and issues discussed and offered no

substantive related discussion. The licensee did not identify as pro-

prietary any of the materials provided to or reviewed by the inspectors

during this inspection.

3. Licensee Action on Previous Enforcement Matters

This subject was not addressed in the inspection.

4. Unresolved Items *

Unresolved items are matters about which more information is required to

determine whether they are acceptable or may involve noncompliance or

deviations. New unresolved items identified during this inspection are

discussed in paragraph 17.

5. Plant Operations

The inspection staff reviewed plant operations during the report period,

January 20 - March 20, 1985, to verify conformance with applicable

  • An Unresolved Ite'n is a matter about which more information is required to ,

determine whether it is acceptable or may involve a violation or deviation.

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regulatory requirements. Control room logs, shift supervisors logs, shift

turnover records and equipment removal and restoration records were

routinely perused. Interviews were conducted with plant operations,

maintenance, chemistry, health physics, and performance personnel.

Activities within the control rooms were monitored during shifts and at

shift changes. Actions and/or activities observed were conducted as

prescribed in applicable station administrative directives. The complement

of licensed personnel on each shift met or exceeded the minimum required by

TSs.

Plant tours were taken during the reporting period on a systematic basis.

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

Turbine Buildings

Auxiliary Buildings

Unit 1 and 2, Electrical Equipment Rooms

Units 1 and 2, Cable Spreading Rooms

Station yard Zone within the protected area

Unit 2 Reactor Building

During the plant tours, ongoing activities, housekeeping, security,

equipment status and radiation control practices were observed.

Unit 1 Operations

McGuire Unit 1 began the reporting period in Mode 1 operating at 100 percent

reactor power and operated at or about that power level until January 28.

On that morning, the IB main feedwater pump trinped when a suction pressure

instrumentation line failed. A turbine runbaci failed to initiate upon the

loss of feed pump due to a failed diode in tF runback circuitry. The unit

subsequently tripped on steam generator 1B 1 lo level.

The unit was subsequently recovered and ent red Mode 1 at 11:09 p.m., on the

evening of January 30. The unit was paralleled to the grid and power held

to 30 percent to allow secondary chemistry to be brought into specification.

The unit's power was subsequently increased to 100 percent and maintained at ~l

that level until February 5, when the unit apparently tripped on negative

high flux rate. This trip is discussed in detail in paragraph 7.

During the trip recovery, two engineered safeguards features actuations

occurred. These events are discussed in paragraph 12. It was also

determined that a wiring modification on the solid state protection system

for Unit 1 had been incorrectly installed thus rendering the reactor trip

breakers inoperable for Unit 1. This event is discussed in paragraph 11.

Following correction of the modification the unit was restarted reaching

criticality at 6:18 a.m., on February 7 Reactor power was subsequently

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increased to and maintained at or about 100 percent until February 21, when

power was reduced to 90-95 percent to maintain generator hydrogen temperature

within limits (one cooler was valved out due to a leak). Power was maintained

between 90-95 percent until March 8, when power was reduced to optimize

outage scheduling. The unit was subsequently operated between 55-62 percent

throughout the duration of the report period.

Unit 2 Operations

McGuire Unit 2 began the reporting period in Mode 1 operating at 100%

reactor power. The unit was maintained at or about that power until

8:54 a.m., on January 25, when unit shutdown was begun to facilitate a

refueling outage. The unit was shutdown and cooled down entering Mode 5 at

10:05 p.m., on January 26. The unit was maintained in Mode 5 until

February 7 when the unit entered Mode 6.

Detensioning of the Reactor Vessel Head was complete at 3:00 a.m. on

February 8. Core alterations comenced at 3:40 p.m., on February 16.

Fuel removal was completed at 2:45 p.m., on March 3. The unit remained

defueled until March 20 when fuel reload was initiated.

6. Reactor Trip of January 28

On January 28, when Unit I was operating at 100 percent reactor power, an instru-

ment air line failure to the B main feedwater (CF) pump suction pressure

transmitter caused the loss of B CF pump on apparent low suction pressure.

A turbine runback signal from loss of this feedpump failed to initiate a

turbine runback due to a bad diode on a card in the turbine electro-

hydraulic control. Operators attempted a manual turbine load reduction but

were unsuccessful and a reactor trip occurred on 10-10 B steam ger.erator

level. After the trip some problems were encountered with B and C steam

generator Pressure Operated Relief Valves (PORV). These valves failed to

close for 4 minutes and 25 seconds respectively. A faulty pressure trans-

mitter on B steam generator pressure caused the delay in closing the B steam

generator PORV. The resultant inventory loss and void collapse caused B

steam generator level to drop below its narrow range scale for approximately

6 minutes. The resulting cooldown caused pressurizer level to fall below

the letdown isolation setpoint. A second charging pump was started,

pressurizer level was recovered and letdown reestablished.

Following the trip the check valve in the Turbine Driven Auxiliary Feed Pump

(TDAFP) line to the "C" steam generator failed to seat when the TDAFP was

being realigned to the A and B steam generators. The valve was subsequently

isolated, however a large portion of motor driven auxiliary feedpump flow '

to the "C" steam generator was backfeeding into the TDAFP suction line

i through the check valve prior to isolation. Further discussion related

to backleakage of auxiliary feedwater check values is contained in para-

graph 15.

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7. Reactor Trip of February 5,1985

On February 5, 1985, a Unit i reactor trip occurred on what appeared to be a

High Negative Flux Rate. Unit I was at 94 percent reactor power in steady state

operation. Power had been reduced to this level to facilitate the resetting

of the High Negative Flux Rate trip setpoints per Westinghouse recomen-

dation as discussed in paragraph 9. At the time of the trip, three of the

four Power Range Nuclear Instruments had been reset; preparations were

underway to reset the fourth. No instrumentation and electrical work was in

progress at the time of the trip. Two design engineering personnel were

performing a visual inspection of the nucler station modification installed

in the Unit 1 Reactor Trip Breaker Cabinets discussed in paragraph 11.

There is no conclusive evidence tc indicate that changing the High Flux Rate

trip setpoints contributed to the reactor trip. A reenactment of the

visual inspection which design engineering was conducting did not result

in opening of the reactor trip breakers. Efforts to determine the exact

sequence of events was hampered by the fact that the events recorder points

for the reactor trip breakers were out of service as had been noted on the

reactor trip which occurred on January 28. A work request to correct this

problem had been issued but the repairs had not been affected.

It cannot be determined conclusively whether one or both of the reactor trip

breakers opened causing the rods to fall and thus causing a High Negative

Flux Rate trip indication or whether an actual High Negative Flux Rate

signal opened the reactor trip breakers.

Since the cause of the reactor trip could not be determined, an independent

review was performed per Station Directive 3.1.10. Licensee personnel

evaluated the occurrence and could not determine the cause of the trip. The

Station Manager made the decision to restart the unit with instructions to

monitor the High Flux Rate trips with recorders.

8. Diesel Generator (D/G) 2A Valid Failure

Diesel Generator (D/G) 2A experienced a valid failure on January 31, 1985.

The failure occurred as a result of a low lube oil pressure trip while

Operations personnel were performing a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> run test in preparation for

an engineered safety features (ESF) test. After the trip, inspections were

made to determine the cause for low lube oil pressure. When no cause was

found, D/G 2A was restarted for additional troubleshooting. Due to abnormal

vibration in the engine, the run was terminated and the D/G was declared

inoperable.

An inspection of the main bearinas following the shutdown of the D/G showed

severe damage had occurred to five of ten main bearings. The bearing

deterioration appears to be the result of a mechanical failure. Preliminary

investigations indicate that damage was not due to oil starvatica of the

bearings. A final determination of the cause of the bearing failure can not

be made until the licensee completes all inspections and measurements during

the course of repairs.

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Details concerning the D/G 2A failure is covered in Report No. 50-369/85-13

and 50-370/85-12.

9. Westinghouse Determination of Incorrect Rod Drop Time Specifications

On February 1,1985, Westinghouse notified the licensee that McGuire's TS 3.1.3.4 allows a rod drop time of 3.3 seconds. This does not coincide with

Reactor Trip System Instrumentation Trip Setpoints stipulated in Table 2.2-1

Item 4. This specification if corrected would require Power Range, Neutron

Flux, High Negative Rate, Trip Setpoint of less than or equal to 5 percent

of Rated Thermal Power with a time constant greater than or equal to 2

seconds. It was identified during a review of this issue that the applicable

TS 2.2.1, Table 2.2-1, Item 4 is incorrect in that it specifies a trip

setpoint of greater than 5 percent rated thermal power when it should state

less than 5 percent rated thermal power. From Westinghouse's calculations a

trip setpoint of less than or equal to 5%/2 seconds would require a rod drop

time of'less than or equal to 1.7 seconds.

At the time of the notification, McGuire Unit I was in Mode 1 operating at

100 percent and Unit 2 was in Mode 5 at the beginning of a refueling outage.

A licensee evaluation of the previous Unit 1 Rod Drop surveillance revealed

that McGuire Unit i rod drop times were 1.47 seconds. This is less than 1.7

seconds as required by the new Westinghouse determined requirements. On

February 5 and 6,1985, the Unit 1 Power Range Neutron Flux High Negative

Rate trip setpoints were adjusted to 21 percent of rated thermal power with

a time constant of greater than or equal to 2 seconds in accordance with

Westinghouse recommendations, Unit 2 setpoints will be set at a similar

value prior to the end of this refueling outage.

10. Inoperable Fire Barrier

On February 2, licensee personnel were preparing to implement a Nuclear

Station Modification when a i inch by 11 inch hole was discovered under

control board 2MC11. This hole connected the Unit 2 side of the Control

Room to the Unit 2 cable spreading room underneath the control room. It was

subsequently determined that a similar hole existed on the Unit 1 side in

the equivalent area under IMC11, but this hole was appropriately sealed by

fire barrier foam. A licensee evaluation failed to determine when or why

the hole was drilled.

TS 3.7.11 requires that all fire barrier penetrations (walls, floor /

ceilings, cable tray enclosures and other fire barriers) separating safety-

related fire areas or separating portions of redundant systems important to

safe shutdown within a fire area and all sealing devices in fire rated

assembly penetrations (fire doors, fire windows, fire dampers, cable piping,

and ventilation duct penetration seals) shall be OPERABLE at all times. The

fu e barrier between the Control Roor,and the Cable Spreading Room was found

by the licensee to have been inoperable for an indeterminate amount of time.

Upon discovery of the hole the licensee promptly took compensatory measures

and estab'iished continuous fire watches. The above event is a licensee

identified violation and will not be cited since it meets the NRC Enforcee

ment criterion in 10 CFR 2 Appendix C.

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11. Improper Installation Of Wiring During Modification Of Train "A" and "B"

Reactor Trip And Bypass Breakers

During the implementation of a Nuclear Station Design Modification (NSM) on

the Unit 2 Reactor Trip and Bypass Breakers, NSM MG-2-285 Rev. O, (commit-

ment to SSER No. 7, Section D.5.3) the technician responsible determined

that the NSM was not clear about the required cable separation for Train A

and Train B wiring components. As a result the technician did not perform

the modification but referred the problem to his supervisor. Subsequent

evaluation determined that the same design modification had been performed

on Unit 1 on March 26, 1984, NSM MG 1376 Rev. O.

A Quality Assurance inspection of the Unit 1 Reactor Trip and Bypass

Breakers determined that the Train A and Train B separation criteria was not

met, in that a Train A wire was routed in a Train B wire track. The NSM's

were not clear about required cable separation or which wiring tracks within

the trip breaker cabinets to use for the A and B trains.

10 CFR 50, Criterion III states in part that "... design control measures

shall provide for verifying or checking the adequacy of design..." and

further states that " design changes, including field changes, shall be

subject to design control measures commensurate with those applied to the

original design..." The original design incorporates 10 CFR 50, Appendix A,

Criterion 21 - Protection System reliability and testability, which states

in part that redundancy and independence designed into the protection system

shall be sufficient to assure that no single failure results in loss of the

protection function.

Contrary to the requirements of 10 CFR 50 Appendix B, Criterion III, NSM

MG-1376 Rev. 0 was incorporated into the Unit 1 Reactor Trip Breaker

cabinetry without adequate design control measures, in that no guidance was

provided to ensure that wiring separation criteria would be met. The above

constitutes a violation 369/85-06-01.

12. Unplanned Actuation of Engineered Safeguards Features (ESF)

On February 6, 1985, while Unit I was in Mode 3, an unplanned auto actuation

of Engineered Safeguards Features occurred when procedural prerequisites

were not met during the performance of PT/1/A/4601/03, Protective System

Channel III Functional Test (Unit 1), while a channel undergoing negative

rate trip adjustment was simultaneously out-of-service. A reactor trip and

turbine driven and motor driven auxiliary feedwater pumps initiation

occurred.

Procedure stcas 6.1 and 12.3 of PT/1/A/4601/03 were not met in that reactor

protective system instrumentation for Channel III A, B, C and D steam

generator lo-lo levels were in test with the bistables tripped while

Channel IV of the Nuclear Instrumentation (NI) power range was in test for

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adjustment of the negative rate trip per Procedure IP/0/A/3207/03K as

discussed in paragraph 9. When power range Channel IV was increased to

100 percent, the subsequent increase of steam generator 10-10 level trip setpoint

reached the actual steam generator level initiating the ESF actuation.

A few minutes later another inadvertent ESF actuation occurred resulting in

the automatic start of the A & B motor driven auxiliary feed pumps. An

electrician accidentally depressed a limit switch inside the reactor trip

breaker "A" (RTA) cabinet. After the cause was determined and corrected,

the plant was realigned to a normal shutdown lineup. The unit was in

Mode 3.

An evaluation of these incidents revealed the following concerns. Proce-

dural steps specifying that only one channel be tested at a time were

violated for both PT/1/A/4601/03, Protective System Channel III Functional

Test (Unit 1), steps 6.1 and 12.3 and IP/0/A/3207/03/K, Nuclear Instru-

mentation System (NIS) Power Range Drawer Calibration Procedure, Prerequi-

site 4.1. Furthermore, Control Room operators knew about this simultaneous

work and permitted it to be done.

TS 6.8.1 requires that written procedures shall be established, implemented,

and maintained covering the activities referenced in Appendix A of Regula-

tory Guide 1.33, Revision 2, February 1978 which includes the Nuclear

Instrumentation System. Contrary to this requirement, procedural steps

as noted above of PT/1/A/4601/03 and IP/0/A/3207/03K, were not correctly

implemented. This item in conjunction with the item in paragraph 14, is a

violation 369/85-06-02: Failure to Follow Procedure.

13. Diesel Generator Surveillance Inadequacies

On February 15, 1985, the licensee identified to the resident inspector that

McGuire has been in violation of TS Table 4.8-1, Diesel Generator Test

Schedule. This violation involved an interpretation of the criteria for

determining the number of failures and number of valid tests as identified

in the TS and Regulatory Guide 1.108, Rev.1. This criteria is based on

a per unit basis and the McGuire personnel had based their criteria on a per

diesel generator basis. Based on this interpretation, D/G 1A had a valid

failure on February 28, 1984, with unit start attempt 116 and a second valid

failure on July 22, 1984, with unit start attempt 133. On July 22, 1984,

the surveillance frequency for D/G 1A was increased to once every 14 days,

however, D/G 1B remained on a 31 day surveillance cycle. For Unit 2, D/G 2A

had a valid failure on July 8,1983, with unit start attempt 9, D/G2B had a

valid failure with unit start attempt 41. Since the criteria was not being

correctly interpreted at this time, it was not recognized that the surveil-

lance frequency for Unit 2 D/Gs was required to be increased to a frequency

of 14 days. Subsequently D/G 2B had another valid failure with unit start

attempt 42 on July 21, 1984, which should have increased the surveillance

to seven days for Unit 2 D/Gs. Action was taken at this time to increase

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surveillance frequency to D/G 2B to 14 days. On September 11, 1984, D/G 2A

again had a valid failure with unit start attempt 49. At this time D/G 2A

surveillance was increased to 14 days, when this was actually the 4th unit

failure and the frequency should have been increased to a 3 day interval.

On January 31,1985, D/G 2A had another failure which caused the diesel

to be declared inoperable and required disassembly and maintenance to be

performed which is still in progress at this time. On or about February 12,

1985, McGuire personnel recognized the interpretation problem and imple-

mented the 3 day requirement on 0/G 2B for Unit 2 and the 14 day requirement

on D/G1B for Unit 1. This item is identified as a violation 369/85-06-03,

370/85-06-01: Failure to Correctly Implement TS Surveillance Requirement 4.8.1.1.2.a.

14. Nuclear Service Water Valve Misalignment

During a routine tour of Unit 2, on January 23, 1985, the inspector

identified that 2RN-158 (RN pump 2B motor cooler inlet isolation) was not

" locked open" as required by 0P/2/A/6400/06, Nuclear Service Water System.

This observation was provided to the Shift Supervisor who took appropriate

corrective action. Subsequent investigation by McGuire station personnel as

described in Non-Routine Event Report No. 2-85-03 and Licensee Event Report

370/85-01 identified that this valve had apparently not been locked since

October 16, 1984. These reports concluded that this occurred as a result

of not adequately following 0P/0/A/6100/09, Removal and Restoration (R&R)

of Equipment. The R&R was issued October 15, to isolate RN pump 2B for

maintenance. On October 16, the R&R was cleared but the valve was returned

to an "open" position in lieu of " locked open" as prescribed by 0P/2/A/

6400/06. This failure to " lock open" this valve resulted in TS surveillance

4.7.4 not being accomplished for this valve since this valve is not checked

by the monthly surveillance test for this system. This item in conjunction

with the item in paragraph 12 is identified as a violation 370/85-06-02:

Failure to Follow Procedure OP/0/A/6100/09, Removal and Restoration of

Equipment For Valve 2RN-158.

15. Auxiliary Feedwater Overpressurization

The events relevant to auxiliary feedwater suction piping overpressurization

were analyzed in this, a followup inspection of an unresolved item (50-369/

85-08-07) identified in an earlier inspection report. There are two concerns

pertaining to this area. Both of these concerns are associated with a

failure to take appropriate corrective action in a timely manner. The first

concern is the lack of notification to plant operations personnel of a

potential problem with backleakage past feedwater check valves which could

potentially cause a degradation in the capability of auxiliary feedwater

pumps to fulfill this safety function. This was identified by a design

engineering memorandum in which a water hammer event occurred at a foreign

plant due to leaking check valves and piping configuration. In this memo

the engineer recommended a provision to provide indication of leakage past

the check valves and also recommend that operations perations personnel

should be cautioned about this potential problem. In addition, Westinghouse

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notified Duke Power Company (DPC) of the above backleakage problem in a

letter dated November 11, 1981. This letter also proposed modifications to

detect leakage and modify operating procedures to minimize this potential

problem.

A January 1984, report was issued discussing operability of industry

auxiliary feedwater pumps due to backleakage. This report provided specific

procedural guidance on how to detect backleakage and stated that actions to

mitigate the situation should be provided. A DPC memorandum to various

superintendents dated June 22, 1984, identified among other recommendations

that operations should initiate as soon as possible a walkdown inspection

once per shift.

The second concern is a failure to adequately take prompt corrective action

for the improper installation of the turbine driven auxiliary feedwater pump

(TDAFWP) discharge stop check valve (ICA-22). On August 25, 1981, the

suction piping of the TDAFWP was overpressurized. Contributing to this

problem as reported in Reportable Occurrence Report R0-369/81-136 dated

September 8, 1981, was that the stop check valve in the pump discharge was

mounted in a horizontal pipe with the cylinder in a horizontal position so

that closure is not aided by gravity. Although this was identified as

a contributing factor, corrective action was not taken to correct this

deficiency. Following the January 1984 industry report and review by the

licensee, a DPC memo dated June 22, 1984, identified that stop check valves

were installed in a horizontal position and McGuire Projects should initiate

a Nuclear Station Modification (NSM) to correct this discrepancy. On

August 26 and again on August 30, 1984, the TDAFWP suction piping was

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overpressurized due to back leakage past the check valves and the stop check

valve. It was not until September 5,1984, that NSMs were originated to

install a monitoring system to determine leakage past the check valves and

to correct the installation of the stop check valves, although this problem

was identified on various occasions since 1981.

10 CFR 50, Appendix B, Criterion XVI as implemented by Duke Power Company

(DPC) Topical Report, Quality Assurance Program Duke-1-A, Amendment 7,

Section 17.2.16 requires that conditions adverse to quality be promptly

identified and corrected and that the identification of the significant

condition, the cause of the condition 6nd the corrective action shall be

documented and reported to appropriate levels of management.

Contrary to the above, conditions adverse to quality were not promptly

identified and corrected, as detailed below. An occurrence on Unit 1 as

reported in R0-369/81-136, caused overpressurization of the suction side of

the turbine driven auxiliary feedwater pump. Identified as contributing to

this problem was the stop check valve on the outlet of the pump being

mounted in a horizontal position which prevents the closure of this valve to

be aided by gravity as designed. Furthermore, on November 11, 1981,

Westinghouse notified DPC of a potential problem concerning the design of

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the auxiliary feedwater pump discharge piping and valve arrangement such

that damage could occur which would compromise the safety-related function

of the auxiliary feedwater system. Westinghouse in this letter, recommended

system modifications and an operating procedures amendment to detect and

correct this problem.

No actions were taken on these items identified above until September 5,

1984, when NSM 1-1705 and NSM 2-0550 were generated to replace the existing

stop check valves with a different design valve, and NSM 1-1706 and NSM

2-0551 were generated to install a temperature monitoring system as

recommended by Westinghouse. As of March 12, 1985, NSM 1-1706 and NSM

2-0551 are in process of being installed and NSM 1-1705 and NSM 2-0550 are

scheduled for outages in 1986 due to material delivery.

This item is identified as a violation 369/85-06-04, 370/85-06-03: Failure

to Take Prompt Corrective Action to Notify Operations Personnel of Potential

Degradation of Auxiliary Feed Water System and Correct Improper Installation

of TDAFWP Discharge Stop Check Valve. This violation is applicable to both

units. This item closes unresolved item No. 50-369/85-08-07.

16. Containment Integrity

On February 19, 1985, valve 2SA-1 (the steam generator (S/G) 2C steam line to

the turbine driven auxiliary feedwater pump isolation valve) was disassembled

for maintenance. This created a possible flow path between inside contain-

ment and the interior doghouse. The valve was discovered disassembled by

the licensee on February 21, 1985, at 3:12 p.m. Between these times, core

alterations were made. TS 3.9.4 requires that containment integrity be

maintained during core alterations or movement of irradiated fuel within

containment. Core alterations are defined in TS definition 1.9 as the

movement or manipulation of any component within the reactor pressure vessel

, with the vessel head removed and fuel in the vessel. Suspension of core

l alteration shall not preclude completion of movement of a component to a

l safe conservative position. The valve being disassembled, in conjunction

with S/G 2C secondary side being open to containment atmosphere provided a

flow path directly from containment, through the S/G secondary side, through

the valve to the " dog house" (piping penetration room), directly to the

outside environment.

Two possible flow paths into S/G 2C existed inside containment. The sludge

lance cover plates were removed but the ports were taped closed with plastic

for housekeeping. These plates cover four two-inch ports and two six-inch

ports. A flow path also existed from containment atmosphere into the feed-

water line of S/G 2C, 2CF-27, a sixteen-inch check valve was disassembled

for maintenance, but plastic was taped over the valve body for housekeeping.

Operations personnel believe the containment purge ventilation system (VP)

was operating throughout the time 2SA-1 was open. This created a slight

vacuum within containment, ensuring any leakage would have been into

containment.

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The following steps are used in scheduling work during an outage:

a. The Outage Coordination group make a schedule of work to be performed

during an outage.

b. The Operations Unit Coordinator reviews the schedule.

c. Planning personnel schedule work requests using the Outage Coordination

group's schedule as a guideline,

d. Each work request is sent to the shift supervisor for clearance to

begin work.

The following occurred when scheduling the work on 2SA-1:

a. The work request description for 2SA-1 was typed in Project 2 as

"2SA-11".

b. Prior to core alterations, Operation staff personnel and Outage

Coordination personnel reviewed the outage schedule. The work on 2SA-1

was not identified as a potential containment integrity problem due to

the incorrect entry.

c. Planning personnel scheduled WR 1202930PS on February 18.

d. The Assistant Shift Supervisor signed the " clearance to begin work"

line on WR 1202930PS.

Once the work on 2SA-1 was scheduled, the Assistant Shift Supervisor was

the only control point to stop the work. It is not realistic to expect a

shift supervisor to catch every work request that could cause a containment

integrity problem during an outage because: (1) there are a large number

of containment penetrations and different ways to isolate each one (the

procedure used to verify containment integrity, PT/2/A/4700/02C, is 62 pages

long) and (2) the shift supervisor has a large number of work requests on

which to give clearance. The shift supervisors must depend on the Outage

Coordination group, the Unit Coordinator, and Planning to control scheduling

work on equ.ipment that can potentially affect containment integrity.

The Assistant Shift Supervisor stated that when he saw the work request on

2SA-1, he did not realize it could affect containment integrity. He saw

that 2SA-1 could be worked on using an existing tag out (block tag out 85-F)

so he signed the clearance line on the work request.

Corrective action to prevent future occurrence will include modifying work

request entries on outage schedules to note that the item is a " Potential

Containment Integrity Item." In future outages procedures will be modified

to reduce the likelihood of this event occurring by involving the Outage

12

Coordination Group, the Unit Coordinator and the Planners such that a

typographical error or oversight will be determined on a subsequent review

by one of these groups prior to sending the work request to operations for

clearance to begin work.

The above event is a licensee identified violation and will not be cited

since it meets the NRC enforcement criterion in 10 CFR 2, Appendix C.

17. Containment Pressure Control System (CPCS)

Subsequent to identification by the licensee, the inspector conducted a

review of TS 3.3.2, Engineered Safety Features Actuation System Instrumenta-

tion, specifically the Containment Pressure Control System (CPCS). The

function of the CPCS is to preclude depressurization of containment by

terminating containment spray and air return fans when they are no longer

required. TS Table 3.3-4 identifies the CPCS trip setpoint as &0.25 psid

for a start permissive and termination function. Table 3.3-3 identifies for

CPCS that for both the start permission and termination function there are

four total channels per train, implying a total of eight separate channels

(four for start permissive and four for termination). In actuality there

are a total of four channels per train to perform both functions. Also

Table 3.3-3 lists that two channels per train are required to trip. This

is in error. There are four pressure switches per channel: one switch

provides on an increasing pressure in containment, a permissive signal to

allow startup of the containment spray (NS) pump in that train, this switch

also provides an automatic trip signal if the spray pump is running and

containment pressure decreases to 0.25 psid; one pressure switch, on an

increasing pressure in containment provides a permissive signal to the NS

pump discharge valves, on a decreasing pressure of 0.25 psid this will

automatically shut these valves; one pressure switch provides a start

permissive signal for the Air Return and Hydrogen Skimmer Fan and will stop

the air return and Hydrogen Skimmer Fan on a decreasing pressure; and the

fourth pressure switch will provide a permissive signal for the hydrogen

skimmer fan discharge valve and the Air Return Fan damper, and will shut the

damper and valve on a decreasing pressure.

Table 3.3-3 also requires that CPCS must have a minimum of three channels

per train for operation. However, any failure of an individual pressure

switch would render that train inoperable, therefore all four pressure

switches should be required. The action statement for CPCS allows power

operation to continue with one less than the total number of channels if

(a) the channel is placed in the tripped position - there is no tripped

position for this instrument, and (b) the channel may be bypassed for up to

two hours for surveillance testing of other channels - there is no bypass

function for this channel.

The design for this system allows valves to be shut while pumps and/or fans

are running, which could cause damage to the component. The plant currently

operates under a TS interpretation which results in declaring an associated

component inoperable if any one or more of the four channels in that logic

train is inoperable.

'

'

.

13

This item is identified as Unresolved Item (369/370-85-05): Resolution of

Containment Pressure Control System Design Questions, Pending Additional

Review By Regional and NRR Design Engineering Personnel.

18. Surveillance Testing

The surveillance tests categorized below were analyzed and/or witnessed

by the inspector to ascertain procedural and performance adequacy. The

completed test procedures examined were analyzed for embodiment of the

necessary test prerequisites, preparations, instructions, acceptance

criteria, and sufficiency of technical content. The selected tests

witnessed were examined to ascertain that current written approved

procedures were available and in use, that test equipment in use was

calibrated, that test prerequisites were met, system restoration completed

and test results were adequate. The selected procedures perused attested

conformance with applicable TS and procedural requirements, they appeared to

have received the required administrative review and they apparently were

performed within the surveillance frequency specified.

Surveillances

PT/1/A/4600/03E Quarterly Surveillance Items

PT/2/A/4600/01 RCCA Movement Test

PT/1/A/4350/02B Diesel Generator 1B Operability Test

PT/2/A/4150/16 Steam Generator Temperature Checklist

PT/2/A/4200/02C Containment Integrity Verification During Core

Alterations

PT/1/A/4204/02 ND Valve Stroke Timing

PT/1/A/4203/02 NB Valve Stroke Timing

PT/1/A/4451/02 VB Valve Stroke Timing

PT/1/A/4405/02 YM Valve Stroke Timing

PT/1/A/4208/01B NS Pump 1B PERF Test

PT/1/A/4208/01A NS Pump 1A PERF Test

PT/1/A/4403/01A RN Train A PERF Test

PT/1/A/4252/01A Motor Drive Aux Feed 1A PERF Test

PT/1/A/4209/018 NV Pump PERF Test

PT/0/A/4209/01C Standby Makeup Pump PERF Test

PT/1/A/4252/01 Aux Feed Pump #1 PERF Test

PT/0/A/4457/01A Control Room Chilled Water Pump 1 PERF Test

PT/1/A/4601/08A SSPS Train A Periodic Test

PT/1/A/4206/01A NI Pump 1A PERF Test

PT/1/A/4601/03 Proctive System Channel III

PT/0/A/4601/07A A reactor Trip Breaker Response Test

PT/0/A/4601/07B B Reactor Trip Breaker Response Test

19 Maintenance Observations

.

The maintenance activities categorized below were analyzed and/or witnessed

by the resident inspection staff to ascertain procedural and performance

adequacy. The completed procedures examined were analyzed for embodiment of

E

,

14 ,

the necessary prerequisites, preparation, instruction, acceptance criteria

and sufficiency of technical detail. The selected activities witnessed were

examined to ascertain that where applicable, current written approved

procedures were available and in use, that prerequisites were met, equipment

restoration completed and maintenance results were adequate. The selected

work requests / maintenance packages perused attested conformance with

applicable TS and procedural requirements and appeared to have received the

required administrative review.

Work Request Equipment

65401 Battery EVCA

85953 Train B VX

93356 Train B VC

65320 Train B VC

41203 RF Pump C

123097 S/G C Narrow Range Level

119109 Loose Pails Detector

85884 Valve 1 SA 49

039480 Turbine Driven Auxiliary Feedwater

950119 A Train VC

93296 A Train VE

123349 Turbine Stop Valve TV#1

040175 Containment Pressure Channel III

03975 FWST Level

123092 Repair as Necessary "B" S/G PORV (ISU-13)

122989 Repair ICA-49 Check Valve

123014 D/G 1A Cylinder #2L Bad Temperature Indicator

Check and Repair

20. IE Circulars, Construction Deficiency Reports and Bulletin Closecut

The following IE Circulars and Construction Deficiency Reports are being

closed based on review of these items conducted at Region II:

Docket Number 50-369

CDR 82-06 78-CI-18

CDR 82-72 80-CI-03

CDR 83-15 80-CI-04

CDR 83-46 80-CI-13

80-CI-15

81-CI-13

81-CI-14

.

.

.

15

Docket Number 50-370

CDR 81-06 81-CI-12

CDR 83-01 81-CI-13

CDR 83-03 81-CI-14

CDR 83-07

CDR 83-27

IE Bulletin 79-07, Seismic Stress Analysis of Safety-Related Piping, is

considered closed for the purposes of the Regional Inspection Program. This

closure does not affect the status of any NRR evaluations. Related inspec-

tion followup will be performed as required by IE Bulletin 79-14, Seismic

Analysis for As-Built Safety-Related Piping Systems.

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