IR 05000277/1997007

Insp Repts 50-277/97-07 & 50-278/97-07 on 970921-1122. Violations Noted.Major Areas Inspected:Operations, Surveillance & Maintenance,Engineering & Technical Support & Plant Support Areas

ML20197H061
Person / Time
Site:	Peach Bottom
Issue date:	12/16/1997
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20197H012	List: IR 05000277/1997007 ML20197H008 ML20197H043
References
50-277-97-07, 50-277-97-7, 50-278-97-07, 50-278-97-7, NUDOCS 9712310174
Download: ML20197H061 (61)

Text

__ _. - _ _. _ . _ _ _ . _ _ . _ . - . . _ _ . _

i

,

• i

!

U. S. NUCLEAR ROGULATORY COMMISSION  :

REC.10N I [

Docket Nos. 50 277,50 278 License Nos. ' DPR 44, DPR 56 Report Nos. 97 07  !

!

C

'

Licensee: PECO Energy Company Facility: Peach Bottom Atomic Power Station Units 2 end 3

!

Dates: September 21 November 22,1997 ,

r

,

inspectors: R. Barkley, Acting Senior Resident inspector -

M. Buckley, Resident inspector i R. Cain, Contractor, Idaho National Engineering Laboratory T. Hoeg, Reactor Engineer K. Kolaczyk, Reactor Engineer R. Ragland, Health Physics inspector B. Welling, Resident inspector J. Yerokun, Senior Reactor Engineer Approved By: C. J. Anderson, Chlef Reactor Projects Branch 4 Division of Reactor Projects .

.

9712310174 971216 POR-0 ADOCK 05000277-PDR g

.

,

w _ _ _ .

-,

_ . _ _____ _ .- __ _ .___ _ _ ___ _ . - - _ _ _ _

,

.

. r EXECUTIVE SUMMARY

Peach Bottom Atomic Power Station NRC Inspection Report 50 277/97 07,50 278/97 07

. This integrated ir.spection report includes aspects of licensee operations; ourveillance and 1 maintenance; engineering and technical support; and plant support areas.

l PJAnt Ooorations: [

• The inspectors concluded that refueling activities were conducted in a safe manner with very good independent varlfication of fuel element shuffles. (02.2)

,

• Overtime approvals during the Unit 3 outage were generally limited, justified and well controlled. However, the practice of permitting blanket approvals for overtime work on safety related activities for multiple weeks with no hourly limit specified resulted in abuses that were considered a breach in the intent of the overtime authorization process. (02.3)  ;

• Overall, the inspectors found that there are odequate controls to ensure that spent

, fuel pool (SPF) temperature remains below its design limit of 150F, although operators were not knowledgeable of the specific procedurellimits when spent fuol pool cooling for Unit 2 was isolated. Modifications are scheduled to be implemented in the near future that will install two valves in the SFP cleanup system such that third domineralizer can be readily shared between each unit.

(02.4)

• The NRC Identifit.d an instance of poor equipment status control for the standby safety related 2D 2 station battery charger. This battery charger had been in a ,

degraded, inoperable condition since April 1997, but was not being tracked by  ;

^

operations personnel. (02.5)

• Two minor RHR system mispositioning events occurred during the Unit 3 outage. .

However, overall RHR/ shutdown cooling system status control was very good. l (02.6)

• Operations personnel monitored the cooldown rate as required by the procedure during and af ter the reactor scram transient and maintained the reactor coolant cooldown rate within the requirements of the TSs. Some administrative errors were noted during the conduct of the procedure, but they did not affect the temperature readings and rebutted in no significant safety Irnpact. However, these errors represented another example of failing to follow procedures. (NOV 97 07 02, Example 1) (03.1)

-_ . _ _ . _ .. ._ , . ._

. _ _ _ - _ . _ _ _ _ _ - - _ . _ _ - _. __ _ _ _ _

,

i

!

-

.

Executive Summary (cont'd)

,

o Failure to follow procedures by an equipment operator swapping station battery chargers caused a Unit 2 main turbine trip and reactor scram. Although this operator was recently quallfled, shif t supervision did not take such prudent actions as discussing the procedure with the operator or providing direct supervisory oversight prior to and during the performance of the test. (NOV 97 07 02, Example 2) (04.1)

e Overall, post scram review actions following the November 9 scram were good. ,

However, the STA did not compare plant response with the UFSAR, as described in '

operations guidance. This, combined with a similar self identified issue, revealed a minor weakness in operators' awareness of the need to refer to licensing basis and UFSAR information when certain off normal or degraded equipment conditions arise.

(04.2)

e NRC Identification of an out of-recification high oillevel on the in service 3D high pressure service water (HPSW) pump motor revealed a minor lapse in attention to-detall on the part of equipment operators. (04.3)

e POhC members demonstrated a good safety perspective and maintained a sound questioning attitude during meetings in October and November 1997. (07.1)

Maintenance:

o On September 22,1997, PECO identified that a safety related high pressure service water (HPSW) pump was electrically uncoupled without being isolated because contractor personnel thought they were working on a non safety rtlated service water pump that was electrically isolated. This event highlighted weaknesses in procedural adherence, particularly the use of work package documentation at the job site, self checking, and o questioning attitude that led to multiple breaches in work process barriers. (NOV 97 07 02, Example 3)(M1.1)

e Maintenance activities associated with reactor pressure vessel disassembly were v5 ell controlled and conducted per procedure. (M1.2)

e The failure of the 2A RFPT trip system would have prevented the 2A RFPT from being remotely tripped in the event of a high reactor water level signal Moreover, PECO did not determine the root cause of the f ailure before restarting Unit 2.

However, since no testing is performed on the mechanism during power operation, PECO had nc way of knowing that the trip had f ailed prior to the actual f ailure.

Pending evaluation of any testing possible while on line to verify and possibly identify this type f ailure, as well as information in the pending LER on the safety significance of this event, this item remains unresolved. (M2.1)

,

iii

___ _ _-. _,, . . _ - -_ -

. __

-. . - - - - - - - . - . . . _ - - - . _ . --

,

-

!

<

Executive Summary (cont'd)

r e An inadvertent trip of the E 43 bus and subsequent actuation of the E 4 EDG were i caused by krtowledge weaknesses on the part of l&C techr.icians and by an inadequate rrocedure. Operator response to this event was very good Corrective ,

actions for this issue were appropriate. PECO'S failure to ensure that the procedure was adequate to properly control the testing evolution constituted a Non Cited Violction (NCV 50 277 (278)l97 07 05)(M3.1)

'

e The ISI Program was being implemented with an approved plan and in accordance '

with ASME Code Section XI. Code Cases used had been approved for use as part of the plan and reliefs from Cooe requirements that were used had been approved i by the NRC. Program engineers showed good understanding and ownership of the ISI program. (M8.1) ,

,

o The licensee was implementing the snubber surveillance program in accordance ,

with the technical requirement manual to satisfy the Code requirements. (M8.2) l Enoineerina:

o PECO established a program that met their commitments to GL 8910," Safety-Related Motor Operated Valve Testing and Eurveillance." Final validation of MOV svcitch settings was completed by the close of this inspection period. (E1.1)

e Based on the review of key aspects of this modification, PECO installed the ECCS suction strainers in accordance with modification P 350. Weldir g was performed by qualified individuals in sccordance with ASME Code Case N 5161. (E1.3)

• The identification of cracking on three of the ten recirculation riser pipe elbow welds posed a significant challenge to PECO's engineering organization late in the Unit 3 .

refueling outage. The te;hnical support provided by Engineering in this matter was considered very good, particularly given the lack of significant industry experience r with similar cracking, although documentation of some supporting activities lagged, ,

in part, due to the compressed time frame for their resolution. (E1.4) i e PECO senior management demonstrated a good safety perspective and acted conservatively in changing out SSPV diaphragms, known te be susceptible to hardening, on a schedule more aggressive than planned in September 1907. (E1.5) -

e Operations promptly identified and initiated an action request to address the out of-specification tailpipe temperature on the Unit 3 'E' SRV. However, the inspectors considered that er'gineering was slow to develop a comprehensive monitoring plan for the degradod condition. The final monitoring plan was very good, and PECO later took conservative actions to shutdown Unit 3 and replace the SRV after the end of thia inspection period. (E2.2)

e> Since PECO has shown proper test operation of the EDG, verified that the ,

'

ventilation system had additional capacity during startup testing, and has not t

iv

._. _ _ _ _ , _ , - . . _ , _ . - - , . . _ . , . . _ _ .-

..

._ ______ __ _ __ _ _ _ _ _ _ _ _ _ _ _ _ _ . . _ _ . .

,

!

,

<

Executive Summary (cont'd) l

!

modified the system,it is reasonable to conclude that the EDG compartment ventilation system has been operable. Although past documentation was minimal, ,

the recent revisions to testing procedures provide documentation of proper l operation of the ventilation system. (E2.3)  ;

i e While the initial HPCI troubleshooting plan was limited in scope after early, more j elaborate plans were developed, fallow-on troubleshooting identified the source of the water leakage noted during surveillance testing in late September. Plans are ;

'

being developed to correct the source of the leakage. The inspectors did not '

consider the length of the delay in troubleshooting commensurate with the high safety importance of HPCI, but recent actions to more aggressively address the ,

leakage problem were considered quite conservative. (E2.4) .

!

Plant Suongs e PECO continued to maintain an effective radiological controls program. This was ,

evidenced by extensive planning and effective implementation of radiological j controls for outage work, initiatives to use a gamma imaging device to identify :

radiation sources ar'd management commitment to establish a full time multi-disciplined source reduction *Fix It Now" team were commendable. However, a weakness in radiological control planning was identified in that the ALARA review for the Unit 3 emergency core cooling system (ECCS) suction stralner modification did not include a documented evaluation of radiation sources in the overhead of the torus room that contributed to radiation dose. (R1.3) ,

• - During a tour of the western fence perimeter early la the inspection period, ths inspectars noted substantial rock debris had accumulated against the security fence at various locations. At the end of the inspection period, PECO removed most of this debris via manual methods. (S1)

• The inspectors reviewed the listing of fire watches, confirmed the proper termination of selected fire watches no longer needed and discussed with security personnel the methods taken to randomly check on the actual completion of these fire watches. The inspectors considered this program to be a very reliable and effective system for ensuring the timely conduct of fire watches where required.

(F1)

v

_ _ _ , ,_ __

._. . _ _ - _ _ _ _ _ _ . _ . _ _ _ _ . _ _ _ _ _ _ . - _ . -,

!

i i

• , j l

i

,

TABLE OF CONTENTS  !

'

EXECUTIVE SUMMARY ' . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Il

-

!

Summary of Plant Status . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .~ . . . . . . . . . . . . . . 1  !

i

-

1. Operat ions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 l

,_

01 Conduct of Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . -. . 1 :l 01.1 General Comments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1  :

01.2 Response to CRD Accumulator Trouble Alarm . . . . . . . . . . . . . . . 3 j

O2 Ooorational Status of Facilities and Equipment . . . . . . . . . . . . . . . . . . . . 4

, 02.1 Engineered Safety Feature System Walkdowns (71707) . . . . . . . . .- 4

]

'

O2.2 Unit 3 Refueling Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 -  ;

-

02.3 l Outage Overtime Usage and Approvals

-

. . . . . . . . , . . . . . . . . . . . 5 i

'

, 02.4 Unit 2/3 Spent Fuel Pool Operations . . . . . . . . . . . . . . .-. . . . . . . 5 j

- 02.5 2D 2 Station Battery Charger Degraded Condition . . . . . . . . . . . . 6 j

'03 - Operations Procedures and Documentation . . . . . . . . . . . . . . . . . . . . . .' . 8 ~  ;

03.1 Residual Heat Removal System Status Control /Mispositionings  !

( U nit 3 ) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . = . . 8 03.2 Unit 2 Cooldown Monitoring Following the November 9th Reactor 'l

'

Scram ................................................ 8 4 04 Operator Knowledge and Performance . . . . . . . . . . . . . . . . . . . . . . . . 10  !

!

04.1 Unit 2 Scram . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 04.2 Licensee Post Scram Review (Unit 2) . . . . . . . . . . . . . . . . . . . . 11

- 04.3 3D High Pressure Service Water Pump Motor - High Oil Level . . . . _12 07 Qualitv Assurance in Operation . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13 07.1 Plant Operations Review Committee (PORC) Meeting . . . . . . . . . 13 08 Miscellaneous Operations issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13  :

08.1- (Closed) Unresolved item 9 5 04 0 2 - . . . . . . . . . . . . . . . . . . . . . 13 i i

ll Ma!ntenance and Surveillance . . . . . . . . - . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14 l M1i Conduct of Maintenance and Surveillance . . . . . . . . . . . . . . . . . . . . . . 14 .;

M1.1 Inadvertent Electrical Disconnection of the 3B High Pressure Service j

+ Water (HPSW) Instead of the 3B SW Pump

. . . . . . . . . .............-.......................14

- M1.2 - Preparations for Refueling (Unit 3)

-

..- . . . . . . . . . . . . . . . . . . . . 16 M1.3 Outage Surveillance & Preventive Maintenance Activities . . . . . . 16 ~

.

lM2: - Maintenance and Material Cnndition of Facilities and Equipmt it . . . . . . 17- .

. . M2.1 : Reactor Feedwater Pump High Reactor Water Level Turbine Trip Inoperability s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ' . . 17

-

-

M3 - Maintenance Procedures and Documentation . . . . . . . . . . . . . . . . . . . 19  !

- M3.1Linadvertent Trip of the Unit 3 E-43 4 kV Bus During Relay Testing I Activities (Closed) LER 50 277(278)/2 97-006 . . . . . . . . . . . . . 19  ;'

M8 Miscellaneous Maintenance issues . . . . . . . . . . . . , , . . . . . . . . . . . . 20 -

- M8.12 Inservice inspection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20 ,

-- M8.2 Snubber Surveillance Program . . . . . . . . . . . . . . . . . . . . . . . . . . 23 i

vi.

~

-

j

_

!

y >

j .

,,we- + , -ny,+,-e r w , ,r-m--,,4n,. ,--e-g.a., , ,,-ye.,-_-n,-,,,--mm,w e g-, .,,-, m e -w, w w gmy , 4,

- ,. - - . - - - . - - - _ - - ~ -

_

. .--

,

.

Table of Contents (cont'd)

!

lli. Engine e ring . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 5 E1 Conduct of Engineering - Motor-Operated Valve Program Review (Tl '

2512/109) ..........................................25 E1.1 Motor Operated Valve Full Flow Test and Core Spray injection V a lv e s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 6 '

E1.2 MOV Margin improvement Program . . . . . . . . . . . . . . . . . . . . . 30 E1.3 Emergency Core Cooling System (ECCS) Suction Strainer Modific a tion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 0 E1.4 Unit 3 Jet Pump Riser Elbow Weld Cracking . . . . . . . . . . . . . . . 31

- E1.5 Replacement of Deficient Hydraulic Control Unit (HCU) Scram Solenoid Pilot Valve . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33 E2 Engineering Support of Facilities and Equipment .................34  !

'

E2.1 Emergency Diesel Generator Lube Oil Piping Potential 10 CFR 21 '

lssue ..........................................34 E2.2 'E' Safety Relief Valve Tailpipe Temperature Increase (Unit 3) . . . 35 E2.3 Emergency Diesel Generator Ventilation Review (CLOSED)

Unresolved item 97 02 06: Operability Testing of the Emergency Diesel Generator Ventilation Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36 E2.4 Unit 2 High Pressure Coolant injection (HPCI) System Turbine Leakage.............................................38 E8 Miscellaneous Engineering issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39 E8,1 (Closed) Unresolved item 94 12 02 . . . . . . . . . . . . . . . . . . . . . 3 9 E8.2 (Closed) Unresolved item 9 4 12 04 . . . . . . . . . . . . . . . . . . . . . 3 9 E8.3 (Closed) Unresolved item 928202....................39 E8.4 (Closed) Violation 50 277(278)/96 08 02. Failure to Meet TS Requirements for APRM Instrument Surveillance / Operability . . . . 40 E8,5 (Closed) Unresolved item 50 277(278)/96 08 03. Controls

'

Over the Core Thermal Power Calculation Programs . . . . . . . . . . . . . . . 40 E9 Review of Updated Final Safety Analysis Report (UFSAR) . . . . . . . . . . . 41 IV. Plant Support ................................................41 R1 Radiological Protection and Chemistry (RP&C) Controls . . . . . . . . . . . . 41 RI .1 ALARA ......................................... 41 R1.2 Control of Contamination and Radioactive Material . . . . . . . . . . 44 R1.3 External Exposure Controls . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 5 R5 Staff Training and Performance in RP&C . . . . . . . . . . . . . . . . . . . . . . . 45 R6 RP&C Organization and Administration . . . . . . . . . . . . . . . . . . . . . . . . 46 R7 Ouality Assurance in RP&C Activities . . . . . . . . . . . . . . . . . . . . . . . . . 47 R8 Miscellaneous RP&C lasues

..................................................48 R8.1 (Closed) Inspector Followup ltem 50 387;388/97-06-05," Multiple Personnel Contamination" ...........................-48 vii

. - -

^

.

.

Table of Contents (cont'd)

R8.2 (Closed) Unresolved item 50-277(278)/97-01-02- Effect of Control Rod Boron Leakage on Core Reactivity . . . . . . . . . . . . . . . . . . . 48 S1 Conduct of Security and Safeguards Activities . . . . . . . . . . . . . . . . . . 48 F1 Status of Fire Protection Facilities and Equipment . . . . . . . . . . . . . . . . 49 V. M a na ge me nt Me e ting . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 9 X1 Exit Meeting Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 9 X2 Review of UFSAR Commitments . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49

,

viil

_ _ . .

.

Report Details Summary of Plant Stalm PECO operated both units safely over the period of this report.

Unit 2 entered the period at 100% power. On November 9, the plant scrammed from 100% power when the improper performance of an evolution swapping battery chargers resulted in a voltage depression on a vital bus that actuated generator protective relays, resulting in a turb4ne trip and subsequent reactor scram. The plant returned to 100%

power on November 11 where it remained for the rest of the period.

Unit 3 entered the period at 66% power,in end of-cycle coast down. The plant was subsequently taken offline on October 3,1997, to commence refueling outage 3R11.

During that outage, a n'imber of maintenance and surveillance activities were conducted and several major modifications were installed, including replacement of the emergency core cooling system suction strainers per Bulletin 96-03 and installation of wide range nuclear instruments in lieu of the source and intermediate range nuclear instruments. The unit returned to power operations on November 2 af ter completion of an outage that lasted just under 30 days. However, due to cracking identified on three of ten recirculation riser pipe elbow welds, PECO elected to develop a new operating strategy that limited recirculation flow such that the plant could be returnad to power until the first half of 1998 (at which time a repair strategy could be developed) without having these cracks grow significantly in length. As a result, the plant operated at 80% recirculation flow and 93%

power, except for a three day period at 91% flow and 100% power during which time the plant completed power ascension testing.

L.EMIRilSDA 01 Conduct of Operations'

01.1 General CJamDDia in general, operators performed routine activities and outage related evolutions in a satisf actory manner. Operbtors also responded well to off normal conditions, such as the November 9 scram on Unit 2 and the subsequent failure of thu 2A reactor feed pump to trip.

The inspectors observed that communications among operators were generally very good. In a few instances, shift management coached operators on the proper use of three part communications. The inspectors observed the turnover process for several shift turnovers and found that operators performed thorough control room board walkdowns.

1 Topical headogs such se 01. M8. etc., re used an netwdance with the N4C standarth,ed reactor trapection report cuttne enorvidust reports are not espected to address et cuttne topics.

_ _

-

.

.

Operators typically conducted good briefings prior to significant operations and testing, and following shif t turnovers. Exceptions included the inadequate pre job brief;ng and supervisory oversight of an equipment operator during a battery charger swapover which contributed to the November 9 scram on Unit 2 when the operator did not adhere to the procedure.

Unit 3 Reactor Shutdown for Refuetina Outaae 3R11 The inspectors observed portions of the reactor shutdown evolution from the control room on October 3, and determined that, overall, operators performed satisf actorily. The inspectors found that:

• Communications were geneially good. . .ever, minor comrnunication and/or coordination lapses occurred c' . ting periods of high activity and during testing of the main turbine.

• Af ter operators had shifted steam seal supply to auxiliary steam, they experienced a trip of the auxiliary boiler. This caused condenser vacuum to lower, requiring the operators to terminate main turbine testing and perform a manual reactor scram earlier than planned. Although operators had problems with the boiler earlier that day, the crew did not station an operator at the boiler or discuss shif ting steam supplies as contingencies.

• Operator actions following the manual reactor scram were very good.

Reactor Startuo from 3R11 The inspectors observed that control room operators generally performed well during the startup from the refueling outage. The inspectors found that:

• Operators closely monitored the new wide range neutron monitoring system (WRNMS) during the approach to criticality. Operators considered that the WRNMS provided clear indication both at reactor criticality and during the power ascension.

• Although there were numerous staff personnelin the control room during the startup ovolution, operators were not distracted from their duties. Reactivity changes were performed in a controlled manner.

• The control room supervisor provided good command and control.

• Communications in the control room were very good.

.

.

• Procedure weaknesses led to a minor reactor level excursion from its normal level of 23" to about 17". This occurred when the capacity of the startup level controller was exceeded while the operators were raising power with reactor pressure at 450 psig. Operators briefly entered the applicable off-normal procedure and restored level to normal. Operations initiated corrective actions to revise the start up procedure.

01.2 Response.Jo CRD Accumulator Trouble AI1(m o. Insoection Secoe (71707)

On October 6 the inspector observed an equipment operator drain a Control Rod Drive (CRD) Hydraulic Accumulator in response to a control room CRD Accumulator trouble alarm.

b. Observation and Findinat During observation of an equipment operator performing SO 3.7.B-2," Control Rod Drive Hydraulic Scram Accumulator Nitrogen Charging without isolating the HCU" on hydraulin control unit (HCU) 30 55, the inspector noted the following:

• The equipment operator reviewed the copy of the procedure at the Operations CRD Charging Equipment locker and found it to be an old revision. He obtained a current revision copy from the control room.

• The operator verified the accumulator trouble alarm came in due to a water prob'em. Although accumulator trouble alarms caused by water problems are considered uncommon, the operator believed it happens more during long continuous plant runs.

• Initially, after the operator finished draining the water, the vent plug had a small nitrogen leak identified with leak detection fluid, but it stopped after the operator applied more torque to the vent plug. The procedure did not specify a torque value or over torque caution.

• While venting the water from the instrument block, the operator allowed water to get under the plastic bag and rags onto the reactor building floor near the HCU. The operator noted the water spilled and proceeded to wipo up the potentially contaminated water. An HP arrived and took swipes of the dried spill area and found no contamination.

An independent verification by the inspector indicated that the alarm for the accumulator trouble had cleared.

-- _

. - - - - - . _ . _ _ _ _ _ _ _ _ _ _ _. _ .

,

,

c. Conclusions Operator 6 responded promptly and effectively to the CRD accumulator trouble alarm ,

and to the complications that arose during the venting of the HCU instrument block.

The operator had fulfilled the intent of this procedure and took appropriate actions t after noticing a potentially contaminated spill had occurred, j

'

O2 Operational Status of Facilities and Equipment 02.1 Enaineered Safety Feature System Walkdowns (71707)

{

The inspectors used Insocction Precedure 71707 to walkdown sections of the folinwing engineered safety feature (ESF) systems or subsystems:

o Condensate Storage Tanks . Units 2 and 3 e High Pressure Coolant injeution - Unit 3 e Residual Heat Removal Unit 3 Equipment operability and material condition were acceptable in all cases. Minor equipment discrephncies were brought to PECO's attention and corrective actions ;

were initiated.

02.2 Unit 3 Refuelina Activities

'

a. Inspection Scone '

The inspoctors observed the removal and transfer of six fuel elerrents from the reactor core to the spent fuel pool during two portions of the multi-part core shuffle. '

.

In addition, the removal of an LPRM remnval and the installation of a control rod blade was also observed. ,

b, Observations and Findinas ,

The refueling evolution was handled by PECO's Nuclear Maintenance Department

. (NMD); operations involvement in this activity L limited to the RO in the control room who maintains communication with the refueling crew ano documents each fuel movement in reactor engineering procedure RE-C 40 CCTAS. The inspector noted that there were a number of independent checks on the element position (i.e.

'

the fuel handler, the limited SRO, a GE representative and indirectly, the RO in the control roorn) and that personnel worked short (two hour) shifts to ensure peak human performance, c. Conclusions The inspectors concluded that refueling activities were conducted in a safe manner *

with very good independent verification of fuel element shuffles. *

,

t -

, . ,

.

i

.

02.3 Outaac Overtime Useae and Anorovals a. Insocction Scope The inspectors reviewed PECO's implementation of TS 5.2.2.e governing the control of overtime of t. nit staff who perform safety related functions. These controls are implemented by Administrative Procedure A C 401, Rev.1, and are intended to ensure that personnel do not perform safety-related ectivities in a fatigued condition.

b. Observations and Flndinus The inspectors noted that most of the overtime in excess of GL 8212 guidelines which was approved was for limited duration (i.e. two days to one week) and only limited amounts of overtime involved operators. Personnelinvolved with the ECCS suction strainer modification had the most approvals as expected t,1ven the schedule delays incurred on this project during installation.

While overtime approvals were generally limited, justified and well controlled, the inspectors were concerned that some personnel were given blanket approvals for overtime work for up to three weeks with no hourly limit specified. As a result, the inspectors found (through a review of time records) that one engineering project manager (PM) involved in the safety-related ECCS suction strainer mod worked an average of nearly 90 hours0.00104 days <br />0.025 hours <br />1.488095e-4 weeks <br />3.4245e-5 months <br /> a week over a three week period. Another PM on this same project worked nearly 23 consecutive hours in the middle of an 88 hour0.00102 days <br />0.0244 hours <br />1.455026e-4 weeks <br />3.3484e-5 months <br /> week.

The inspector was concerned that these individuals must have worked on safety related project 0 in a fatigued condition given their schedules and considered such blanket approvals a breach in the intent of A C 40.1. The inspector raised this concern with blanket overtime approvals and the absence of a specified hourly limit on the working hours deviation limitation form with senior plant manwement. At the close of this inspection, management was reviewing this issue to determine the circumstances involved and the corrective actions merited in this matter.

c. Conclusions Overtime approvals were generally limited, justified and well controlled; however, the practice of permitting blanket approvals for overtime work on safety related activities for multiple weeks with no hourly limit specified was considered a breach in the intent of PECO's overtime authorization process. The inspector will followup on the corrective action:: taken in this matter. (IFl 50 277/278/97 07-01)

O2.4 Unit 2/3 Soent Fuel Pool Operations a. Insnection Scong The inspectors reviewed PECO's controls over unique lineups and operations of the spent 8uel pool cooling systems at Units 2 & 3.

.

.

b. Qblervations and Findinag Early in the Unit 3 refueling outage, the inspectors noted that the Unit 2 spent fuel pool cooling was completd I secured to permit diversion of a third demineralizer to the Unit 3 spent fuel pool cleanup system for reactor cavity water cleaning enhancement. This evolution was permitted by proceduru and indirectly discussed in the UFSAR, but at the time the evolution was conducted, no procedurallimits existed on how long it should occur. Operators also were not knowledgeable of the procedutallimits on SFP heatup when cooling for Unit 2 was isolated. Following inspector questioning, Operations later imposed a 120* F administrative limit on the heat up on the Unit 2 spent fuel pool.

Subsequent inspector review of System Operating Procedure (SO) 19.2.A 2, Fuel Pool Cooling Shutdown revealed that a limit of 130'F degreas was specified -the procedure at which time the system must be restored to service. An action limit of 130'Fis specified in the RO rounds and 150*Fis specified in the UFSAR as a design limit. They noted that ECRs 97 02448 & -02934 are scheduled to be implemented in the near future that will install two valves in the SFP cleanup system such that the third domineralizer can be shared between each unit without isolating SFP cooling to the other unit. Also, abnormal operating procedure 30.2 3 governing the removel of the Unit 3 SW system from service, an evolution performed later in the outage for maintenance, permitted cn uppar limit of 140* F for the fuel pool at which time SW to the spent fuel pool cooling sy.cem must be restored to prevent exceeding the design lirnit of 150*F.

c. Conclusiong Overall, the inspectors found that there are adequate controls to ensure that SFP temperature remains below its design limit of 160'F, although operators were not knowledgeable of the specific procedurallimits when spent fuel pool cooling for Unit 2 was isolated.

02.5 2D-2 Station Batterv Charaer Dearaded Condition a. jnspection Sgpoe (71707)

The inspector reviewed equipment status control for station battery chargers, as a follow up action to the Unit 2 scram, b. Observations and Findinas The inspector found an instance of poor equipment status control for the standby safety related 2D 2 station battery charger. This battery charger had been in a degraded, inoperable condition since April 1997, but was not being tracked by operations personnel.

. . - - - - . - . . - - - - . . _ _ - - - - -

,

i

'

.

l

• /

• On November 13, the inspector observed a deficiency tag on the 2D 2 battery charger (in standby) that stated *do not place in service without  ;

contacting the system manager. No action request number was listed on  ;

the tag, s

• The inspector questioned control room personnel, who were unaware of any degraded condition on the battery charger. The battery charger was not listed on any equipment deficiency lists or turnover Information sheets.

• After further research, control room perconnel referred to an action request for the battery charger and found that it had been declared inoperable. -

I Operators considered this to be an operationally significant issue and added the battery charger to the equipment deficiency list.

• Another operations crew reviewed this equipment problem and determined i that the condition should be logged as a Potentla! Tech Spec Action (PTSA).

,

This provides a tracking mechanism which would indicate that if the in- ,

service charger should fall, for example, a Tech Spec Action statement would be entered. Further, the crew considered the degraded condition to ,

require expedited r.epair efforts during the current work week. Previously, the battery charger had been scheduled for repair in January 1998.

After discussions with engineering and operations personnel, the inspector learned that the full extent of the degraded condition was not known initially when the action request was drafted. Further troubleshooting revealed a more significant problem. This information, though, was either not communicated to operations personnel, or was not loge,4d or tracked by the operations crew. The equipment status tag informatior' G.d not meet Operations' expectation, because it provided no information as to the degraded condition or to the action request that applied.

Operations and engineering personnel indicated that weaknesses in coordination and follow up review among maintenance, operations, and engineering likely contributed to this issue.

The inspector considered this issue to have minimal safety impact since the 2D 2 station battery charger was in a standby status. However, the inspector was concerned that operators were not tracking this as a degraded, Inoperable

'

component. This was important, given that a degraded condition on a station ,

. battery charger forced a battery charger swapover that led to a Unit 2 scram during the previous week.

c. Conclusions The NRC Identified an instance of poor equipment status control for the ,rety  ;

related 20 2 station battery charger, which was in a standby status, u nis battery charger had been in a degraded, inoperable condition since April 1997, but was not.

being tracked by operations personnel.

>

i

!

. . . ~ , .~.v - . . , , . . - , _ . _

_ . . - . . _. -. , m __.

- . . - . -- . . _ = _. . - -

!

. ,

i 8 ,

i 03 Operations Procedures and Documentation i

03.1 Residual Heat Removal System Status Control /Miscositioninas (Unit 3) i i

a. Insoection Scooe (71707)

The inspectors reviewed two mispositioning events and overall status keeping for the Unit 3 residual heat removal (RHR) system during the 3R11 outage, b. Observations and Findinas During the Unit 3 outage, PECO identified two mispositioning events associated ,

'

with the RHR system:

-.

e in one instance, control room operators inadvertently closed a shutdown cooling system isolation valve, MO 31017, when they intended to operate ,

a different valve on the control panel. Operators recognized the error and ;

immediately re opened the valve PECO considered the cause of this event to be poor self checking. ,

o During surveillance testing, operators found 4 - 9HR differential pressure '

switch isolated from the system. PECO initiated a PEP report and was investigating the cause and corrective actions for this event.

The inspectors considered these mispositioning events to be minor issues. Overall control of the RHR/ shutdown cooling systems during the outage was very good.

RHR loop operability and availability status was maintained on a status board in the control room. Appropriate log entries were made when operators temporarily removed the shutdown cooling system from service, as allowed by procedure, c. Conclusions Two minor RHR system mispositioning events occurred during the Unit 3 outage. '

However, overall RHR/ shutdown cooling system status control was very good.

03.2 Unit 2 Cooldown Monitorina Followina the November 9th Reactor Scram a. Inspection Scope (71707)

After an automatic reactor scram of Unit 2 on November 9,1997, PECO reduced reactor temperature and pressure and maintained the unit in hot stand by. The inspectors reviewed the record of temperature changes to verify PECO did not exceed the TS cooldown or heat up rates.

!

l l

l

-. - - - - - _ . .

.-

,

.

i b. Observations and Findinos:

Following a scram on Unit 2, PECO commenced monitoring the cooldown rate of the reactor vessel using ST 0-0BO-500-2," Recording and Monitoring Reactor Vessel Temperatures and Pressure," to ensure the cooldown rate did not exceed the Technical Specification limit of 100 'F/hr. The procedure appropriately notes that validating the recirculation loop temperature to determine reactor vessel heat up or cooldown is dependent on the recirculation pumps running. When a recirculation pump is running, the loop temperature is circled and considered valid.

An independent review of the procedure and specific temperature values by the NRC indicated that PECO stayed well within the maximum heat up or cooldown rate during and following the transient and upon meeting the criteria exited the procedure. This was consistent with inspector observations of the cooldown on l

'

Unit 3 on October 4 5 at the start of the refueling outage. The data taken during the plant cooldown af ter the scram indicated vessel metal temperature changes greater in magnitude or in different directions (heatup vs cooldown), during some periods, than the worst case recirculation / steam dome temperature changes. The 4 use of the recirculation or steam saturation temperature vs reactor vessel metal tempeeature in determining the rate of temperature change (heatup/cooldown rate),

although an unresolved item, seemed reasonable. Currently the vessel metal temperature is used to comply with Technical Specifications Figure 3.4.9.2,

" Temperature / Pressure Limits for Non-Nuclear Heatup and Cooldown Following a Shutdown" for brittle fracture discontinuity assessments only. Also, although the '

vessel drain pipe temperature is recorded, it is not considered during the cooldown or brittle fracture assessments.

in accordance with A C-079, this ST is considered a Level I procedure requiring continuous use, and individual step documentation shall be completed prior to proceeding to the next step in the procedure. The administrative errors identified by the inspector on November 10, consisted of not performing any of the prerequisites even af ter several reviews by PECO shift management. Shift management discussed the situation of this ST with the inspector and completed the required documentation on November 11, c. Conclusions Operations perscnnel monitored the cooldown rate as required by the procedure during and af ter the reactor scram translent and maintained the reactor coolant cooldown rate well within the requirements of the TSs. Some administrative errors were nomd, but they did not affect the temperature readings and resulted in no l significant impact on the safe operation of the reactor or safety systems. This was considered poor performance and represented another example of failing to follow procedures. This procedure violation is one of three examples cited in this report.

(VIO 50 277(278)/97 07 02, Example 1). The issue regarding whether the l

.

.

appropriate and/or most conservative vesselivessel drain pipe temperatures were used, such that TS pressure / temperature limits were not violated, remains an unresolved item pending additionalinspector review. (URI 50 277(278)/97 07-03)

04 Operator Knowledge and Perf armance 04.1 Unit 2 Scam a. Insoection Scone (71707)

The inspector reviewed events related to the Unit 2 scram on November 9,1997.

b. Observations and Findjngs On November 9, Unit 2 experienced a main turbine trip and reactor scram from 100% power as a result of operator error associated with swapping a station battery charger. The plant responded as designed, according to the transient description in the Updated Final Safety Analysis Report (UFSAR). Operators entered appropriate tr;p procedures and took actions for minor anomalies following the scram. One notable occurrence following the scram was the failure of the 'A'

reactor food pump turbine (RFPT) to trip by remote push-button. This issue is discussed in detailin section M2.1 of this report. The post scram review of this event is discussed in section 04.2.

The problems with swapping the battery charger caused a momentary drop in the associated DC bus voltage. This led to the actuation of main generator protective relays, which fonctioned as designed, and the trip of the main generator.

The events related to the swap of the t.attery charger were as follows:

e An equipment operator responded to a fan failure alarm on the in-service battery charger. The fans appeared to be operating normally, but the alarm did not reset, e Control room operators directed the equipment operator to place the standby battery charger in service per system operating procedure SO 57B.1.A 2.

The equipment operator had the procedure in hand to perform the evolution.

e To plu:e the standby charger in service, the procedure directs the operator to shut the AC supply switch and then shut the DC output switch after the charger DC voltage reaches 125 VDC. The procedure also contains a caution statement that directs the operator to wait 15 - 20 seconds before closing the DC output switch to prevent blowing fuses in the charger.

e The equipment operator f ailed to verify that DC voltage was at least 125 VDC prior to shutting the DC output switch and failed to heed the caution satement.

___ _ . __ _ - - _ _ _ . - .. _ __ _ _ __.. _ _

.., _

'

o

!

l

e When the operator shut the DC output switch, the charger fuses blew, and DC bus voltoge dropped momentarily and then recovered, causing the actuation of generator protective relays and ultimately a turbine trip and reisctor scram.

The inspector noted that the equipment operator was newly qualified and had not performed this task before. Shif t supervision did not recognize the potential risk of the evolution and did not walk through the procedure with the individual before it was accomplished nor provide supervisory /ersight.

The equipment operator had the syste- erating procedure in hand while performing the task. However, the ator did not follow the procedure step by- -

step as required by plant administrativ orocedures for this type of procedure.

Since the operator was recently qualifl6 the inspector questioned other recently qualified equipment operators on their tiaining regarding station requirements for ,

procedure usage. The inspector found the operators to be knowledgeable of these requirements.

Technical Specifications 5.4.1 requires that written procedures be established, implemented, and maintained covering activities as recommended in Regulatory Guide 1.33, Appendix A, November 1972. These activities include startup, shutdown, and changing modes of operation for the DC power systems. Contrary to the above, the licensee failed to properly implement SO 570.1.A 2,"125/250 Volt Station Battery Charger Startup," resulting in a reactor scram (VIO 50-277(278)/97-07 02- Example 2).

c. Conclusions Failure te follow procedures by an equipment operator swapping station battery _

chargers caused a Unit 2 main turbine trip and reactor scram. Although this operator was recently quellfled, shift supervision did not take such prudent actions-as discussing the procedure with the operator or providing direct supervisory oversight prior to and during the performance of the test.

04.2 Licensee Post Scram Review (Unit 21 a. Insoection Scope (71707)

The inspector observed PECO's post sr ram review activities on November 9-10, 1997.

b. Observations and Findinos Following the scram on November 9, operations personnelinitiated a review of the scram as required by plant procedures and guidelines. Procedure GP-18, " Scram Review Procedure," contains instructions and a checklist to help ensure that operators fully analyze a scrarn and verify inat the plant is safe for restart. The plant Operations Manual also contains guidance on the roles and responsibilities of L

, , ~~ -r ,- , , ,- --

. . . _ . - _

,

.

operators following a transient or scram. For example, the shift technical advisor (STA)is expected to compare plant parameters with predicted parameters in the Updated Final Safety Analysis Report to determine if the plant is responding as predicted.

The inspector observed that the operations personnel on-shift during the scram conducted a thorough critique of the scram event. Operations also recorded date and answered the questions as specified in the GP 18 check off list. However, the STA did not compare plant response with that predicted in the UFSAR, as described in Operations Manual guidance.

The inspector found this to be a minor weakness in operators' awareness of the need to censult licensing basis and UFSAR information when some off normal conditions or degraded equipment issues arise. PECO self identified a similar issue during this Ir spe 'tlon period in which operations staff was slow to recognize that operating a reacts.' feed pump turbine with both high vibration trips defeated was inconsistt * with ti e UFSAR. The Performance Enhancement Program (PEP) report for this isuue tited s need to heighten station awareness of the need to consider the licensing basis unen making operability determinations, c. fonclusions Overell, post scram review actions following the November 9 scram were good.

However, the STA did not compare plant response with the UFSAR, as described in operations guidance. This, combined with a similar self identified issue, revealed a minor weakness in operators' awareness of the need to refer to licensing basis and UFSAR information when certain off normal or degraded equipment conditions arise.

04.3 3D Hiah Pressure Serving Water Pumo Motor Hiah Oil Level a. Insoection Scone (71707)

The inspector identified an out of specification high oil level on the 3D high pressure service water (HPSW) pump motor upper bearing sight glass, b. Observations and Findinas On October 9, during a routine plant tour, the inspector observed that the 3D HPSW pump motor upper bearing oil sight glass was high out of specification. The 3D HPSW pump was in service, providing cooling for the operating loop of residual heat removal / shutdown cooling. Two of the three other HPSW pumps were unavailable due to outage activities.

l

_ _ _ - - __ _ _ _ _ _ __ _ _ _ _ _ _ . _ _ _

,

.

I 13 ,

The inspector brought the condition to the attention of operators, who promptly returned the oillevel to normal and checked bearing temperatures. Operators also directed that the oil be analyzed to verify that there was no water leakage through the oil cooler, which could have led to the high level condition. The inspector found these actions to be prompt and thorough.

Operations supervision determined that equipment operators should have identified the condition during rounds, and that this did not meet management expectations with respect to attention to detail. Operations management took appropriate corrective actions including discussing this event with equipment operators and reinforcing expectations with respect to attention to detall, c. Conclusions NRC identification of an out of specification high oillevel on the in-service 3D high ,

. pressure service water (HPSW) pump motor revealed a minor lapse in attention to-detail on the part of equipment operators.

07 Quality Assurance in Operations 07.1 Plant Ooerations Review Committee (PORC) Meetina a. Insoection Scone (40500)

The inspectors attended two Plant Operations Review Committee (PORC) meetings

!n October 1997 and one in November 1997.

b. Observations and Conclusions At the meetings, PORC reviewed the final results and recommendations of Class A Performance Enhancement Program (PEP) reports. The PORC members demonstrated a good safety perspective and maintained a good questioning attitude during the meetings, resulting in several additional PORC follow on or revision items.

08 Miscellaneous Operations issues 08.1 (Closed) Unresolved item 95 04-02: Internal secondary containment flooding review. IR 95 04 noted that the secondary containment transient response implementation plan (TRIP) was flawed with respect to local verification of internal flooding conditions. Specifically,if a design basis or less severe flood were to

.

occur and watertight doors between rooms were opened to verify flood levels, the flooding would migrate to another room. PECO review of this finding indicated that ,

additional guidance to the operators was warranted in Secondary Containment Control (SCC) Emergency Operating Procedure (EOP) T-103 cautioning them that breeching the integrity of a potentially flooded room could endanger personnel and plant equipment. It also provii 4 guidance on how to monitor room water levels in rooms with watertight doors (i.e. via Indirect means or via direct observations using

. . . - . - .- -. . .

!

l 0 I

doors which open into (versus out of) the room). Additional information was also provided in the bases for T 103 and was provided to the operators in training sessions in 1990. The inspectors confirmed the implementation of these procedure changes and reviewed RT M 045 980 2which verifles the water tight integrity of these doors. Based on these corrective actions, the inspector considers this item closed.

61. Maintenance and Survsillance M1 Conduct of Maintenance and Surveillance M1.1 lagdvertent Electrical Di', connection of the 3B Hiah Pressure Service Water (HPSW)

Instead of the 3B SW,fum a. insoection Scope (62707)

The inspector rer'1wed the events surrounding the Inadvertent electiical disconnection of the unblocked 3B HPSW pump instead of the blocked 3D SW pump cn September 22,1997.

b. Observations and Findinas PECO, using the serv'ces of a contractor, performed work in September and October 1997 to replace the cables for the three Unit 3 SW pumps. This required the blocking of each of the SW pumps, the disconnection of cabling on the pump motor and the transformers located immediately outside the building, and the removal, pulling and termination of replacement cabling. On September 22,1997, while a work crew was taking electrical readings on de terminated wiring which they thought was connected to the 3B SW pump, they noted readings that were not as expected. Subsequently, their foreman noted that the schemo numbers on the cabling leading to the pump did not match the scheme numbers on the transformer which they were testing. At that time, the foreman recognized that the pump his work crew was on was not the blocked, non safety-related 3B service water pump, but the unblocked 38 safety related HPSW pump. Upon identification of this error, al' work was halted; Operations declared the pump inoperable and blocked the pump untilit was reterminated and satisfactorily retested the next day No TS LCO was entered nor violated as a result of this error.

PECO root cause investigation into this event determined that the contract vork foreman mistook the 3B HPSW pump for the 3B SW pump from the initir' < oint at which he was assigned the job in July even though both pumps were clearly and correctly labeled. As a result, when walkdowns of the pump were conducted in July and September by the contract foreman with the scaffolding team and the work crew, respectively, the 3B HPSW pump was consistently identified by the foreman as the affected pump. At no tirne during these walkdowns was the work order package in hand for reference. Further, opportunities to identify this error were miss9d by the scaffolding crew and their planner who mistakenly also erected

.

.

scaffolding around the 3B HPSW pump in support of this job in spite of a conflict between the pump number and the work order as well as by the work crew who electrically determinated the 3B HPSW pump. In addition, Operations personnel also did not pick up on this error, principally because the clearance hung for the pump was done at the switchgear to the pump; the actual work site was not visited.

Upon identification of this event, immediate corrective actions were taken to educate site workers on this event and to reemphasize the importance of self-checking, attention to detail and questioning attitude. Additional corrective and disciplinary actions were taken for specific contract individual (s) directly involved in this event. Longer term comprehensive corrective actions were taken or ongoing during this inspection period, including additional, improved initial contractor training, development of a pre job check off sheet, evaluation of the clearance and tagging program for improvements and evaluation of the role of operations personnel in the control of plant activities. While some important corrective actions (i.e. changes to the clearance process) remain to be decided, the inspectors considered these corrective actions to be comps ms. lve.

TS 5.4.1 requires that procedures shall be established, implemented and maintained covering procedures recommended in Regulatory Guide 1.33, Appendix A; RG 1.33 requires procedures for performing maintenance and for procedural adherence.

PECO administrative controls procedure A C 26 for processing work orders requires the work group supervisor to " complete assigned tasks in accordance with the work plan or modification package and ensures all work stated on the A/R or W/O has been completed." Administrative controls pmcedure A C 79 also provides expectations regarding procedure adherence and use. With regard to the September 22nd event, the !nspectors noted that the f ailure of multiple plant personnel to conduct plant walkdowns and perform work in this matter in accordance with the work order, in part, because the work order was not in-hand, resulted in the inoperability of a safety related HPSW pump and represented a violation of NRC requirements. (VIO 50 278/97 07 02 Example 3)

c. Conclusigna On September 22,1997, a safety related HPSW pump was electrically uncoupled without being isolated because contractor personnel thought they were working on a similarly numbered non-safety-related service water pump that was electrically isclated. This event posed a potentially serious industrial safety hazard and resulted in rendering an important piece of safety related equipment inoperable for over 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. The event highlighted weaknesses in procedural adherence, particularly the use of work package documentation at the job site, personnel self-checking, and a questioning attitude that led to multiple breaches in work process barriors. The failure of multiple personnel to conduct plant walkdewns and perform work in this matter in accordance with the work order, in part, because the work order was not in-hand, was a violation of NRC requirements.

_ _ _ _ - . _ _ -. _ _ _ _ _ _ _ _ . . _ ._

,

l

.

M1.2 hagarations for Refugina (Unit 31 s. Inspection Scope (62707)

The inspector observed maintenance activities on the refuel floor in preparation for refueling on Unit 3.

.  ;

b.- Observations and Findinas  ;

.The inspector observed several activities associated with reactor pressure vessel !

disassembly and preparations for refueling. Portions of the following work were -

observed:

o Reactor cavity shield plug removal e Mirror installation removal e Preparations for reactor pressure vessel head de tensioning e Main steam line plug installation The inspector noted that the evolutions were well-controlled and were conducted in accordance with maintenance procedure M-004 200," Reactor Pressure Vessel Disassembly.' Good supervisory and management oversight were also cbserved, c. Conclusions -

,

Maintenance activities associated with reactor pressure vessel disassembly were well controlled and conducted per procedure.

M1.3 Outaae Surveillance & Preventivs Maintenance Activities a. inspection Scone (61726)

The inspectors observed selected surveillance test activities performed on an outage (e.g., once per 24 month) frequency as well as outage preventive maintenance inspections, b. Qbservations and Conclusions During the Unit 3 outage, the inspectors observed selected survAance test activities that are performed during outage conditions. Portions of the following surveillance tests were observed:

• RT R-02F 900 3 Rectre Flow Monitoring for Jet Pump Riser Indica.lons .

e . ST R 003-460 3 CRD Scram insertion Timing e ST 0-052-100 3 Simultaneous Start of All Emergency Diesel Generators e ST-O 054 7513 E 13 4KV Bus Under voltage Relays and LOCA LOOP Functional Test

!

- ~ - -

- - . . . ._ _ -. . -_ _ _ . _ _ _ _ __ _

.  :

I i

17 j e ST 0 054 753 3 E 33 4KV Bus Uridervoltage Relays and LOCA LOOP Functional Test e ST 0 37D 375 2 " Diesel Driven Fire Pump Starting Batteries Weekly Check" e ST 0 020 3013 "HPCI Pump, Valve, Flow, and Unit Cooler Functional and in Service Test" e ST 0 052 204 2 "E4 Diesel Generator slow start and full load test" e SP.2091 " Differential Pressure Test of Unit 3 HPCI Steam Supply Valve MO 3 23 014" Portions of M C 756-000 7, *HPCl Turbine Major inspection" were also observed.

The inspectors found these activities to be well controlled and coe :cted in l accordance with procedures. Supervisory / management oversight was very good. l System managers resolved minor testing discrepancies in a prompt manner.

!

M2 Maintenance and Material Condition of Facilities and Egulpment M2.1 [ignctor Feedwater Pumo Hlah Reactor Water Level Turbine Trio Inocerability .

a. insoection Scooe: (62707)

Following the Unit 2 automatic scram on November 9, the inspectors reviewed actions taken after the "A" reactor feedwater pump turbine (RFPT) f ailed to trip ,

when the control room operator pushed the trip push button for RFPT normal shutdown, b. Observations and findinas During the actions following the Unit 2 reactor scram, the reactor operator pushed the trip button for the "A" reactor feedwater turbine and noted that the RFPT did not trip. An equipment operator attempted local manual trip which initially also failed. Mechanical agitation (i.e. tapped by hand) caused the trip mechanism to actuate. An investigation of the problem followed.

Maintenance removed the RFPT trip mechanism as part of an investigation of the i failure to trip problem. Trip mechanism work done in April 1997 (when a similar ;

problem occurred) caused this item to be considered a repr$t maintenance item.

PEP (10007584 was written and the vendor contacted. The vendor had no knowledge of similar failures elsewhere in the industry to date. PECO management i indicated that a historic maintenance activity in 1987 on the 2A RFPT, which called for the trip mechanism disassembly, may have contributed to this problem, t

.

.

in April 1997, while removing the 2A RFPT from service, the turbine f ailed to trip by the teniote push button a'id attempts to trip the turbine locally failed. When the stem of the hydrau'io trip dump valve was lightly tapped, the valve moved and the RFPT tripped. Maintenance cleaned, recssembled, and tested the RFPT trip mechanism. Based on the successful exercising and proving proper functioning of the trip mechanism, maintenance considered the root cause corrected and the RFPT returned to service.

The cause of the f ailure to trip !s currently considered to be binding with the tang that the spring retention washer ridas along upon actuation of a trip, which prevents the trip mechanism from making a full travel to trip the turbine. Maintenance personnel repeatedly reproduced the failure to trip with simulated inputs in the shop.

This condition over time most probably caused the washer to deform and flatten on the portion that rides sgainst the casing. The flattening of the washer increased the ,

area and subsequently increased the friction and resistance to movement of the trip mechanism. The resistance to movement became such that the mechanism did not move under normal tripping force. The manual trip rod when tested indicated 22 mils from straight which could possibly further increase the resistance to trip.

Analysis of the damaged parts at PECO's Valley Forge Laboratory indicated this failure was a time dependent defect, but that the mechanism w os likely inoperable for some time. The failure was believed to be unique to the 2A RFPT trip mechanism, but that can not be totally eliminated from possibility without inspection of the spring retainer and manual trip rod of the other RFPTs. The inspectors are still evaluating the possibilities of testing that PECO could have preformed to identify the failure earlier. The system manager recommendation is for the other RFPT trip mechanisms be inspected during the next outage (2R11)

currently scheduled for the Fall of 1998. This is based on the belief that the other RFPTs on Unit 2 (and Unit 3) have functioned as expected over time. PECO tentatively plans to inspect one or more of the Unit 3 RFPT trip mechanisms during a mid-cycle outage in 1998. All three Unis 3 RFPT trip mechanisms functioned as expected when last tested on November 30. The Unit 3 RFPT trip mechanisms also operated properly when cyt, led in October 1997 as part of the Unit 3 outage; the mechanisms were nct inspected or disassembled at that time as it is not a vendor recommended maintenance activity.

Part of the Post Maintenance Testing for the A RFPT trip mechanism required ths satisf actory tripping of the turbine from both the control room push button and the local manual trip 3 times; the mechanism functioned as expected. The Unit 2 B and C RPFT trip mechanisms operated satisfactory during the November 9th scram and startup. However, the inspectors were concerned that PECO did not internally examine the 2A RFPT trip mechanism to determine the root cause of the f ailure and its potential generic implications to the other five RFPTs until after the restart of Unit 2. While PECO did develop evidence that the problem was limited to the 2A RFPT, some of this informa:lon was not developed until after Unit 2 restart.

. . .

.

.. .. .

,

. .

.. .

.

.

E Since the failure mode of the 2A RFPT, as identified by maintenance would have prevwnted a trip of the 2A RFPT during a high reactor water level and with this type of failure, it is reasonable to assume that the condition existed for greater than the

-

Technical Specification Section 3.3.2.2. limit of 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />, a TS non-compliance axisted. Operaoility of the feedwater high water level trip instrumentation is required by TS 3.3.2.2: therefore this failure rendered a portion of this trip function inoperable in that the 2A RPFT would not have tripped automatically given a vahd iilgh water level trip signal. PECO p'ans to include tYs equipment problem with the 2A RFPT in the Licensee Event Report that oescribes the automatic reactor scram on Unit 2.

c. Cnaglusions s The fai!ure of the 2A RFPT trip system would have prevented the 2A RFPT from being remotely tripped in the event of a high ieactor water level signal. Moreover,

-

PECO did not determine the root cause of the failure before restarting Unit 2.

However, since no testing is performed on the mechanism during power operation, PECO had no way of knowing that the trip had failed prior to the actual failur1.

Mo";over, both of the other RFPT trip mechanisms and the main turbine trip meenanisms remained operable during this event, thus limiting the safety consequences of this failure. Pending evaluation of any testing possible while on line to verify and possibly Identify this type failure as well as information in the pending LER on the safety significance of this event, this item remains unresolved.

(URI 50-277/97-07 04)

M3 Maintenance Procedures aisd Documentation

. M3.1 Inadvertent Trio of the Unit 3 E-43 4 kV Bus Durina Relav Testina Activities L, (Closed) LER 50 277(2781/2 97-006 T -

a. Insoection Scoce (61723)

The inspector reviewed PECO's actions following a trip and lockout of the E-43 4kV bus and subsequent actuation of the E-4 emergoncy diesel generator (EDG). This

-

event occurred on September 23,1997, during instrumentation and controls (l&C)

testing activities, b. Observations and Findinas The trip of the E-43 bus occurred during the re-installation of an over current relay that had been calibrated as part of a testing procedure. While installing the relay o cover, l&C technicians cllowed the relay reset lever bar to come in contact with the relay internals, which caused a trip and lock out of the bus feeders. The E-4 EDG started, but did not load onto the bus, as designed. Operators restored power to the bus witNn aboJt 12 minutes. Also, operators reviewed the impact of the deenergizoo bus on safety related systems and determined that no loss of safety function had occurred.

- _ _ _ _ _ _ _ _ _

, , . . -. .- - _ - - .- -.

'o

PECO concluded that this event was the result of both personnel errors and an inadequate procedure. Further, PECO found that the relay design was also a-contributing factor. The l&C technicians incorrectly assumed that any work on an '

open feeder breaker would not adversely affect the condition of the associated,

-energized 4-kV bus. Thus, the technicians were not fully aware of the potential consequences of the evolution. The procedure, Sl3M 54-E43 XXC2," Calibration Check and Functional Test of E43 Bus and E434 Bus Meters and Overcurrent Relays," was poor in that it did not contain any precautions regarding the possibility'

of a bus trip while installing the relay.

The inspector observed that operator response to this event was very good.

Operators restored power to the E 43 bus in a prompt manner, made the appropriate NRC notification, and reviewed the impact of the event on technical specifications and safety related systems. The inspector found that PECO initiated -

adequate corrective actions to address the identified causes. This issue had ;

minimal safety impact, as evidenced by the licensee's safety impact determination and because sufficient power was available to safely shutdown the plant during the period E-43 was deenergized.

The inspector determined that PECO failed to ensure that procedure Sl3M 54 E43-XXC2 was adequate to properly control the testing evolution. This failure constitutes a violation of minor significance and is being treated as a Non-Cited Violation cor,Xstent with Section IV of the NRC Enforcement Policy (NCV 50-

.277(278)/97 07 05).

c. Conclusions An inadvertent trip of the E-43 bus and subsequent actuation of the E-4 EDG were caused by knowledge weaknesses on the part of I&C technicians and by an inadequate procedure. Operator response to this event was very good Corrective actions for this issue were appropriate. PECO's failure to ensure that the procedure was adequate to properly control the testing evolution constituted a Non Cited Violation.

M8 Miscellaneous Maintenance lasues M8.1- Inservice insoectbr3 a. -Ir,soection Scope (73753)

.

This inspection was conducted to determine whether the inservice inspection (ISI)

of Class 1,2, and 3 pressure retaining components at Peach Bottom Atomic Power Station (PBAPS) Unit 3, was being performed in accordance with Section XI of the American Society of Mechanical Engineers (ASME) Code.

.

21 b. Observations and FinfD91 Philadelphia Electric Company (PECO), PBAPS technical requirement manual (TRM)

prescribes the surveillance requirements for inservice inspection and testing of ASME Code Class 1. 2, and 3 components as required by 10 CFR 50.55a and ASME Code Section XI. PBAPS Unit 3 was committed to ASME Code Section XI, 1980 Edition through Winter 1981 Addenda, and to inspection program B of subsection IWA 2400, inspection Intervals. The inspection program requires that the 2nd inspection interval be 10 years following the 1st inspection interval. This inspection was conducted during the end of the second ISIinterval which was from November 19,1986 to November 4,1997. The ISI Program requirements for PBAPS Unit 3, were contalnud in Specification M-733, Revision 3, PBAPS 2 & 3 ISI Program. The procedure contained an overall description of the activities necessary to fulfill the ISI requirements as defined in ASME Code Section XI.

The inspector reviewed the 1997 Outage ISI schedule, dated October 1,1997. The schedule contained a listing of the Class 1,2 and 3 ccmponents rcflecting the appropriate NDE method to be accomplished. The inspector selected some ASME Class 1,2 and 3 components using the Final Safety Analysis Report (FSAR) at:.1 verified that those components were included in the ISI schedule. A hydrostatic test was not planned for the end of the outage because PECO had sought and received approval from the NRC to conduct an alternate test. The NRC approved PECO's request (Relief Request 22) for relief from the Code requirement of a hydrostatic test of the Reactor Pressure Vessel and Class 1 piping durir.g the 10-year interval (Table IWB 2500-1, item No. B15.11) via a safety evaluation transmitted in letter, dated July 23,1997. Instead of a hydrostatic test, a system leakage pressure test was performed.

Review of Procedures (73052)

The inspector reviewed the following licensee procedures to ascertain that they were in compliance with technical specification, ASME Code, and FSAR commitments:

e Administrative Procedure A-C-080, ASME Section XI Programs, Revision 2, dated January 31,1996.

This procedure provides the administrative controls for the cot, duct of activities necessary to fulfill the requirements of ASME Section XI. It outlines the purpose, scope, responsibilities and authority, controls and oversight, and records and reports necessary to properly implement the program, o Maintenance Guideline MAG-CG 418, Oversight of Vendor NDE Activities, Revision 0, dated September 08,1997.

.

.

This procedure establishes the requirements and responsibilities for the oversight of non-destructive examination (NDE) performed fce PECO Nuclear by vendors.

The procedure also outlines the processes for the practice and review of all NDE techniques, NDE certification reviews, and witnessing of examinations. The procedure requires that NDE Oversight Reports be generated to document the oversight activities.

The procedures implemented ASME requirements and were up to date for all currently approved Code r&f requests. The inspector reviewed some of the oversight reports generated as required by procedure MAG-CG-418, and found that they reflected that the licensee was conducting good oversight of NDE activities.

Reactor Pressure Vessel Shell Welds Auamented Insoection The inspector reviewed PECO's processes to address NRC requirement for augmented inspection of reactor vessel welds.10 CFR 50.55a(g)(6)(ii)(A)(2)

requires all licensees to augment their reactor vessel examinations by implementing the examination requirements for Reactor Pressure Vessel (RPV) shell welds specifiod in item B1,10 of Examination Category B-A, " Pressure Retaining Welds in Reactor Vessel," in Table IW8 250v-1 of Subsection IWB of the 1969 Edition of Section XI, Division I of the ASME Boiler and Pressure Vessel Code, subject to ine conditions specified in 50.55a(g)(6)(ii)(A)(3)and (4). Additionally,10 CFR 50.55a(g)(6)(li)(A)(5) requires licensees that are unable to completely satisfy the augmented RPV shell weld examination requirement to submit information to NRC to support the determination, and propose an alternative to the examination requirements that would provide an acceptable level of quality and safety.

PECO submitted an alternate plan for the examination of PBAPS Unit 3 RPV via letter to NRC, dated January 30,1997. The proposed alternate plan included the use of the Genarol Electric (GE) GERIS-2OOO System for the remote-controlled, automated ultrasonic (UT) examination of the RPV. In letters to PECO, dated July 2,1997, and October 7,1997, the NRC approved the proposed altemate method. The inspector reviewed the processes employed to accomplish this effort.

The review included personnel interviews, records review, and observation of test locations and equipment setup at the refueling floor, data acquisition and data analysis stations. The inspector reviewed the vessel inside diameter (lD) roll out drawing reflecting the weld arers planned to be inspected and another drawing reflecting those welds actually scanned already. All planned inspection were subsequently conducted before the end of the Unit 3 outage. Activities were well controlled and were conducted safely by qualified a.1d knowledgeable individuals.

The inspectors also observed in-vessel visual inspections (IVVI) being performed on elements of the jet pump hold down beam on two of the jet pumps. The inspections were performed by GE representatives who were experienced and knowledgeable of inservice inspection criteria and who were supported by an NDE Levelill qualified examiner. Discussions were conducted of the scope of the inspections, documentation and review of the inspecticns and the inspection findings to date; no performance concerns were noted. At the time of this review,

O.

.

no recordable indications had been identified during these inspections; however, several days later, several significant cracks were found in the recirculation piping thermal sleeve to riser pipe elbow. This cracking is discussed in depth in section E1.4 of this report.

Proorams Oversloht/indencndent Assessment NDE services branch developed an oversight activity plan to review and approve all vendor NDE procedures; personnel qualification; personnel performance; witness / independently re-examine some ISI examinations; and review some percentage of examination data. The inspector reviewed some of the NDE oversight reports that had been generated as required in procedure MAG-CG 418. The reports were properly completed and contained substantial information reflective of a good oversight.

The inspector reviewed the latest Nuclear Quality Assurance (NQA) assessment of the ISI program. The assessment (A0900893) covered the period between November 30,1995 and February 6,1996 at the station. The assessment coverad a good aspect of the ISI program, including the corrective actions and self assessment. It reflected excellent insights into programmatic issues. The assessment concluded that administrative controls governing the inservice inspection and non-destructive examination programs were adequately and effectively implemented. The assessment identified areas of good performance as well as areas that needed performance enhancement. There were no significant problems identified in the assessment. The inspector did not identify any issues or areas in the assessment that differed significantly from the inspector's findings.

c. Conclusions The ISI Program was being implemented with an approved plan and in accordance with ASME Code Section XI,1980 Edition through winter '81 Addenda. Code Cases used had been approved for use as part of the plan and reliefs from Cods requirements that were used had been approved by the NRC. There were good procedures in place to effectively control and implement the program. Program engineers showed good understanding and ownership of the ISI program. The personnel certifications and qualifications reviewed were maintained in order. The program oversights, both self and independent, nre good.

M8.2 Snubber Surveillance Prooram a. Inspection Scone (50090,61726)

The inspector reviewed the implementation of the snubber surveillance program to ascertain that it was being implemented in accordance with ASME Section XI requirements.

_ _ . _ _ _ _ _ _ - - - _ _ _ _ _ - _ _ _ _

,

l

.

b. Findinas and Observations

>

Technical Requirements Manual (TF M) 3.16, Snubbers, orescribes the tests and inspections necessary to assure th i snubbers are maintained operable. By relief request RR 10, PECO asked for relief from performing the examination of Class 1, 2, and 3 hydraulic and mechanical shock suppressor according to the Code requirements (Table IWF 25001). The proposed alternative was that the shock suppressors will be inspected and tested in accordance with plant technical specification requirements. The NRC approved this request via safety evaluation, dated April 8,1986. Later, however, the Technical Specifications at PBAPS were changed and the requirements for shock suppressor tasting were transferred to the -

Technical Requiremer'ts Manual (TRM). Based on this, the relief request needed further clarification since its basis (tests contained in technical specifications) was no longer valid. At the time of this inspection, PECO had not formally documented this clarification but stated that it would be made. The fact that the licensee did not have the proper clarification in place at the time of this outage was identified as a weakness.

Surveillance Test Procedure ST J-065 910-3, Revision 5, Hydraulic and Mechanical Snubber Functional Tests, dated April 03,1997, documents the functional testing of safety related hydraulic and mechanical snubbers to meet the requirements of the ISI program (Specification M 733) and in accordance with TRM 3.16, Snubbers.

Surveillance Test Procedure ST J-085 900 3, Revision 4, Hydraulic and Mechanical Seismic Snubber Inspection, prescribes the necessary periodic inspection activities.

The inspector reviewed these procedures and discussed their implementation with the licensee. The procedures were detailed and technically adequate. Pagram personnel showod good knowledge of program requirements. A review of the performance history of snubbers at PBAPS Unit 3 revealed no abnormal failure rates among the approximately 185 snubbers included in the program, c. Conclusions The licensee was implementing the snubber surveillance progrem in accordance with the technical requirement manual to satisfy the Code requirements. While the overa!I program was good, not initiating a timely clarification for a relief request when the basis for the request changed was considered a weakness. The licensee indicated that the necessary clarifications would be made to correct this weakness.

The licensee responded timely and well to industry information and implemented good inspection techniques to identify flaws on the jet pump risers.

. __ . _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ . _ _ _ _ _ . - _ _ _ _ _ _ _ _ _ _

. .- . _ . -- _ . - .. .

.

.

'

111. Enaineerina E1 Conduct of Engineering - Motor Operated Valve Program Review (Tl 2512/109)

Backaround On June 28,1989, the NRC issued Generic Letter (GL) 8910, " Safety.

Related Motor Opersted Valve Testing arid Surveillance," which requested licensees to establish a program to ensure that switch settings for safety-related motor operated valves (MOV)s were selected, set, and maintained

- properly. Seven supplements to the GL have been issued to provide additionalinformation and guidance on development of programs. NRO inspections at PBAPS have been conducted based on guidance contained in

, NRC Temporary instruction (Tli 2515/109," Inspection Requirements for Generic Letter 89-10."

On December 29,1995, PECO notified the NRC that the GL 89-10 program at PBAFS wrs complete. The NRC had previously conducted an initial programmatic (Part 1) inspection at PBAPS in November 1992, as documanted in inspection report (IR) 92-82. During July 1995, the NRC performed an implementation (Part 2)

inspection, as documented in IR 94-12. A (Part 3) inspection for the purpose of verifying that PECO had completed its commitments to develop and implement a =

safety relatad MOV program as described in GL 8910 and its supplements was performed in May 1996, (IR 96-03). During that inspection, the NRC determined the GL 89-10 MOV program could not be closed because of the following items:

• PECO had excluded 16 safety-related full flow test MOVs from the GL 8910 program based upon a Boiling Water Reactor Owners' Group (BWROG) position that was inconsistent with the GL-89-10 guidance on inclusion of valves with active safety functions.

• The valve friction factors for the core spray system injection valves that wore contained in valve group #21 were not clearly justified since a statistically bounding 0.52 valve f actor was not assumed for the non-dynamically tested valves.

Based upon the results of the inspection, in a June 3,1996 letter, the NRC requested PECO to supply in part, the fcl lowing information:

• The plan and schedule for inclusion and verification of capability for the 16 valves excluded from the GL 89-10 program.

• Commit to perform an additional test of a core spray injection valve to strengthen valve fac*.or assumptions for valve group #21.

._.

- __ _ . . ..

,

.

in an August 6,1996, letter to the NRC, PECO committed to perform an additional dynamic test of core spray injection valve MO 214-012Ato obtain additional data .

to support the valve f actors applied to group #21 during a unit 2 (efuel outage.

Capability assessments for the 16 full flow test valves, which were excluded from the GL 89-10 program were also provided. However, no commitment was made to include the valves in the GL 8910 program.

In a September 4,1997, letter, PECO modified its position concerning the full flow test valves and decided to include 12 of the 16 MOVs in the GL 89-10 program.

The four valves that would not be included would be administratively controlled such that when they are out of their normal standby position,' the afix'ed system / train would be declared inoperable according to plant Technical Specifications (TG). PECO also reported the instrumented dynamic test performed on core spray valve MO 214-012Adid not reveal useful data. Accordingly, PECO committed to perform a dynamic test of group #21 core spray system injection valve MO-3-14-012Bduring the October 1997 unit 3 refuel outaga.

The purpots of this fourth inspection was to examine the actions implemented at PBAPS to address the closure issues identified during the Part 3 inspection and determine if those actions were sufficient t., warrant " closure" of the NRC staff review of the GL 89-10 MOV program.

E1.1 Motor-Operated Valve Full Flow Test and Core Sora / Inlection Valves a. Insoection Scope The inspectors reviewed the test results and engineering evaluations for the following MOVs:

MO 2/3-13-030 RCIC Pump Discharge Test Valves MO 2/3-14-026A Core Spray Loop "A" Isolation Valves MO-2/3-14-0268 Core Spray Loop "B" lsolation Valves

,

MO-2/3-23-021 HPCI Pump Discharge Test Valves MO-2/3 23 024 HPCI Pump Discharge Test Velves MO-2/3-23-031 HPCI Torus Return Block Valves MO-2/3-14-012A Core Spray Inboard Loop "A" Isolation Valves MO 2/3-14-012B Core Spray Inboard Loop "B" Isolation Valves The review consisted of examining data associated with: (1) valve factor, which correlates differential pressure to the stem thrust requirement; (2) stem friction

- coefficient, which affects the conversion of actuator output torque te valve-stem thrust; and (5) rate of loading or load sensitive behavior, which reflects the change

__( usually a loss) in deliverable stem thrust under dynamic conditions as compared with the available thrust measured under static conditions. Additionally, the inspectors reviewed specifications Nuclear Engineering (NE)-201 "NRC Generic Letter 89-10 MOV Program Plan end Description," and NE-119, " Motor Operated Valves Thrust / Torque Determination Methodology."

,

-

.. .- -- . .- . . -

,

.:

b, Observations and Findinas z General-NE-201 was the guldance document for the PBAPS MOV program. The document -

contained an overall description of the GL 89-10 program, and a list of actions implemented to address the recommendations contained in GL 8910. Additionally, NE 201 contairnd a series of position papers that described PECO's approach to address issues such as rate of loading, MOV thrust and torque calculations, and extrapolation of test results.

NE 119 consolidated the information contained in the NE -201 posit.on papers into -

one document that defined PECO's technical design methodology used to ensure the proper functioning of MOVs. Both documents appeared up-to-date and reflected the latest design assumptions for establishing MOV logic and switch settings. -

MOV Loalc and Switch Settinas The 12 full flow test valves placed into the GL 8910 program consisted of Walworth gate and globe valves. When establishing the initial MOV switch settings, valve factor assumptions of 1.10 for globe and 0.60 far gate valves were used. The design stem friction coefficient was 0.20, which encompassed the licensee's statistical study value of 0.189. For valves that were not dynamically tested,~a 16% bias value was applied for load sensitive behavior based on plant data. Dynamically tested MOVs used the measured load sensitive behavior value. -

Once the required thrust value was determined, the required thrust was appropriately increased by 5% to account for valve degradation. As outlined in inspection report 50 277/278 96-03, these assumptions were found to adequately bound the majority of the PBAPS test data and were, therefore, considered acceptable.

Standard industry equations were used for calculation of torque and thrust. When calculating the requirod opening thrust for gate valves, PECO did not include the thrust due to stem rejection. This thrust aids the MOV in the opening direction and added a small amount of conservatism to calculations depending on the stem size of the MOV and the system line pressure where the MOV is located, inspection report 50-277;278/96-03 originally documented a concern regarding the calculation of stem rejection loads during valve opening calculations, however, upon reexamination of the test evaluation methodology, the inspector concluded it was acceptatie.

- The maximum MOV thrust / torque limit was besed on the lesser value of degraded

- voltage motor capability, or the structural limit of the valve or actuator. This value

.was then reduced to account for torque switch repeatability and diagnostic equipraent uncertainties.

l:

e

.

.n . . . - -

=I

.. 1

.

.28- ,

,

RCIC System Valves The RCIC system valves consisted of 2 MOVs (MO 213-030 and MO 313-030). i These valves were 4 inch, 900#, Walworth globe valves with a safety function to ,

close. Although both valves were dynamically tested with diagnostic equipment, -

the data quality for valve Mor3-13 30 was questionable due to excessive valve i vibration during testing. Accordingly, PECO_ analytically _ demonstrated that MO 3- -l'

?13 30 would operate by using the PBAPS bounding valve input assumptions.-

The inspectors reviewed the test results for MO 213-030 and analytic assumptions -

for MO 313 030, and verified the test results_were properly _ interpreted and the ,

analysis process used appropriate design assumptions. The inspectors noted that. -

valves MO 2/3-13-030 had adequate capability with available valve factors of 1.47 -

Land 1.21, respectively. ,

HPCI System Valves

,

- The HPCI system valves consisted of two 900# 10" Walworth globe valves - ,

MO-2/3 23-021,two 8" 900# Walworth gate valves MO 2/3 23 024 and two 4"

_

900# Walworth gate valves MO 2/3-23 031. All six valves had a safety function to -

close.  ;

Bounding program data were used to analytically demonstrate that the four gate- -

'

r valves and globe valve MO 3 23-021 wou_id operate under design basis conditions.

The capability of MO 2 23 021 was verified through the performance of a dynamic

- test with diagnostic equipment,-which produced a valve factor of 1.08 and a load sensitive behavior value of 7% ,

The inspectors reviewed the methodology used to establish the switch settings for

'

the HPCI system valves and verified the correct input assumptions were used and

- test data was appropriately applied.' All the HPCI system valves had adequate ,

'

margins with available valve factors greater than 1.23.

Core Sorav Test Return Valves

- The core spray test return valves consist of four 10" 300# Walworth globe valves with a close safety function. Since none of the valves had undergone a dynamic-

,

test using diagnostic equ,pment, i PECO attempted to demonstrate analytically the b - valves had adequate design margins. However, the design analysis did not include -

a value for rate of loading.

Using the PBAPS MOV orogram design assumptions for_ valve factor, rate of

_

loading, stem friction' coe ficient, and valve degradation, the inspectors calculated thrust values for the valvesJ The inspectors determined, except for MO 2-14-026A,

'

l- which had minimal des!gn margin, all valves in the group had adequate capability, L - - - . (i.e., greater than 10% neargin). Valve MO-214 026A also had adequate, albeit a small (1_%) thrust margin when actual values were used for stem friction coefficient i

with'no allowance for valve degradation.

.

b

_

,

'

-

l- w-s- - , n-

-mv- v w -+w ** --nw m , +'v-s --- * v-,rms-' , , - e av -- - w + -

_ _

,

.

The lack of valve-specific test data or failure to use bounding design assumptions to establish cote spray return valve switch settings was considered a weakness since, on three occasions during the most recent operating cycle, core spray return valves MO 314-026A/Bfailed to stroke closed. To validate the current switch settings for this valve group, PECO dynamically tested with diagnostic equipment valves MO 3-14-026A/B by the end of this inspection.

Core Sorav Inlection Valves Core Spray injection valve group #21 consisted of four 12" 600# Walworth flex wedge gate valves. The valves have both open and close safety functions with design basis differential pressures of 49 and 300 psi, respectively. Although valves MO-214 012A/Bhad both received dynamic tests with diagnostics, the test results for valve MO-214-012Aweren't used because of excessive data ::pread, which prevented accurate interpretation of the test results.

As previously outlined in inspection report 50 277;278/96-03,the valve factors assigned to group #21 were considered to be inadequately justified since PECO did not use bounding values when establishing switch settings. Specifically, a O.45 valve f actor was applied to the non-dynamically tested valves, though 0.52 was the bounding number at the 95% confidence level for Walworth gate val"es.

To demonstrate the valves had adequate dasign margin with their present switch settings, PECO calculated available valve factors using bounding assumptions.

Valve MO 2-1412A had the lowest available margin with a 0.50 valve factor. The remaining valves had calculated valve factors above 0.52. The inspectors independently calculated available valve factors for the core epray injection valves and obtained results that were consistent with the licensee's. Based upon the available valve factors the MOVs appeared to have adequate capability to operate under design conditions. To validate the current switch settings, PECO dynamically tested MO 314-012B by the end of this inspection period.

c. Conclusions Generally, the design assumptions used to establish MOV switch settinns were adequately supported by test data or engineering analysis. The exceptions were the assumptions used for the core spray injection and return valves, which were not adequately justified. To validate the switch settings for those valves, PECO dynamically tested core spray system valves MO-3-14-012 Band MO-3-14-026A/B by the close of this inspection oeriod. These valves tested satisfactorily. Based upon the activities completed to t' ate, the inspector concluded the GL 89-10 program ceuld be closed.

.

.

E1.2 MOV Marain Imorovement Prooram a. Inspection Scop _g The inspector reviewed the status of the MOV mart,5 improvement program to determine what actions are planned to improve MOV operating margin, b. Observatinns and Findinas NRC inspection report 50-277;278/96-03noted that the licensee planned to modify twenty MOVs to increase operating margin. Since the completion of that inspection, the margin improvement program was changed to address the motor performance and MOV program issues outlined ir. NRC Information Notices 96-48,

" Motor Operated Valve Performance Issues," and IN 97-07, " Problems identified During GL 89-10 MOV Inspections."

The revised margin improvement program is iritended to increase thrust capability of more than thirty valves by greater than 10% through design reanalysis, hardware modifications and changes to switch settings. The inspector reviewed the program and noted the modifications appeared to address the itsues outlined in NRC IN's 96-48 and 97-07. Although a start date for the program had not been established as of September 1997, the inspector considured the upgrade effort to be necessary since twelve valves currently show less than 5% design margin. These valves include several "high risk" MOVs including the 24" recirculation loop isolation valves MO 2/310 053A and the 6" unit 3 RCIC injection valve MO-3-13 021, c. Conclusions PBAPS has modified its margin improvement program based upon industry information. The proposed program is a good initiative since several MOVs have less than 5% design margin.

E1.3 Emeraency Core Coolina System (ECCS) Suction Strainer Modification a. Insoection Scone The inspectors reviewed key elements of the installation of new, large capacity passive ECCS saction strainers in the torus at Unit 3 in accordance with NRC Bulletin 96-03.

b. Observations and Findinas PECO installed large capacity passive ECCS suction strainers for all eight of the RHR and Core Spray pumps under modification P-350 during the Unit 3 refueling outage.

. Due to the difficulty in draining and decontaminating the torus as well as the

y(

w

. - -- - . ~-

-

- - . - - - -. . _ - - - - - - - . - - - . - . . _ -

L. ,

-

-

_

,

I

-

131 ,

resulting loss of.a suction source for the core spray and.RHR pumps during the -

outage, PECO elected to install this modification underwater.- In order to perform

this work, PECO requested and was granted NRC authorization to perform required-underwater welding per the provisions of ASME Code Case N 5161, " Underwater ,

.- Weldingi Section XI, Division 1," on October 3,1997. '

'

,

.The installation of the suction strainers involved the welding of support pieces to l

the torus ring girders, the alignment and bolting of suction strainer modules and the.

!

installation of piplng %n the modules to the existing piping penetrations through _

_

- the torus. The inspectors examined selected strainer modules in the storage area as- -

well as during rigging operations in the torus. They observed the preparation of the torus surface for welding as well as the inspect;on of a completed weld by an NDE ,

- L Level lll and the ANil. The inspectors also reviewed the welding procedure and the qualification records of the divers who performed welding and found them ,

,

acceptable and in accordance with ASME Code Case N 516-1. They also evaluated the radiological and industrial safety provisions for the divers and the workers in the

,

torus on three separate occasions during the outage. Finally, the inspectors reviewed selected modification documentation use following the completion of the' ,

modification.

c. Conclusions Based on the review of key aspects of this modification, PECO installed the ECCS

'

suction strainers in accordance with modification P-350.- Welding was performed by qualified individuals in accordance with ASME Code Case N 516-1. Schedule problems noted early in the outage with the installation of 'the modification were - .

overcome as the outage progressed by the~use of additional management and diver-resources. However, as noted in Section R1,1 of this report, this resulted in a ,

_

'

significant increase in the radiation exposure incurred over the level estimated prior to the outage.

,

E1.4 = Unit 3 Jet Pumo Riser Elbow Weld Crackino l

,

a.- Insoection Scone (37551)

The inspectors ieviewed PECO's activities to characterize, evaluate and disposition ,

.on'an interim basis cracking identified on three of the ten recirculation system riser elbow welds during in-ves_sel visual inspection (IVVI) during the Unit 3 refueling outage. .-This review included multiple discussions with NRR and PECO regarding _

ifuture repair' options, the restart and near term operations with this cracking and the

_

operating strategy developed to limit the growth of this cracking.

b. Observations and Findinas During the IVVI performed <iuring the Unit 3 Refueling Outage (3R11) on the

^

recirculation inlet nozzle thermal sleeve weld to the elbow on the lower end of the

-

v

'

jet pump riser pipe, cracks wore found in the heat affected zone on the thermal ,

isleeve side of the weld. The cracks were found on the risers associated with jet

-

.

' ' .f~ +

, . - . - . - . - ~ . . . z-.- - . - , - - --. - - - . ~ - . - - . , . - . - -. .--

,3- . _

..

pumps 1 & 2,9 & 10 ani 13 & 14 and were approximately 10.8 inches,1.7 and 12.7 inches, respectively. of the 33.8 inch circumference of the thermal sleeve.

The examination method employed was an enhanced visual VT-1 type [CSVT-1 (0.001 inch. wire) standards! The !ength of this cracking was later confirmed via independent visual methods and by ultrasonic testing (UT). These findings were documented in NCR 97 02899.

The IVVis performed were the first conducted at Peach Bottom at this location; these inspections were being performed in response to the recent identification of this cracking at another BWR, The information was provided in the following documents: BWRVIP-28; BWRVIP letter, dated January 31 1997, inspection of Jet Pump Riser to Thormal Sleeve Welds: SIL 605, Revision 1, Jet Pump Riser Pipe Cracking; and NRC Information Notice IN 97-02, Cracks found in Jet Pump Riser Assembly Elbows at Boiling Water Reactors. The inspector noted that a draft Augmented Inspection Program (AUG 14) had already been drafted to include this type of inspection into the ISI Program (Specification M 733) indicative of good awareness and use of industry information.

The 10-inch jet pump riser elbows were original installation stainless steel s::hedule 30 pipe (0.28 inch wall) attached to stainless steel schedule 40, thermal sleeves.

The previous examination method in these areas was the visual VT-3 method which was not geared towards finding cracks in ti.'s area. Preliminary analysis of the

'

cracks was that they were intra Granular Stress Corrosion Cracking (IGSCC),

outside diameter (OD) initiated.

Following the identification of this cracking, PECO dispositioned NCR 97-02899 on.

an interim use-as-is basis which allowed plant restart from the refueling outage and continued operation for the near future provided operations were limited to the reactor coolant recirculation drive flow and time constraints evaluated by GE for PECO. In particular, the evrluation performed by GE regarding the allowable flaw size of these cracks used the methodology presented in BWR VesselInternals Project (BWRVIP) document #41, which was consistent with ASME Section XI, Appendix C requirements. The evaluation determined the maximum acceptable length of these cracks. The allowable flaw length was 17.9 inches, indicating that all three cracks that were identified were currently acceptable. Calculations were then performed assuming a conservative growth rate for IGSCC which induced the cracking as well as the susceptibility of the flaws to fatigue cracking. Based on the estimated growth rate of the cracks due to IGSCC, plant operation for the next two year cycle would be acceptable. However, when fatiguo cracking was added in, the two longest cracks were calculated to exceed the allowable flaw length well before the end of the next operating cycle assuming full power operations. Therefore, to mitigate the impact of flow induced vibration, recirculation drive flow was originally limited to 80% (corresponding to a power level of 93%) for a period not to exceed 6,000 hours0 days <br />0 hours <br />0 weeks <br />0 months <br /> at which time PECO would conduct a forced outage to repair the riser cracking. PECO subsequently decided to revise this operating strategy to permit operations at 91 % drive flow (corresponding to 100% power) for up to 800 hours0.00926 days <br />0.222 hours <br />0.00132 weeks <br />3.044e-4 months <br /> to permit the completion of power ascension testing and higher power operation during peak winter electric demand. However, this revised strategy limited

.

33 operations at 90% drive flow to 2,224 hours0.00259 days <br />0.0622 hours <br />3.703704e-4 weeks <br />8.5232e-5 months <br /> for a total of 3,024 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> (versus 6,000). This operating strategy, along with an accompanying 10 CFR 50.59 evaluation, was PORC approved and implemented prior ta restart from the refueling outage.

Following implementation of this revised operating strategy, the inspectors vorified that adequate procedural controls were in-place to ensure that operators maintained recirculation flow in the required operating band and that engineering collected computer data documenting recirculation flow versus time. However, the inspectors noted that a procedure governing the formal tracking of recirculation flow versus time was not approved until three weeks after restart; while this was technically adequate given the time available, this time lag did not appear commensurate with such a significant change in plant operating practice. NRR, with the assistance of the Office of Research and their contractor, is currently reviewing the thermal sleeve tracking indications and supporting documentation.

Based on the previous and revised operating strategy, PECO plans to conduct a mid-cycle outage in the first half of 1998 to effect a permanent repair of the riser weld cracking absent additional revisions to the operating strategy and/or crack growth analysis that would provide for a longer operating period.

c. Conclusions The identification of cracking on three of the ten recirculation riser pipe elbow welds posed a significant challenge to PECO's engineering organization late in the Unit 3 refueling outage. The technical support provided by Engiaeering in this matter was considered very good, particularly given the lack of significant industry experience a with similar cracking. However, documentation of some supporting activities lagged, in part, due to the compressed time frame for their resolution. The inspectors will continue to follow the implementation of and adherence to this revised operating strategy as well as the repair methods chosen, (IFl 50 278/97-07-06)

E1.5 Roolacement of Deficient Hydraulic Control Unit (HCU) Scram Solenoid Pilot Valve (SSPV) Dianhraams a. Insoection Scone The inspectors confirmed the replacement of 54 HCU SSPVs with Buna diaphragms that have been determined by the BWR Owner's Group to be susceptible to hardening and cracking.

b. Observations and Findinas Following operational problems noted in September 1997 at Limerick with HCUs containing SSPVs with Buna diaphragms that are known to be susceptible to hardening and cracking, engineering evaluated the number of SSPVs at Peach Bottom with these diaphragms. Only 54 cuch diaphragms remained on Unit 3, of

. - _ _ _ -

. . - -. _ . - - .- . - - - . . . - .

,

t

. -

which eight were originally scoped into the outage for replacement; all such-diaphragms had been replaced on Unit 2. While engineering had planned to replace the remaining 46 diaphragms on-line by January 1998 prior to the end of their calculated service life, senior PECO management elected to scope these replacements into the Unit 3 refueling outage. The inspectors confirmed the replacement of these SSPVs with the system manager for the HCUs and via a sampling review of the work orders for the diaphragms changeouts.-

c. Conclusions PECO senior management demonstrated a good safety perspective and acted conservatively in changing out SSPV diaphragms, known to be susceptible to hardening, on a schedule more aggressive than planned in September 1997.

E2 Engineering Support of Facilities and Equipment E2.1 s;mp.taencv Diesel Generator Lube Oil Pioina - Potential 10 CFR 21 lssue_

a.. Lajip.pction Scoce (37551)

The inspectors reviewed licensee actions following the identification of cracked welds on emergency diesel genuator (EDG) lube oil piping at other nuclear power stations.

b. Observations and 'indinas in September 1997, Coltec Industries - Fairbanks Morse Engine Division submitted a potential 10 CFR 21 letter to the NRC regarding failed - elds on EDG lube oil piping at Mil! stone Unit 2. This letter listed Peach Bottom as being affected by a potential quality issue with associated piping welds. The affected welds were performed during original construction.

PECO engineering determined that the Peach Bottom EDG lube oil system was better supported than that at Millstone Unit 2. Therefore, they concluded the potential for failure was less likely. PECO engineering intends to review the Coltec Industries evaluation under 10 CFR 21, which is expected to be completed in December Based on the results of this evaluation, PECO will then decide on future actions. The inspectors identified no concerns with PECO's interim actions. This item remains open and will be reviewed upon PECO's determination of final corrective actions. (IFl 50 277(278)/97-07-07)

c. Conclusiong The inspectors identified no concerns with PECO engineering's interim actions for a potential 10 CFR 21 issue associated with EDG lube oil piping welds.

- . .. - -. . . - - - -

,

-,

3 5 --

- E2.2- 'E' Safety Relief Valve Talloioe Temoerature Increase (Unit 31 a. - Insoection Scone (37551)

The inspector reviewed licensee actions in response to an out-of specification high tailpipe temperature indication for the Unit 3 'E' Safety Relief Valve (SRV).

b. Observaticns and Findinas -

On November 9, operators noted that the 'E' SRV tailpipe temperature had exceeded its maximum temperature limit of 260*, as listed in plant procedures.

Operators initiated an action request to document the out of specification reading.

Operators concluded that the SRV remained operable.

>

The increased tailpipe temperature is potentially indicative of SRV leakage, which can lead to SRV blowdown and subsequent plant transient. The 'E' SRV is one of eleven SRVs that provide a relief function in the event of a reactor over pressure condition. The SFV is a 3-stage design manufactured by Target Rock Corporation.

Following inspector questioning on November 13, the licensee initiated plans to begin a monitering and action plan based on industry data and input from Limerick.

Engineering had not yet begun a plan, despite the four days of out of-specification readings and a continued upward trend.

The monitoring plan went into effect on Evember 17. The plan was comprehensive, discussed the applicable technical bases, and included the following elements:

e Log tallpipe temperature every four hours

,

o Notify engineering if temperature increases more than 2* in 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> e At 285*, commence discussions for plant shutdown and valve replacement Engineering determined that at 295*, there was a potential for blowdown of the SRV. Also, operators were advised not to operate the valve.

Trend data for the 'E' SRV tailpipe indicated a generally steady temperature increase-from about 242* on November 4, to 270* on November 14. All other SRVs oi.

Unit 3 remained below 250' during this period.

-Subsequent to the end of the inspection period, the "E" SRV tailpipe temperature continued to rise to approximately 279F. PECO took conservative action to shutdown Unit 3 and to replace the SRV. - Preliminary inspections of the removed SRV indicated that soms leakage had been occurring.

.

.

c. Conclusions Operations promptly identified and initiated an action request to address the out-of-specification tailpipe temperature on the Unit 3 'E' SRV. However, the inspectors considered that engineering was slow to develop a comprehensive monitoring plan for the degraded condition, despite a clear upward temperature trend. The final monitoring plan was very good and PECO fator took conservative actions to shutdown Unit 3 and replace the SRV after the end of this inspection period.

E2.3 Ememency Diesel Generator Ventilation Review (CLOSED) Unresolved item 97-02-06: Operability Testino of the Emeraenev Diesel GeneratoLyentilation Systems a. Insoection Scoce As stated in N3C Inspection Report 97 02, the EDGs have criteria to carry the design load for an hour during testing which gives reasonable assurance that the EDGs are operable. The operability of the EDG is dependent on the operability of the ventilation system; therefore, an operability verification of the ventilation system is required. The NRC opened unresolved item 97-02-06 pending review of PECO's actions on the verification and documentation of cssurance of the compartment ventilation systems to support EDG safety function capability, b. Findinas and Observations The EDGs have criteria to carry the design load for an hour during testing to provide reasonable assurance that the EDGs are operable. The heat input to the diesel compartment during a fully loaded run and the air consumption of the diesel make operation of the compartment ventilation necessary without exceeding the compartment air temperature alarm of 107 F. The actual maximum diesel compartment temperature for the EDG to maintain the design load is 122'F.

Therefore, although the v6ntilation systems had to be operating properly to allow the EDGs to perform the surveillance runs, PECO did not provide conclusive documentation for verifying proper operation of the ventilation system.

The ventilation system in the diesel generator building originally installed during construction had flow rates verified through testing with acceptable results. The existing ventilation system has not been reconfigured or modified. The fans are motor driven direct drive, have no belts to stretch or slip nor is reduced speed a characteristic failure mode. The licensee stated that the present EDG compartment ventilation system has not been reverified since the system was never reconfigured.

Test data from May 20,1973 indicates that the Emergency Diesel Generator Ventilation Systems had excess capacity during initia! startup testing as follows:

.

.

EDG ROOM Fan Design Flow Actual Flow % Deviation (CFM) (CFM) from Design Flow A OAV 64 42800 47118 + 10.1 OAV-91 40000 43885 + 9.7 1OTAL 82800 91003 + 19.8 B OAV-64 42800 47370 + 10.7 OAV-91 40000 47152 + 17.9 TOTAL 82800 91003 + 28.6 C OAV-64 42800 45948 + 7.4 OAV-91 40000 45969 + 14.9 TOTAL 82800 91917 + 22.3 D OAV-64 42800 43888 + 2.6 OAV 91 40000 45827 + 14.6 TOTAL 82800 89715 +17.1 The surveillance and routine tests for EDGs listed below have been revised to add specific.

sign-off steps for operation documenting the verification of the starting of the EDG ventilation fans as well as the starting and damper opening for the supplemental fans:

ST-0 052-201 (202,203,204) 2 ST O-052-211 (213) 2 ST O-052 212(214)-2 ST-O-052 311 (312,313,314) 2 RT O-052 2012 RT 0-052 202(203,204) 2 c. Conclusion Since PECO has shown proper test operation of the EDG, which required the ventilation system to be operable, combined with the additional capacity verified during startup testing without subsequent system moriification, it is reasonable to concluded that the EDG compartment ventilation system has been operable.

Although past documentation has been minimal, the recent revisions to testing procedures provides documentation of proper operation of the EDG ventilation system and this concern is considered closed.

.. .

e i

- 38 E2.4 Mnit 2 Hioh Pressure Coolant iniection (HPCI) System Turbine Leakaoe )

e, insoection Scope

' The inspectors followed PECO efforts to identify the source of unusual water i

leakage noted on the Unit 2 HPCI system turbine during a surveillance.

i b. Observations and Findinos On September 30,1997, while performing ST-023 301-2, a water leak was noticed on the bottom of the HPCI turbine; the exact location of the water leak could not be determined due to insulation covering the area. That leakage was determined not to impact operability of the pump based on its quantity; however, significant actions to identify the source of the water leak were not undertaken until'

October 3 when the pump was again operated to check for the source of the leak. ,

The inspector noted that while comprehensive troubleshooting proposals to search for the source of the leak were proposed on October 2 & 3, the actual troubleshooting activities that were performed on October 3 were more narrowly focused. Further, even though the source of the leakage could not be identified, additional troubleshooting of the source of the leak was limited to a check of the system supply drain system, based on the recommendation of PECO's turbine consultant, until the system was tested again on November 15. At that time, the source of the leak was identified since part of the HPCI turbine insulation was removed, permitting direct observation of the HPCI turbine casing. Since this water leakage was not pressure boundary leakage and was limited in amount, it was again assessed not to impact system operability.

Following the November 15 testing results, plant management made additional inquiries into system engineering's plans for repairing the leakage identified on the HPCI turbine. While engineering intended to continue monitor'ng the leakage for the foreseeable future, no plans were made to repair the leakage priur to the next major turbine overhaul scheduled for the year 2000. However, plant management later directed engineering to pursue options to correct the source of the leakage on a more aggressive time schedule and to develop a mathod of quantifying the leakage such that it did not mask future leakage from other, more critical sources, c. Conclusions While the initial HPCI troubleshootirg plan was limited in scope after early, more elaborate plans were developed, follow-on troubleshooting identified the source of the water leakage and plans are being developed to correct the source of the leakage. The inspectors did not consider the length of the delay in troubleshooting commensurate with the high safety importance of HPCI, but recent actions to more aggressively address the leakage problem were considered quite conservative.

,

.

-

. . - .- . - .- -- -. . . . _ _ . .

'

.

E8 Miscellaneous Engineering issues ,

- E8.i (Closed) Unresolved item 9412-02: Periodic Verification. (.4 their response to Generic Letter 96 05," Periodic Verificaden of Design-Basis Capability of Safety-Related Motor Operated Valves," dated March 14,1997, PECO committed to a periodic verification program that was consistent with the Joint Owners' Group (JOG) periodic verification guidelines. The JOG program established static test.ing intervals depending on MOV design margin and safety significance as defined by the Peach Bottom Probabilistic Risk Assessment (PRA). The number and selection of MOVs that will subsequently receive a dynamic test would be based upon a schedule determined by the JOG. The inspectors reviewed PECO's proposed periodic verification testing program; since the Office of Nuclear Reactor Regulation (NRR)is now tracking this issue as pa-t of the response to Generic Letter 96-05, this URIis being closed.

E8.2 (Ciased) Unresolved item 94-12-04: Pressure Locking and Thermal Binding (PLTB)

of Gate Valves. This item was opened to track the status of PECO's corrective actions for gate valves determined to be susceptible to pressure locking. In addition, this item documented ths fact that the NRC disagreed with PECO's position that valves closed only fc surveillance purposes such as valves in the reactor core isolation cooling (RCIC) and high pressure cootsot injection (HPCI)

systems need not be evaluated for susceptibility to PLTB. Since this item was oponed, the NRC issued Generic Letter 95-07, " Pressure Locking and Thermal Binding of Gate Valves," which requested licensees take actions to ensure those safety <e!ated power operated gate valves that are susceptible to pressure locking or thermal binding can perform their safety functions. PECO has since modified its program and evaluated valves closed for surveillance testing for susceptibility to PLTB. In lettors dated January 13 and July 25,1990, respectively, PECO described its revised PLTB program as part of its response to GL 95-07.- These responses are currently under review by the Office of Nuclear Reactor Regulation (NRR) who will document acceptance of the PLTB program by preparing a safety evaluation report.

Since NRR is now tracking the status of the Peach Bottom PLTB program, maintaining a separate redundant unresolved item for the same purpose is no longer necessary. Therefore, this item is closed.

E8.3 (Closed) Unresolved item 92-82-Q2: Direct Current (DC) Motor Capability Under Degraded Voltage Conditions. This item concerned: (1) justification of DC motor performance assumptions at less than 70% of rated terminal voltage, (2) use of generic motor performance curves without compensating for uncertainties attributed to manufacturing variances, and (3) verification that DC MOV stroke times under degraded voltage conditions remain within the current licensing basis.- By June 1996, PECO had adequately addressed itsms (1) and (2). They were closed in inspection report 50-277;278/96-03. However, item (3) was left open pending completion of a degraded voltage stroke-time calculation study for safety-related DC powered MOVs.

._

e

__ _ _ _ _ _ . _ _ _ _ __ _ _

.

J

in August 1996, PECO completed its review of DC MOV performance and concluded all 50 DC MOVs stroke times at PBAPS units 2 and 3 met system operability requirements under degraded voltage conditions. To check the results, the inspectors independently calculated MOV stroke times using a software program developed for the NRC by the Idaho National Engineering and Environmental Lab

(INFL) and compared the results to the times obtained by PECO. The inspectors noted both programs woduced similar stroke times. Based on these results, the inspector concluded the study was acceptable and this item can be considered closed.

E8.4 (Closed) Violation 50-277(278)/96-08-02- Failure to Meet TS Reouirements for APRM Instrument Surveillance /Onerability The inspector verified the corrective actions described in the licensee's response letter dated January 17,1997, to be reasonable and complete. No similar problems were identified.

( E8.5 (Closed) Unresolved item 50-277(2781/96-08-03- Controls Over the Core Thermal Power Calculation Proarams NRC Inspection Report 50-277(278)/96-08noted concerns related to: (1) Updates to the 3D Monicore computer database without formal engineering review, and (2) -

Whether the core power and flow log (CPFL) should have indicated a failed sensor.

Both of these issues were associated with the licensee's failure to meet technical specification iequirements for average power average power range monitor (APRM)

operability, as cited in violation 50-277(278)/96-08-02.

,

The inspector found that for issue (1), PECO determined that procedure RE 40,

"NSSS Software Databank/ Database Update" needed enhancements to ensure that reactor engineers obtained appropriate technical and management reviews prior making changes. These procedure changes were completed as part of the corrective actions for the violation mentioned above. The inspector concluded that weaknesses in RE-40 related to controls over the 3D Monicore ccmputer database contributed to the technical specification violation, ror bsue (2), th0 f ailed sensor information for the CPFL was not intended to indicate a f ailed sensor under the conditions in question. However, PECO made changes to the plant monitoring system computer, as well as procedural changes to preclude similar events involving reactor feed pump operation at low flow rates. As in issue (1), the inspector determined that administrative controls weaknesses contributed to the technical specification violation.

The inspector concluded that the two issues were contributing factors to previously cited violation 50-277(278)/96-08-02. Corrective actions for the violation addressed both issues. This item is considered closed, l

' ' * ' ' ' ' '

_-______mm -_______________.____ . _ _ _ _ _ _ _ _

-- - - - . . -.- - - -

,

,

E9 Review of Updated Final Safety Analysis Report (UFSAR)

a. Insoection Scope The inspectors reviewed sections 4.7,6.4.1 *nd 6.4.3 of the PBAPS Unit 2 UFSAR to verify PECO had correctly incorporated UFSAR information into GL 891U design

- documents for valves in the RCIC, HPCI and core spcay systems.

b. Observations and Findinos The system design pressures described in the aforementioned sections of the UFSAR were correctly incorporated into MOV design documents.

IV. Plant Suncort R1 Radiological Protection and Chemistry (RP&C) Controls

'The inspector performed a review of the radiological controls program, with speciel emphasis on the controls implemented for the Unit 3 refueling outage. Specific areas reviewed included: maintaining radiation exposures as low as is reasonably < .

achievable (ALARA); control of contamination and radioactive material; external '

exposure controls; organization and administration; and quality assurance oversight.

'

.

R1.1 ALARA a. insoection Scoce (83750)

A selected review of the program to maintain radiation exposures as low as is reasonably achievaDie (ALARA) was performed. Information was gathered by a review of radiation exposure goals, selected ALARA reviews, several ALARA initiatives, and through discussions with cognizant personnel, and tours through the plant.

,

- b. Observations and Findinas Radiation Exoosure Goals Radiation exposure goals were extensively used for outage work. This included

- dose goals for radiation work permits, per work area, for modifications, and total outage. - Performance versus goals were closely monitored, routinely published, and- !

!

work-in-progress reviews were performed when accumulpted radiation dose exceeded preset _thre; holds. Total outage dose, as measured by electronic dosimetry,- was 282 person-rem and exceeded the or:ginal outage dose goal of 225

, person-rem by 52 person-rem. The majority of this doce, approximately 34 person -

rem, was received during installation of plant modification POO271," Replacement of The Emergency Core Cooling Suction Strainers"in the torus. The major reason for

._

_ ..

. . .

..

,

l o

exceeding the established goal for the modification was due to an under estimate of the time required to perform underwater welding, design and installation problems requiring rework, and additional person-loading for in torus activities.

ALARA Reviews _

Three ALARA revinw packages were selected to evaluate the general quality of ALARA reviews including control rod drive exchange, drywell non-destructive examination, and a modification to install a ew wide range neutron monitoring system. ALARA packcges included radiation work permits, person-rem estimates, dosimetry requirements, anticipated dose rates, contamination levels, health physics operational concems, and required external and internal exposure controls. ALARA packages were detailed, included lessons learned from previous jobs, and were overall very good.

SRM Shuttle Tube Removal The ALARA review for removal of the D source range monitor shuttle tube included specific controls for handling highly radioactive components. The initial plan included a provision to re insert the SRM shuttle tube if dose rates exceeding 500 R/h were encountered. During initial removal, a dose rate of 750 R/h was measured and the tube was re-inserted. A maximum dose rate of 1200 R/h was calculateo, and that information was ur.ed to develop a revised detailed ALARA plan. The plan required fabrication of special transport containers / shields, use of long handled cutters, thorough coordination of work activities, and special provisions for contingencies. The radiological engineering supervisor stated that the SRM shuttle tube was removed from the reactor and transported to radwaste according to the ALARA plan for a total of 0.210 person-rem. The inspector enncluded that the shuttle tube removal was well planned and effectively implemented.

Modification POO271 Renlacement of ECCS Suction Strainers The AL/.RA plan for t:ie modification to replace the emergency core cooling system (ECCS) suction strainers in the torus included water filtration to remove radioactive material and improve water clarity; identification of radiation sources beneath the torus water; designation of low dose areas on the torus platform; coordination of dives with the operations department to ensure no systems were running in planned dive areas; use of communication devices; attempts to minimize support personnel in the torus; and strict contamination controls for removing personnel and equipment from the torus water. Overall, radiological controls appeared to be well planned and effectively implemented. Howes r, the inspector noted that personnel on the torus catwalk received greater dose per hour than some of the divers. The inspector reviewed radiological surveys of the torus and noted that torus bays 1-6 and 15&16 had an average dose rate of approximately 9.8 mR/h which was about twice the average general area radiation dose rate of 4 mR/h in bays 7-14. The inspector toured the torus room with a health physics technician and determined that elevated dose rates in these torus bays originated from residual heat removal (RHR) piping located outside and above the torus. The inspector confirmed this

.- . . . _ _ _ _ _ _ _ _ _ _ _ _ _ _ _

-

..

-.-

,

observation by performing a survey with a directional shielded probe on the catwtik in the torus. The inspector noted that the ALARA review for the modification did '

not include a documented evaluation of potential dose reduction measures such as system flushing or use of temporary shielding for radiation sources in the overhead of the torus room that contributed to radiation dose for the modification. The inspector concluded that this represented a weakness in the radiological control planning for the job The radiation protection manager stated that numerous -

opportunities for improvenient were being documented for incorporation into the post job review, and that lessons learned would be included in the ALARA plan for the Unit 2 ECCS suction strainer modification planned for October of 1998.

ALARA initiatives Source Reduction Team

,

A multi disciplined radiation source reduction "Fix-it Now" (FIN) team had been commissioned to work solely on source reduction activities. Team members included an operator and several health physics technicians that were supervised by a senior reactor operator. The team was assigned to identify and assess the impact of radiation sources, evaluate potential remediation efforts and potential radiation savings, and to plan and implement source reduction activities. In preparation for-planned work in Unit 3 reactor water cleanup system rooms, the source reduction FIN team initiated several system flushes to reduce general area dose rates. Very good results were achieved, including a reduction of general area dose rates in the A RWCU pump room from 2 - 80 mR/h to 2 - 4J mR/h, and a reduction of general area dose rates in the "B" non-regenerative heat exchange room from 2 - 200 mR/h

,

to 2 - 60 mR/h.

Radiatiort imaoino Camera The licensee had contracted the use of a remote radiation imaging camera that superimposed radiation images on photographs. The device was particularly useful

'

for the identification of radiation sources in congested and overhead areas. For example, the inspector reviewed several pictures obtained with the device that identified isolated radiation sources in overhead piping that were previously unknown. This information was provided to the source reduction FIN team for evaluation, c. Conclusions Based on this review, the inspector made the following conclusions:

• Overall, ALARA packages were detailed, included lessons learned from previous jobs, and were effectively implemented. However, a weakness in radiological control planning was identified in that the ALARA review for the Unit 3 emergency core cooling syctem (ECCS) suction strainer modification did not include a documented evaluation of radiation sources in the overhead of the torus room that c.ontributed to radiation dose.

- - - - - _ - - - . - _ _ - - - - _ _ - - ___

,

l.

I

• ALARA initiatives such as the use of a gamma imaging device to identify radiation sources and the commitment to establish a full time multi disciplined source reduction "Fix-it Now" team were commendable, and demonstrated strong management support for the ALARA program.

R1.2 Control of Contamination and Radioactive Material s. Inspection Scone (83750)

The inspector performed a review of the control of contamination and radioactive material. Information was gathered through plant tours and discussions with cognizant personnel, b. Observations and Findinas The major redinlogical controlled area (RCA) access was spacious, well staffod, and well equipped with both beta and gamma sensitive contamination monitoring equipment. A tool control facility was located immediately adjacent to the plant -

entrance within the RCA to control tool inventory and minimize the number of tools.

brought into the RCA. Many areas susceptible to contamination such as the residual heat removal (RHR) pump rooms had been decontaminated and painted to allow for better surface decontamination. Frequent housekeeping activities such as floor mopping at radiological control boundaries, surface wiping, and trash collections were observed. Contamination monitoring equipment throughout the plant were well maintained as evidenced by good material conditions and up-to-date calibration and source check records. All radioactive material packages examined by the inspector were labeled as radioective material and included appropriate radiological survey information.

Administration Buildina RCA Boundarv The inspector did note that the RCA boundary set-up at the fourth floor administration building was not ideal in that the design allo ned the commingling of controlled and clean areas at the egress point (i.e., the design allowed an individual who had been monitored to walk across the path of an individual who had not been monitored immediately prior to exiting). Licensee staff acknowledged the weakness in the area design, but stated that the area had not been redesigned due to physical space and floor loading limitations (the portal monitors are physically large and quite heavy); only individuals that successfully passed through a PM-7 gamma monitor equipped with a foot detector could enter the area; the area was monitored for loose contamination on a daily basis; and historical records demonstrated that there was a low risk for release of contamination at the egress point.

_ - _ _ _ _ ____-______-___

~~ n.- . , sa- --a a. - , , n

.-

c. Conclusions Based on this review, the inspector concluded that radioactive material and contamination controls were very good. A minor weakness existed in the design of the Administration Building RCA egress point; this weakness was inconsistent with the overall excellent design and condition of the ethar HP support facilities at Peach Bottom.-

R1.3 External Exoosure Controls a. jnspection Scope (83750)

The in,spector performed a review of external exposure controls. Information was gathered by a revie'N of radiological postings and boundaries, radiological briefings, . ,

and use of temporary shielding in the Unit 3 drywell.

b. Observations and Findinas The inspector toured the Unit 3 reactor building including the Unit 3 drywell and .

refuel ficor. Radiological boundaries were well defined, high radiation areas were clearly posted, and areas designated as locked high radiation areas were -

appropriately locked or controlled. The inspector observed frequent use of informational postings including dose rate range posting, and signs that identified areas with elevated and low dose rates. Radiological briefings provided by health physics technicians included a thorough discussion of job scope, work area dose -

rates, and required radiological controls. Audiovisual communications equipment were effectively used to minimize exposures for work in the drywell including control rod drive replacement. The inspector observed extensive use of temporary

, shielding in the Unit 3 drywell to shield recirculation suction and discharge piping and reactor water cleanup piping. Records showed that 24 shielding packages weighing approximately 20,000 kilograms were installed to reduce general area and job specific dose rates. Based on a review of pre and post shielding dose rates, the radiological engineering supervisor estimated that post shielding dose rates were reduced by 20 - 50% depending on area and component.

c. Conclusions Based on this review, the inspector concluded that external dose controls implemented for the Unit 3 refuel outage including radiological postings, high radiation area access controls, health physics briefings, use of audiovisual equipment, and use of temporary shielding were very good.

R5 Staff Training and Performence in RP&C

. . . --

.

e

a. insoection Scoos (83750)

At the completion of the refuel outage, the radiation protection manager (RPM) left -

employ nent with the licensee, and the radiological engineering supervisor w9s named acting RPM. A review was performed to determine if the individual's qualifications met the minimum qualification / experience requirements specified in the technleal specifications. Information was gathered through interviews, review of a resume, and review of technical specifications.

b. ,Q)servation and Findinas

'

Technical specification 5.3, " Unit Staff Qualifications," required the Manager-Radiation Protection to meet or exceed the qualification requirements of Regulatory Guide 1.8, " Personnel Select!on and Training." September 1975. The nspector ,

compared the qualifications of the acting RPM that were documented on a resume, ,

to the qualification requirements presented in Regulatory Guide 1.8. This review indicated that the individual met the minimum qualification requirements for the position of radiation protection manager.

c. Conclusion Based on this review, the inspector concluded that the acting radiation protection .

manager met the qualification requirements outlined in plant technical specifications.

R6 RP&C Organization and Administration a. IDsoection Scoce (83750)

The inspector reviewed the organization and administration of the health physics organization during the refueling outage. Information was gathered by a review of a health physics and ALAHA organization chart, observations in the plant, and through interviews with cognizant personnel. ,

b. Observations and Findinas Orgamation and staffing charts showed that the radiological controls organization was well organized with responsibilities clearly delineated and well staffed with approximately 110 health physics technicians. The staff was supported by health physics contractors, PECO's corporate office, and personnel from three other nuclear stations. During tours through the plant, the inspector discussed ongoing work activities and radiological controls with health physics technicians. These individuals were knowledgeable of ongoing and planned work, and of rad:ological /

controls implemented for outage work. Frequent communications were observed

. between health physics staff members and plant workers at the radiologically controlled area (RCA) access, radiation work permit (RWP) briefings, during health physics job coverage activities, and with posted information. The inspector also observed that health physics and plant management made frequent tours within the plant.

___

.

.

c. Conclusions Based on this review, the inspector concluded that the health physics organization was well organized and staffed to support outage work, and effectively communicated with plant staff.

R7 Qualitil Assuraiice in RP&C Activities a. Insoection Scone (837fiQ)

The inspoor reviewed quality assurance and self assessment ov'stsight of the radiological controls organization. Information was gathered by a selected review of radiological control issues documented in the performance enhancement program and by a roview of a quality assurance (QA) assessment checklist (Assessment A1001533)used to evaluate health physics program performance.

b. Dhservations and Findinas The inspector reviewed a list of eight issues related to radiological controls placed into the performance enhencement program (PEP) between the period of July 9, 1997 and October 10,1597, and discussed details of each event with the radiation protection manager. Three of the issues were categorized as radiological occurrence reports in each event, immediate corrective actions were implemented.

The PEP process also required a detailed description of the event, a determination of cause, documentation of the issun disposition, and corrective actions to prevent recurrehCo.

Qualiti assurance (QA) assessment checklist (Health Physics Operations and ALAM Assessment A1061533) incl >.ided li%s of health physics program requirements, methc>ds for verification, and snecific procedural references. The checklist was comprehensive, clearly listed program requirements, and was well detailed. The inspector concluded that the document could readily be used to assess health physics prograni and procedural compliance, c. Conclusions Based on this review, the inspector concluded ' hat the performance enhancement program and radiological occurrence program were effectively used to identify and resolve program deficiencies, and that quality assurance documents used to assecs health physics program performance were of very good quality.

. .. ..

-. _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _

'

O e

R8 Miscelleneous RP&C lasues R8.1 (Closed) Inspector Followuo item 50-387:388/97 06-05 "Multiole Personnel Contamination" A review was performed of licensee actions taken to investigate and evaluate multiple personnel contamination events that occurred in mid August 1997. The evaluation of this issue was documented in performance enhancement proces

. _ -. ._._ -.- - .- _--_ - - - . . . _- --

!

.

49 ,

spring thaw next year clnce additional rock buildup and ice damage sometimes occur over the winter months. However, at the end of the inspection period, PECO ;

'

elected to remove most of this debris via manual methods which did not require removal of sections of the fence. The inspectors had no further questions in this matter and visually confirmed the removal of the debris. No other sigr'*tcant areas of performance concern were noted during observations of security force activities.

F1 Status of Fire Protection Facilities and Ec;alpment ,

The inspectors reviewed the fire watch records for the period from November 1 10,1997.

Most plant fire watches are hourly fire watches and are performed by security force members. The mejority of the hourly fire watches are long standing watches for Thermo-

,

Lag materialinstalled in various locations throughout the plant; PECO is currently pursuing an Appendix H exemption that would ul'imately permit the relaxation of these fire watches.

The inspectors reviewed the listing of fire watches, confirmed the proper termination of -

selected flee watches no longer needed and discussed with security personnel the methods taken to randomly check on the actual completion of these fire watches. No problems were noted. The inspectors considered this program to oe a very reliable and effective system for ensuring the timely conduct of fire watches.

V. Manaaement Meetina

<

X1 Exit Meeting Summary The inspectors presented the inspection results to members of the licensee management on December 1,1997. The licensee acknowledged the findings presented.

V2 Review of UFSAR Commitments A discovery of a licensee operating their facility in a manner contrary to the Updated Final Saf sty Analysis Report (UFSAR) description highlighted the need for a special focused review that compares plant practices, procedures and/or parameters to the UFSAR cescription, While performing the inspections discussed in this report, the inspector reviewed the application portions of the UFSAR that related to the areas inspected. The inspector veriflod that the UFSAR wording was consistent 'with the observed plant practices, procedure and/or parameters.

. . _ , . . ., .,m. . - . ~ .,. , _

. - ~

J

O o

LIST OF ACRONYMS USED action request (AR)

action statement (AS)

edministrative guideline (AG)

APRM gain adjunt factor (AGAF)

as low as reasonably achievable (ALARA)

average power range monitors neu'ron i (APRMs)

control rod drives (CRDs)

control room emergency ventilation (CREV)

core power and ilow log (CPFL)

core spray (CS)

core thermal oower (CTP)

design input document (DID)

electro hydraulic control (EHC)

eleventh refuelini; outage (3R11)

emergency core cooling system I.CCCS)

emergency diesel generator (EDG)

emergency opera tin;; procedures (EOP)

emergency prepaiedness (EP)-

emergency service water (ESW)

end of cycle (EOC)

engineering change request (ECR)

engineered safety feature (ESF)

fix-it now (FIN)

functional testing (FT)

general procedure (GP)

Generic Letter (GL)

health physics (HP)

high pressure coolant injection (HPCI)

high pressure service water (HPSW)

hydraulic control urit (HCU)

improved TS (ITS)

Independent safety engineering group (ISEG)

inservice inspection (ISI)

inspector followup items (IFis)

instrument and control (l&C)

intermediate range monitor neutron (IRM)

licensee event report (LER)

limited senior reactor operators (LSROs)

limiting conditions for operation (LCO)

load tap changer (LTC)

local leak rate test (LLRT)

loss of coolant accident (LOCA)

loss of off site power (LOOP)

low pressure coolant injection (LPCI)

lubricating oil (LO)

-

._

O

.

i.

Attachment 1 2 main control rmn (MCR)

modification (MOD) motor generator (MG)

nuclear maintenance division (NMD)

nuclear review board (NRR)

offsite dose calculation manual (ODCM)

offsite power start up sou, t #2 (2SU)

offsite power start up source #3 (3SU) '

Poco Energy (PECO)

performance enhencement program (PEP)

plant operations review committee (PORC)

post-maintenance testing (PMT)

primary containment (PC)

primary contalnment isolation system (PCIS)

primary containment isolation valve (PCIV)

protected area (PA)

quality assurance (QA)

-radiologically controlled area (RCA)

rsted thermal power (RTP)

reactor core isolation cooling (RCIC)

reactor engineer (RE)

reactor feed pump (RFP)

reactor operator (RO)

reactor protection system (RPS)

reactor water cleanup (RWCU)

reliability centered maintenance (ROM)

residual heat removal (RHR)

residual heat removt.) (RHR)

safety evaluation report (SER)

safety related structures, system and components (SSC)

safety relief valve (SRV)

scram solenoid pilot valve (SSPV)

secondary containment (SC)

senior reactor operator (SRO)

shift technical advisor (STA)

shift update notice (SUN)

source range monitor (SRM)

specific gravity (SG)

spant fuel pool (SFP)

standby gcs treatment (SGTS)

standby liquid control (SLC)

station blackout (SBO)

structure, system and component (SSC)

surveillance requirement (SR)

surveillance test (ST)

systems approach to training (SAT)

trchnical requirements manual (TRM)

- technical specification (TS)

temporary plant alteration (TPA)

J

_ _ . . . . - _

-

~ _ . . __ .__ _ _ _ . _ . - _ .

a j

4 i

Attachment 1 3 j turbine bypass valve (BPV)  !

turbine control valve (TCV) j turbine stop valve (TSV)  !

undervoltage (UV)  !

unresolved item (URI) i updated final safety analysis report (UFSAR)  !

wide range neutron monitoring system (WRNMS) 1

!

INSPECTION PROCEDURES USED

/

IP 37551: .Onsite Engineering Observationr. .i IP 61726:- Surveillance Observations IP 62707: Maintenance Observation  :

IP 71707: Plant Operations l IP 71750: Plant Support Observations  !

IP 92700: Onsite Folicw of Written Reports of Nonroutine Events at Power  ;

Reactor Facilities  :

IP 92901: Operations Followup i'

IP 92902: Followup Engineering IP 92903: Followup Maintenance ,

IP 92904: - Plant Support Followup lP 93702: Prompt Onsite Response to Events at Operating Power Reactors Tl 2515/109 Inspection Requirements for Generic Letter 8910 " Safety Related i Motor Operated Valve Testing and Surveillance"  ;

.

l ITEMS OPENED, CLOSED, AND DISCUSSED  !

t Opened l 50-277;278/97 07-01 IFl Corrective Actions for Overtime Approval Control 1 50 277;278/97 07 02 VIO - Three Examples of Procedure Non Adherence - 3B ,

'

HPSW Pump Maintenance, Station Battery Startup, Cooldown Operation 50 277;278/97 07-03 URI Heatup/Cooldown Temperature Restrictions .'

50 277;278/97 07 04 URI 2A RFPT Trip Mechanism 50 277;278/97-07 05 NCV E-43 Bus Testing ,

50 277;278/97 07-06 IFl Implementation of a Revised Recirculation Flow versus

Hours Strategy

-

-

50 277;278/97 07 07 IFl EDG Lube Oil Piping *

QQ1td ,

50 277;278/94 12-02 URI- Pressure Locking Thermal Binding .

50 277:278/94 12 04 URI _ Periodic Verification 50 277;278/92 82-02 _ URI DC Motor Operated V0lve Stroke Times -

'50-277;278/95-04-02 . URI internal Secondary Containment Flooc;ing Review ,

<

l

- . . - - -

._- _ _. . . _ _ _

.. .. ._ . - . . _ _ -.

,

Attachment 1 4 50-2777278/96 08 02 VIO Failure to Meet TS Requirements for APRM Instrument Surveillance / Operability 50 277;278/96-08 03 URI Controls over the Core Thermal Power Calculation Programs 50 277;278/97-01-02 URI Effect of Control Rod Boron Leakage on core Reactivity 50 277;278/97 07-05 NCV E 43 Bus Testing 50 277;278/07 06-05 IFl Personnel Contamination Events 50 277;278/2 97-006 LER E 43 Bus Trip

f'

- - _