ML20132E927

Insp Repts 50-277/96-08 & 50-278/96-08 on 960908-1109. Violations Noted.Major Areas Inspected:Operations, Surveillance & Maintenance,Engineering & Technical Support & Plant Support

ML20132E927
Person / Time
Site:	Peach Bottom
Issue date:	12/18/1996
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20132E915	List: ML20132E913 ML20132E919 ML20132E927
References
50-277-96-08, 50-277-96-8, 50-278-96-08, 50-278-96-8, NUDOCS 9612240036
Download: ML20132E927 (34)

See also: IR 05000277/1996008

Text

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U. S. NUCLEAR REGULATORY COMMISSION

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REGION I

Docket / Report No. 50-277/96-08 License Nos. DPR-44 )

50 278/96-08 DPR-56

Licensee: PECO Energy Company

P. O. Box 195

Wayne, PA 19087-0195

Facility Name: Peach Bottom Atomic Power Station Units 2 and 3

Dates: September 8, - November 9,1996

Inspectors: W. L. Schmidt, Senior Resident inspector

R. K. Lorson, Resident inspector  :'

R. L. Nimitz, Senior Radiation Specialist, DRS

C. D. Beardstee, Reactor Engineer, DRS

C. G. Munson, Resident intern, NRR

J. W. Shea, Project Manager, NRR

Approved By: W. J. Pasciak, Chief

Reactor Projects Branch 4

Division of Reactor Projects

9612240036 961218

PDR ADOCK 05000277

G PM _

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EXECUTIVE SUMMARY

Peach Bottom Atomic Power Station

inspection Report 96-08

This integrated inspection report includes aspects of resident and region based inspection

of routine and reactive activities in: operations; surveillance and maintenance; engineering

and technical support; and plant support areas.

Overall Assurance of Quality:

The licensee (PECO Energy) operated both units safely over the period.

Overall PECO management responded well to two Unit 2 trips caused by turbine trips

which resulted from generator protective relaying action, and also lemoval of the Unit 2

turbine from service due to a high beming temperature condition (Section M2). During the

November 7 nuclear review board (NRB) meeting the Vice-President, Nuclear Operations

challenged plant management to aggressively pursue the root causes for these equipment

failures (Section 07).

PECO implemented an effective radiological controls self-assessment program (Section R7).

Plant OAerations:

Operators conducted routine and planned activities well, including: shutdown of Unit 2 for

the eleventh refueling outage (2R11), three Unit 2 start-ups, and several power reductions

at Units 2 and 3. The inspectors found good material condition at both units. However

the operators were challenged by several equipment issues following the Unit 2 outage.

Operators responded well to stabilize plant conditions during unexpected transient events

at both units (Sections 01,02 and 04).

Operators performed well during the refueling outage, including control of plant conditions, 1

response to transients, and identification of the high pressure coolant injection (HPCI) {

bearing / seal problems during start-up testing. Three minor performance issues were

identified dealing with control room operators including: improper electro-hydraulic control

(EHC) load-set during unit sta.t-up leading to one unexpected and one possible operation of

a bypass valve; a situation where the inspector questioned whether the Unit 2 reactor

operator (RO) was paying adequate attention to the instruments and controls at Unit 2

while adjusting the Unit 3 generator controls; and two on-shift senior reactor operators

(SROs) who were unable to describe the available methods for determining spent fuel pool

(SFP) temperature during refueling operations. Subsequent interviews verified adequate

corrective actions had been completed (Section 04.1).

While walking past the control room panel, a RO was distracted and inadvertently bumped

a Unit 2 safety relief valve (SRV) control switch to the open position, he immediately

recognized the error and shut the valve; the operating crew responded well to this event.

PECO implemented appropriate corrective actions designed to remove potential distractions

from the control room (Section O4.4).

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Maintenance and Surveillance:

PECO personnel conducted the observed routine maintenance and surveillance activities

well. Observed post-maintenance testing (PMT) requirements were appropriately

completed using routir'e surveillance testing. These routine PMT surveillance tests

identified the HPCI seal / bearing problem and the mis-wiring in the E-42 panel (Section

M1.2).

PECO properly tested the Unit 2 control rods prior to exceeding 40% reactor power. The i

diaphragm alternative response test (DART) method appeared to be adequate for ensuring i

acceptable control rod performance following replacement of the scram solenoid pilot valve :

(SSPV) (118) diaphragms. The inspector noted a minor concern in that the technical

specification (TS) bases could allow the use of DART testing for PMT activities other than

i the 118 valve diaphragm replacements (Section M1.3).

The inservice inspection program was implemented and controlled in accordance with NRC ,

requirements and commitments. Nondestructive examinations were performed by qualified ,

inspection personnel and data analysis was performed in accordance with procedures and i

ASME Code requirements (Section M2.3).

Overall PECO responded well to several equipment failures during the restart from the Unit

2 outage, this included good plant management and engineering involvement in the

investigations and corrective actions. In the reviewing these instances the inspector did

not identify any specific common maintenance problems. However, it appeared that the I

HPCI and #12 bearing problems were caused by maintenance activities and should have i

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been prevented. The inspector will review how PECO trends these occurrences though the

maintenance rule program (Section M2.1).

Through a review of qualifications for electrical and mechanical maintenance vendor  ;

personnel who performed safety-related maintenance during the Unit 2 outage, the  !

inspector found that PECO did not maintain an adequate systems approach to training l

(SAT) program. This included not maintaining documentation of qualification to perform I

tasks such as soldering, torquing and wire connection crimping. This was a violation of 10

CFR 50.120 (VIOLATION 96-08-01). Unresolved item (URI) 96-04-03, dealing with a

previous vendor qualification issue following a HPCI failure was closed, the corrective

actions will be reviewed as part of the violation response (Section M5.1).

Enaineerina:

The PECO engineering organization provided good support to plant activities, including

troubleshooting of equipment problems. Despite the good engineering responses, the

inspectors were concerned that the modification process did not ensure that a wire was

properly removed during an E42 bus breaker modification. This error allowed the

simultaneous closure of the both offsite power breakers, during testing (Section E.1).

On October 7, PECO did not perform well at assessing and evaluating all available plant

indications, which led to an unidentified inaccurate setting of the average power range

l monitors (APRMs) outside of the 2% of rated thermal power (RTP) band allowed by TS.

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This was a violation of the TS action statement in that the APRM functions were not

restored within one hour and a shutdown action statement was not entered. These  ;

conditions were unknown to the PECO reactor engineer and the reactor operators, at the

time, but PECO finally identified them. However, the inspectors determined that there was

sufficient information available that the reactor engineer (RE) and operators should have

identified the condition when it occurred. On this basis this violation was cited

(VIOLATION 96-08-02). PECO continued to review the controls over parameters used by

the plant computers to calculate core thermal power and the adequacy of current failed j

sensor information. These issues will remain unresolved pending review of PECO's 1

determination (URI 96-08-03) (Section E2.1).

PECO performed a good engineering evaluation of two Unit 2 core spray (CS) system

piping indications internal to the reactor vessel; and the maximum spent fuel temperature

prior to 2R11 (Section E2.2 and E2.3).

Plant Suocort:

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The inspector identified that prior to 2R11 PECO had staged several combustible material l

items inside an area located on the Unit 2135' elevation. This area was marked as a i

combustible free zone. PECO had not performed a specific analysis prior to storing these

materials, however, PECO promptly established a fire watch for the affected area. The

inspector determined that PECO's response was adequate, and did not observe any other

examples of improper material storage during the period (Section F1.1).

Three inspector followup items opened during the last Peach Bottom emergency

preparedness (EP) program inspection were closed during a recent Limerick EP inspection

(Section P8).

As-low-as-reasonably-achievable (ALARA) planning, internal and external exposure

controls, radiation worker training, contamination controls were effective (Sections R1.1,

R1.2, R1.3, R1.4, R1.5, and R5.1).

PECO identified a minor radiological performance issue when two 55 gallon drums used to

store radioactive material on the Unit 2 refueling floor were improperly marked. This issue

was considered a non-cited violation (Section R1.5).

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TABLE OF CONTENTS

EX E C UTIV E S U M M A RY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ii

TA8 LE O F CO NT ENTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . v

SUMM ARY O F PLANT ACTIVITIES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 .

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1 O PE R AT I O N S . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 I

01 Cond u ct of Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

01.1 General Comments ........................... ..... 1 1

02 Operational Status of Facilities and Equipment . . . . . . . . . . . . . . . . . . . 1  !

04 Operator Knowledge and Performance . . . . . . . . . . . . . . . . . . . . . . . . . 2

04.1 Refueling Outage - Unit 2 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2

04.2 Operator Response to Equipment Problems ................ 4

04.3 Conclusions ...................................... 4 1

07 Quality Assurance in Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5

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ll MAINTENANCE AND SURVEILLANCE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 I

M1 Conduct of Maintenance and Surveillance . . . . . . . . . . . . . . . . . . . . . . 5 i

M 1.1 Conduct of Maintenance ............................. 6 !

M1.2 Surveillance Activities ............................... 6

M1.3 Scram Pilot Solenoid Valve Maintenance . . . . . . . . . . . . . . . . . . 7 i

M1.4 Conclusions ...................................... 8 i

M2 Maintenance and Material Condition of Facilities and Equipment ...... 8

M 2.1 Significant Maintenance Related Equipment Challenges . . . . . . . . 8

M2.2 Conclusion - Maintenance and Material Condition of Facilities

and Equipment ................................... 11

M2.3 Inservice inspection Program Review . . . . . . . . . . . . . . . . . . . . 11

MS Maintenance Staff Training and Qualifications .................. 12

M5.1 Vendor Craft Training Program . . . . . . . . . . . . . . . . . . . . . . . . 12

lll ENGINEERING ............................................. 13

E1 General Engineering Comments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13

E2 Engineering Support of Facilities and Equipment . . . . . . . . . . . . . . . . . 14

E2.1 Average Power Range Monitor Calibration Error - Unit 2 . . . . . . 14

E2.2 Core Shroud and Core Spray System insoections . . . . . . . . . . . 18

E2.3 Spent Fuel Pool Heat Load Control ..................... 18

IV PL ANT S U PPO RT . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18

F1 Conduct of Fire Protection Activities . . . . . . . . . . . . . . . . . . . . . . . . . 18

F1.1 Combustible Material Storage . . . . . . . . . . . . . . . . . . . . . . . . . 18

P8 Miscellaneous EP Issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19

P8.1 (Closed) Inspection Follow-Up Item 50-277;278/95-14-

01; Discontinuance of emergency information brochure. ...... 19

P8.2 (Closed) Inspector Follow-up Item 50-277;278/95-14-02;

Emergency Plan errors. ............................. 19

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TABLE OF CONTENTS (Continued)

P8.3 (Closed) Inspection Follow-Up Item 50-277:278/95-14-04:

Corporate EP training deficiencies. ..................... 19

R1 Radiological Protection and Chemistry Controls ................. 20

R1.1 Unit 2 Refueling Outage Radiological Controls (Program

Changes) ....................................... 20

R1.2 Unit 2 Refueling Outage Radiological Controls

(Planning, Preparation, Emergent Work Control and Review) ... 20

R1.3 Unit 2 Refueling Outage Radiological Controls (Internal

Exposure Controls) ................................ 21

R1.4 Unit 2 Refueling Outage Radiological Controls (External

Exposure Controls) ................................ 21

R1.5 Unit 2 Refueling Outage Radiological Controls

(Control of Radioactive Materials and Contamination) ........ 23

R5 Training and Qualifications in RP&C ......................... 24

R5.1 Radiation Workers / Radiological Controls Personnel . . . . . . . . . . 24

R7 Quality Assurance in Engineering Activities . . . . . . . . . . . . . . . . . . . . 25

R7.1 Radiological incident Reports ......................... 25

S8 Miscellaneous Security and Safeguards issues . . . . . . . . . . . . . . . . . . 25

S8.1 (Closed) LER 2 96-008, Revision 1: Weaknesses in the Control

of Safeguards Information ........................... 25

V M AN AG EM ENT ME ETING S . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25

X1 U FS AR Revie w . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25

X2 Exit Meeting Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25

X2 Management Meeting Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26

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SUMMARY OF PLANT ACTIVITIES

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Unit 2 began the inspection period operating in end-of-cycle (EOC) coastdown at 51%  ?

power. Operators shutdown the unit on September 13 for 2R11. PECO completed the -

l outage and restarted the unit on October 1. Several equipment problems delayed the  !

power ascension as discussed in section 04.2 below, these included two automatic reactor i

scrams due to generator negative phase sequence relay problems, on October 6 and 15.

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The unit achieved 100 % power on October 24 and operated essentially there through the  !

end of the inspection period.  !

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Unit 3 began the inspection period operating at 100% power and remained at this power

i level for essentially the entire inspection period. PECO occasionally reduced unit load for

control rod pattern adjustments and the following:

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e On September 10 unit load was reduced to approximately 75% power for

condenser waterbox cleaning, i

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e On October 25 unit load was reduced to about 58% power for waterbox cleaning,

control rod drive scram time testing, and 3A reactor feed pump maintenance,

o On October 29 power was reduced to about 60% power to mitigate a lowering

condenser vacuum condition which developed due to off-gas recombiner system

problems.

I OPERATIONS '

01 Conduct of Operations'

01.1 General Comments (71707)

Routine observations showed that operators conducted normal activities including three

Unit 2 start-ups and several planned power reductions well. Operators responded well to

stabilize plant conditions transient conditions at Unit 2 such as two automatic reactor scrams, a turbine bearing high temperature condition, and an inadvertent opening of the

71D SRV. The operators responded well to a lowering condenser vacuum condition at Unit

3 following an unexpected isolation of the recombiner system. Despite the generally good

performance, the inspectors identified several minor knowledge and performance

weaknesses, as discussed in the applicable sections of this report.

02 Operational Status of Facilities and Equipment

a. Scoce:

The inspectors used Inspection Procedure 71707 to walkdown accessible portions of the

j following engineered safety feature (ESF) systems:

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• standby gas treatment (SGTS)

e low pressure coolant injection (LPCI) - Unit 2

• emergency diesel generators (EDG)

e emergency service water (ESW)

The inspector reviewed the overall plant material condition during and following the Unit 2

outage including: a walkdown of the drywell and torus interior and review of control room

equipment deficiencies.

b. Observations and Findinas:

During the ESF systera walkdowns, the inspectors identified no substantive concerns

finding acceptable equipment operability, material condition, and housekeeping. The

inspectors identified several minor discrepancies, which PECO corrected.

The inspectors toured the drywell finding good material conditions and proper access

controls. The tour of the torus interior showed good material condition and proper control

of foreign materials.

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PECO reduced the backlog of control room equipment deficiencies to near zero at the end

of the outage.

c. Conclusion:

The inspectors found good material condition at both units.

04 Operator Knowledge and Performance

a. Scope (60710. 71707)

The inspectors reviewed Unit 2 outage activities including normal control room conduct,

fuel handling and core verification, the unit restart, and operator responses to equipment

problems.

b. Observations and Findinas

04.1 Refueling Outage - Unit 2

Control Room Activities and Control of Eauioment

During the course of the outage the inspectors observed that PECO properly controlled the

need for emergency core cooling systern (ECCS) operability through general procedure

(GP)-20 " Temporary Defeating of ECCS Auto initiation Signals During Outages" and the

circulation and temperature monitoring of reactor coolant while shutdown in accordance

with GP-12 " Core Coolant Procedure". The inspectors further reviewed these procedures

finding that they complied with the appropriate TS requirements for these situations.

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PECO used a status board in the control room to provide clear and concise information

about equipment status and core decay heat load. Video cameras were appropriately used

to provide control room operators with information from the refueling floor, such as local

SFP temperature and level and SFP cooling skimmer surge tank level.

Work on the safety-related electrical busses was well controlled and necessary TS action

statements were entered for both Unit 2 and the operating Unit 3.

Operators had generally very good knowledge of plant conditions. The inspector noted one

minor knowledge deficiency during refueling operations involving two on-shift SROs who

were unable to describe the available methods for determining SFP temperature. The

inspector subsequently questioned three ROs regarding SFP temperature monitoring and

received the proper responses, indicating PECO corrective actions were appropriate.

Conduct of Refuelina

The refueling activities were performed well with the following specific strengths noted:

• The limited senior reactor operators (LSROs) for fuel handling provided excellent

command and control of the fuel handling evolutions.

• Communications between the personnel on the refueling bridge and with the control

room were good. The unit shift supervisor was kept wellinformed regarding the

status of the refueling operations.

• Good housekeeping controls and water clarity were maintained during the refueling

activities.

Reactor Start-up

The inspectors observed that control room operators performed well during the start-up

from the refueling outage and from the October 6 and 15 reactor scrams. The inspectors

found:

• The ROs and SROs performed reactivity changes in a controlled manner and

properly monitored neutron measuring instrumentation.

• Communications between the control room supervisor and the plant personne! were

good.

• Reactor cavity shield plugs were properly controlled during the initial start-up

activities.

• PECO transitioned smoothly from the reactor vessel pressure test to the reactor

start-up.

• The inspector did note two minor weaknesses with respect to the control of the

EHC system load-set setpoint during two of the reactor startups, specifically, the

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load-set was left near the actual reactor power at about 15% in one instance this

, caused a bypass valve to open as power was increased above the load setpoint and l'

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in the other case tne inspector identified, as the ROs began to increase power, that

the load-set was set near the current reactor power and that a bypass valve would t

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open. In both cases the operators subsequently increased the load setpoint to

115% power. The inspector noted that the startup procedure did not specify where

to set the load setpoint. PECO was pursuing providing additional information to the

operators.

04.2 Operator Response to Equipment Problems

.Egpioment Related Problems Followina the Outaae - Unit 2

Operators responded properly to the two automatic reactor scrams discussed above, and

to the main generator and HPCI bearing issues. Further, the plant auxiliary operator at the

HPCI turbine did a very good job identifying the bearing / seal problems bofore serous ,

damage resulted.

Lowerina Condenser Vacuum - Unit 3

On October 29 Unit 3 experienced a lowering condenser vacuum due to a problem with the

offgas system jet compressor. Operators responded very well. The reactor operator

quickly reduced reactor power, limiting the decrease in vacuum and the spare jet i

compressor was successfully placed in service. The inspector did note one minor issue ,

while observing the response to this transient. The Unit 2 reactor operator, in an effort to l

help the Unit 3 reactor operator, took a phone call from the PECO grid load dispatcher and l

subsequently crossed the control room and adjusted the Unit 3 generator voltage controller i

to limit the VARs being produced. While this was a technically correct action, the I

inspector questioned whether the Unit 2 RO was paying adequate attention to the )

instruments and controls at Unit 2 while adjusting the Unit 3 generator controls. PECO l

took good corrective actions on this issue by reinforcing the boundaries of the individual

unit reactor operators.

Inadvertent Safety Relief Valve Openina - Unit 2

On October 30, a RO inadvertently bumped the 71D safety relief valve (SRV) control

switch to the open position. The RO recognized the error and immediately shut the valve;

the operating crew responded well to this event. The inspector reviewed the control room

strip chart operating data and did not observe any reactor parameter changes resulting

from the event. PECO investigated this event and implemented appropriate corrective

actions designed to remove potential distractions from the control room.

04.3 Conclusions - Operator Knowledge and Performance

Operators performed well during the refueling outage, including control of plant conditions.

However the operators were challenged but responded well to several equipment issues

following the Unit 2 outage. The auxiliary operator identification of the HPCI bearing / seal

problems was very good.

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Three minor performance issues were identified dealing with control room operators. First

the control of the EHC load-set during unit start-up was not clear, leading to one-

unexpected and another prevented operation of a bypass valve. Second, a situation

where, during at Unit 3 plant transier t, the Unit 2 reactor operator . manipulated generator

controls for Unit 3. 1hm could have, but did not, lead to a lack of monitoring of Unit 2 l

parameters. Third, several SROs did not have a clear understanding of available

instruments and information to determine and monitor spent fuel pool temperature, during

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refueling operations.  !

07 Quality Assurance in Operations

During the NRB meeting of November 7, discussions were generally focused on nuclear

i safety topics. The plant manager presented a good discussion of the Unit 2 outage

activities and initiatives being developed to track plant performance. The Vice-President,

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Nuclear Operations challenged the plant management to understand the recent equipment

problems during the restart from the Unit 2 outage. This challenge appeared appropriate to

ensure aggressive pursuit of the root causes.

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The inspector noted that during a surveillance of refueling floor activities a quality  ;

assurance assessor identified that the lifting of reactor cavity shield blocks was not being

done in accordance with the approved procedure. The assessor identified lifting of the

blocks higher than assumed in the associated heavy load analysis (over the cavity hand

rail). The assessor appropriately addressed the situation with nuclear maintenance

personnel and the blocks were subsequently moved properly.

ll MAINTENANCE AND SURVEILLANCE

M1 Conduct of Maintenance and Surveillance

a. Scooc (61726, 62706)

The inspectors observed: the replacement of the 72A reactor vessel level transmitter, an

electrical circuit breaker preventive maintenance activity on the 3A high pressure service

water (HPSW) pump compartment, and several maintenance and modification activities

during the E-22 and E-42 emergency bus outages.

The inspector also reviewed numerous surveillance tests conducted during and following

the Unit 2 outage.

The NRR Project Manager reviewed the post maintenance tests (PMTs) conducted

following work on control rod drive mechanisms and hydraulic control units to verify

compliance with TS 3.1.4.3.

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b. Observations and Findinas

M1.1 Conduct of Maintenance

The technicians who replaced the reactor vessel water levelinstrument were

knowledgeable ard performed the change-out well using good electrical and radiological

practices.

The electricians involved in the HPSW breaker activity were well prepared and used the

approved procedure.

The inspectors observed the following during the modification and maintenance

observations performed on the E22 and E42 busses:

e The E22 bus work clearance boundary was walked down and found to provide

adequate protection for the workers and allowed testing of the system.

e The work included modifications to the offsite breaker control circuits that had been

previously completed on four of the eight other busses at both units.

e The work was conducted well, using approved procedures and work orders,

o PMTs appeared to cover the areas that were worked and properly identified a wiring

error. Post-modification testing included the simulated simultaneous loss of coolant

accident (LOCA) and loss of offsite power (LOOP) test,

e in one instance PECO testing found that the wiring for the E42 bus breaker had not

been propuly modified as a result of not including the removal of a known

extraneous wire in the modification package. This led to the closure of the normal

supply breaker in parallel with the alternate supply breaker, a condition that should

not be allowed to occur. PECO properly responded to this event and determined

through thorough troubleshooting that the wire, which had been identified during a

pre-modification walkdown as needing to be removed, had been left installed. This

wire sent a trip and a closed signal to the offsite breaker when an undervoltage

condition was inserted, and also allowed a closed signal to the alternate breaker.

M1.2 Surveillance Activities

During surveillance testing PECO personnel identified and properly addressed two out-of

calibration issues. First, during the test of the automatic start of all emergency diesel

generators (EDGs), the E-2 machine indicated that it did not reach full voltage of 4160 to

4400 volts. PECO determined that this was caused by an out-of-calibration voltage

recording device. Second, during the initial HPCI run at 175 psig, the high steam flow

instrument indicated greater than its assumed band of 5-25 inches of water. PECO

determined that this instrument had a calibration error and it was subsequently replaced.

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M1.3 Scram Pilot Solenoid Valve Maintenance

During 2R11 PECO performed maintenance activities on certain control rods and their

associated drive and control equipment. Among maintenance activities conducted, PECO

performed 19 control rod drive (CRD) exchanges. In addition PECO replaced the

diaphragms in 16 scram pilot valves (one SSPV-117 (117) valve and 15 SSPV-118 (118)

l valves) for the control rods that demonstrated the slowest scram times during the

shutdown. PECO has been replacing 118 valve diaphragms as part of a program to

address diaphragm hardening problems that have been a recent generic industry concern.

(See Inspection Report 50-277,278/95-26.) The 118 valve diaphragms that were i

replaced were a mixture of BUNA-N and Viton material diaphragms. The replacement I

diaphragms were of BUNA-N.

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TS SR 3.1.4.3 requires PECO to verify following work on control rods that could affect j

scram times, that a control rod scram time test is conducted before declaring the rod  ;

operable. Prior to declaring the control rods operable per TS 3.1.4.3, PECO performed j

PMT control rod scram time testing for all rods which had undergone CRD exchange and

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for the one control rod (Rod 23-34) which had undergone replacement of the diaphragm on

the 117 valve. However, for the 15 rods that had undergone only replacement of the 118

valve diaphragm, the licensee performed testing that evaluated diaphragm performance as

a means of determining that scram time was not adversely affected by the maintenance

activity.

The inspector found PECO's basis for not conducting scram time testing on these 15 l

control rods acceptable. The test method used, referred to as diaphragm alternative

response testing (DART), monitors transient air flow (air pressure) in the exhaust port of l

the 118 valve as an indication of diaphragm response. PECO performed as-found and as-

left DART testing and determined that valve response was improved for all replaced l

diaphragms.

Prior to the outage, PECO revised the TS Bases for SR 3.1.4.3 to reflect that DART testing

could be used to meet the SR, if it could be concluded that DART testing monitored the

performance of all affected components. PECO performed an evaluation of the Bases

change pursuant to 10 CFR 50.59. The 50.59 evaluation specifically considered the use

of DART testing as a means of meeting the SR for replacement of the 118 diaphragm. The

licensee concluded that because the 118 valve and 117 valve acted in series with the

scram valves and other CRD scram related components, changes in 118 diaphragm

performance provided a direct indication of the change in rod scram time introduced by the

118 diaphragm replacement activity. In the 50.59 evaluation, the licensee concluded that

DART testing could be used in lieu of scram time testing for 118 valve diaphragm

replacement only.

The inspector reviewed the as-found and as-left DART testing traces for two SSPVs which

had undergone exhaust diaphragm replacement. The inspector confirmed that 118 valve

response improved as a result of the replacement and agreed that the DART test

adequately monitored the potential effect of diaphragm replacement on scram time. The

inspector concluded that use of the DART testing was adequate to meet the scram time

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verification requirements of SR 3.1.4.3 for those rods that had undergone 118 valve

diaphragm replacement.

The inspector noted that scram time testing was performed for all 185 rods prior to

exceeding 40% power during the startup as required by TS SR 3.1.4.1 and that all rods

met the acceptance criteria.

The inspector did observe one issue of concern. The revised TS Bases for SR 3.1.4.3 did

not sufficiently describe limits on use of DART testing as a substitute for scram time

testing. The revised Bases stated that the SR could be met by performance of scram

testing or by DART testing when it is concluded that DART testing monitors the

performance of all affected components. The inspector expressed concern that the revised

Bases did not reflect that to date, DART testing was confirmed as an adequate means to

meet the SR only for 118 valve maintenance activities. As such, the inspector was

concerned that the Bases could be used to support use of DART testing for other PMT e

activities without the rigorous review that was conducted for the 118 valve replacement

activity.

M1.4 Conclusions - Conduct of Maintenance and Surveillance

PECO personnel conducted the observed routine maintenance and surveillance activities

well. Observed PMT requirements were appropriately completed using routine surveillance

testing. These routine PMT surveillance tests identified the HPCI seal / bearing problem and

the mis-wiring in the E-42 panel.

PECO properly tested the Unit 2 control rods prior to exceeding 40% reactor power. The

DART test method appears adequate for ensuring acceptable control rod performance

following replacement of the 118 valve diaphragms. The inspector noted a minor concern

in that the TS Bases could allow the use of DART testing for PMTs other than the 118

valve diaphragm replacements.

M2 Maintenance and Material Condition of Facilities and Equipment

M2.1 Significant Maintenance Related Equipment Challenges

Following the outage there were four significant equipment-related issues dealing with

equipment that PECO worked on during the outage:

• On October 2, while testing the system at less than 175 psig reactor pressure, the

HPCI booster pump outboard so) 3 rid bearing overheated due an improper

alignment. Maintenance persor;nat toworked the bearing and HPCI testing was

subsequently completed satisfactorily.

• On October 6 the unit automatically scrammed in response to a turbine

trip / generator lock-out caused by a generator negative phase sequence relay

actuation. PECO troubleshot the relay and generator and restarted the unit on

October 7.

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• On October 9 a high temperature condition on the generator #12 bearing (exciter

outboard) caused operators to halt the reactor power increase at approximately

86% power. PECO reduced power to remove the turbine from service, corrected i

the bearing problem and returned the generator to service on October 11. l

• On October 15 the unit automatically scrammed following a second generator

negative phase sequence relay actuation. PECO replaced the relay and restarted the

unit on October 16.

,

b. Observations and Findinas

Hiah Pressure Coolant Iniection Seal /Bearina Failure

PECO tested the HPCI system as required by TS 3.5.1 (SR 3.5.1.9). Upon initiation of the  !

system, the operator stationed in the pump room noted smoke emanating from the booster

pump outboard bearing and seal area. PECO promptly secured the system and declared it

inoperable. PECO entered the 14-day TS action statement, and notified the NRC per the

reporting requirements of 10 CFR 50.72, as appropriate.

Operations, maintenance, and engineering personnel met to determine a course of action.

> A visualinspection of the outboard bearing / seal shaft area did not reveal any obvious

damage. The licensee elected to conduct a " slow start" of the system after connecting

'

vibration monitoring equipment to existing instrumentation ports.. Additionally, an external l

temperature monitoring device was used to monitor the shaft seal area temperature during

the slow start of the system.

,

Using procedure AO 23C.3-2, "HPCI Manual Slow Start Operation," operators restarted the

system, however, the operator secured the system after observing seal housing

temperature increase rapidly and metal shavings exited in the shaft seal area.

, PECO's investigation determined the problem to be improper alignment of the booster

'

pump outboard bearing. The bearing alignment problem allowed contact between the wear

bushing and the pump shaft during operation. PECO replaced the bushing and outboard

seal and retested the system satisfactorily on October 2.

PECO investigated the root cause(s) for this event and determined that the bearing

alignment problem developed during reassembly of the booster pump assembly following

an outage corrective maintenance activity. Several causal factors were identified, involving

, the adequacy of maintenance procedures and the technicians' knowledge of dowel

alignment pins; which had been improperly installed during a prior maintenance activity.

PECO implemented an appropriate plan to diagnose and correct the observed problem. The

repairs to the booster pump problem were effective and PECO identified several appropriate

corrective actions. Overall, the licensee efforts during and following the failure were very

good.

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Neaative Phase Seauence Relav Actuation

The negative phase r,equence relay (346) provides protection to the generator from grid

developed phase imbalancas. The installed relay has an alarm feature and a subsequent

generator lock-out feature. The lock-out would cause a generator trip, a turbine trip, and a

reactor scram. During the outage the Unit 2 346 relay was removed, calibrated, and

reinstalled.

During reactor power increase following start-up, operators received the 346 alarm. Before j

they cou'd take the actions required by the alarm response card, the reactor scrammed due  !

to a generator lock-out and turbine trip.

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Following this scram, PECO investigated possible causes for the relay receiving a current

signal high enough to cause a trip. They determined that the relay possibly saw an

erroneous signal due to a loose connection in the voltage transformer circuit. PECO l

corrected the loose connection and restarted the unit, after installing a temporary plant  ;

alteration (TPA) that allowed monitoring of the input signal to the 346 relay. After over a

week the monitor showed no problems with the input signal and it was removed.

Several days after the monitor was removed this relay again caused a reactor scram.

PECO determined that the relay needed to be replaced, using a newer model that allowed  ;

monitoring of the relay negative phase current. PECO also approved the removal of the )

generator lock-out function and installed additional monitoring equipment prior to restart.

The old relay was sent to the manufacture for examination to determine the cause for the

actuation. The manufacture determined, preliminarily, that an internal connection, which

had not been soldered, may have caused the spurious actuation. Subsequently, PECO ,

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performed a TPA on the Unit 3 346 relay, to remove its lock-out function to prevent having

any unnecessary reactor scrams if that relay had the same fault as the initial Unit 2 relay.

The 346 relay provided a nonsafety-related, back-up generator protective function. I

Generator Bearina Overheatina

During the outage PECO performed work on the #12 (excitor outboard) turbine / generator

bearing, including installing a new vibration probe. Following placing the generator on the

grid and increasing power, operators noticed an increasing trend in temperature on this

bearing and a subsequent reduction in lubrication oil flow. The generator was removed

from service to allow bearing disassembly. Upon disassembly, PECO identified that the

bearing needed to be replaced, but could not determine a specific cause for the failure.

After extensive analysis of the bearing PECO identified that electrolysis of the bearing

material had occurred, characterized by microscopic pitting. Subsequent review indicated

that PECO had modified the generator shaft grounding device during the outage and had

not properly returned it to operation. This allowed the generated current to flow through

the #12 bearing to ground causing the microscopic pitting. PECO also identified that a

post-outage routine test of generator shaft voltage should have identified the ground path

through the bearing, but did not. PECO was pursuing why this test did not identify the

ground path and other corrective actions for not installing the shaft grounding device.

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M2.2 Conclusion - Maintenance and Material Condition of Facilities and Equipment

l

Overall PECO management attention to these issues was very good, this included plant

management and engineering involvement in the investigations and corrective actions.

In reviewing these instances the inspector did not identify any specific common

maintenance problems. However, the HPCI and #12 bearing problems were caused by i

maintenance activities and should have been prevented. These occurrences are trended {

through the maintenance rule program, which rnonitors the effectiveness of maintenance '

activities.

M2.3 Inservice inspection Program Review I

a. Inspection Scope (73753) .

I

The inspector reviewed PECO's inservice inspection (ISI) plans and schedules for the  !

current inspection period. In addition, the inspector reviewed the qualifications and

certifications of all contractor personnel involved in ISI.

Lastly, the inspector observed manual ultrasonic and magnetic particle examinations of

welds, and visual examination of components inside the reactor pressure vessel.

b. Observations and Findinas

!

The inspector determined that changes to the ISI plan were properly documented and

approved.

The inspector determined that the qualifications and certifications of inspection personnel

properly reflected pertinent information, such as; employer's name, person certified, i

activities qualified to perform, level of certification, effective period of certification,

signature of certifying nfficial, the basis used for certification, and annual eye j

examinations. The inspector determined that the inspection personnel met the required  !

ASME standards, and the qualifications and certifications were appropriately reviewed by

licensee personnel.

Through observation of nondestructive examination (NDE) activities, the inspector

determined that approved procedures were available and being followed. Examination

personnel were knowledgeable of the examination method and operation of NDE

equipment. NDE calibrations, examinations and data analysis were performed in

accordance with ASME Section XI requirements. Examination results and evaluation of the

results were recorded as specified in the ISI program and NDE procedures.

PECO performed an examination of a reactor water cleanup system weld in accordance

with NRC Generic Letter (GL) 88-01, "NRC Position on IGSCC in BWR Austenitic Stainless

Steel Piping." An indication was identified. The NRC inspector observed that the analysis

and inspection scope expansion were in accordance with the PECO's GL 88-01 program

commitments. The indication was corrected using a weld overlay process endorsed by an

NRC approved Code case. No further indications were identified.

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c. Conclusions

.

PECO's inservice inspection program was implemented and controlled in accordance with

NRC requirements and commitments. Nondestructive examinations were performed by

qualified inspection personnel and data analysic was performed in accordance with

procedures and ASME Code requirements.

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MS Maintenance Staff Training and Qualifications

MS.1 Vendor Craft Training Program

(OPEN) VIOLATION (96-08-01) - Failure to Adequately Control Vendor

Training / Qualification

(CLOSED) URI (96-04-03) - High Pressure Coolant Injection Failure due to Failed

Solder Connection l

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a. Scoce

The inspector reviewed PECO's vendor craft training program. The program plan, as

described in VCT 1 (Vendor Craft Training Program Plan) contains guidance for ensuring

proper qualification of vendor craft personnel performing specific tasks such as the

crimping and soldering of electricalleads, and torquing of mechanical components. The

program described three methods for qualification of vendor personnel including: a

documented review of the individual's previous qualifications and experience, task specific

testing, or completion of PECO training. ,

!

This review focused on the qualification records for five selected contract electricians who

performed independent safety-related modification installation activities during 2R11 and

on two recent events.

Specifically, the selected individuals had performed multiple activities involving the torquing

of fasteners and the crimping of electricalleads during modifications 2-P232 which

replaced the E-224 load center transformer and modification 2-P262 which changed the E-

42 emergency bus control circuit.

b. Observations and Findinas

The inspector reviewed the PECO vendor task specific qualification matrix and identified

that none of the individuals reviewed, who performed crimping or torquing during

modifications 2-P232 and 2-P262, had been documented as qualified to perform these

activities. The inspector interviewed PECO contract services and training department

personnel and determined that PECO had not implemented the VCT-1 qualification program

for the selected individuals. Specifically, PECO had not tested, trained or reviewed the

qualifications of these individuals prior to allowing them to perform safety-related work

activities.

The inspector did not have a specific safety concern regarding this work since a PECO

quality verification inspector verified its adequacy. Additionally, the selected craft

personnel were reported to have been qualified electrical journeymen and had received a

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l vendor crimp training lecture. PECO, however, had not evaluated the adequacy of these

l programs or the individuals qualifications.

The inspector noted two other recent events where vendor personnel performed

maintenance activities without their qualifications having been formally evaluated by PECO: '

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e The first event occurred in March 1995, and involved an improper Unit 3 HPCI

system solder connection (URI 96-04-03) that had been performed by a vendor

technician. The solder connection had not been performed in accordance with

PECO's requirements and ultimately f ailed, resulting in the Unit 3 system being

inoperable for about 25 hours2.893519e-4 days <br />0.00694 hours <br />4.133598e-5 weeks <br />9.5125e-6 months <br />.

• The second event occurred in October 1996, and involved the post modification

pressure testing of a capped Unit 2 primary containment penetration following a

transversing in-core probe (TIP) system modification. A PECO quality assurance

audit determined that the vendor technician who performed the test had not been ,

properly certified. The individual who performed the test had been previously I

employed by PECO and was certified to perform this type of testing while a PECO l

employee. j

c. Conclusions

10 CFR 50.120 requires PECO to maintain a SAT based program for electrical and

mechanical maintenance personnel. The statements of consideration for 10 CFR 50.120  ;

indicate that the such a program applies to contract personnel who perform independent I

work activities. A key element of such a program is the evaluation of the trainee's mastery

of the subject. Contrary to the above, PECO did not evaluate the qualifications of

individuals performing independent electrical and mechanical maintenance activities. This

is a violation of 10 CFR 50.120 (NOV 96-08-01).

The inspector closed URI 96-04-03 and will review the corrective actions for the HPCI

system f ailure as part of the violation response.

lll ENGINEERING

E1 General Engineering Comments

The PECO engineering organization provided good support to plant activities, this included

good troubleshooting support for: restoration of the E42 electrical bus, the HPCI

seal / bearing failure, negative phase sequence current relay actuation, and the #12

generator bearing failure.

Despite the good response to the E42 electrical bus closure of both offsite power breakers,

discussed in Section M1.1 above, it was noted that the modification process had

previously identified a wire installed that needed to be removed during installation. This

wire was not removed and caused the simultaneous closure of the offsite power breakers.

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E2 Engineering Support of Facilities and Equipment

E2.1 Average Power Range Monitor Calibration Error - Unit 2

(OPEN) VIOLATION 96-08-02 - Failure to Meet TS requirements for APRM

instrument Surveillance / Operability

(OPEN) URI 96-08-02 - Con.rols over the Core Thermal Power Calculation Programs

a. Insoection Scope

The inspectors reviewed a PECO identified event involving a non-conservative calibration of

the Unit 2 APRMs due to an incorrect indication of core thermal power (CTP) on October 7. .

b. Observation and Findinos

Core Thermal Power Calculation - Backoround

The plant monitoring system (PMS) computer gathers data on plant parameters for use in

the calculation of CTP. The actual CTP calculation is completed in the 3D Monicore

computer using data input from the PMS computer. The 3D Monicore computer

continually calculates and displays CTP on the core power and flow log (CPFL) cornputer

screen in the control room. Operators and reactor engineers (REs) use the CPFL to set the

APRM instrument gain to ensure that the monitors are reading within the accuracy required j

by TS (i 2% of rated thermal power) of core thermal power. The CPFL also displays i

APRM gain adjust factor (AGAF) which is an indication of how close the APRMs are

reading to actual CTP. An AGAF of 1.00 means that the APRM is indicating CTP i

calculated by the CPFL. An AGAF of greater than 1.0 means that the APRM is indicating

less than the CTP and conversely an AGAF of less than 1.0 indicates that the APRM is

reading higher than calculated CTP.

The 3D Monicore computer also does an additional calculation of CTP to be used in

determining the core thermal limits in the P-1 program. The P-1 program has an imbedded

check to ensure that plant efficiency meets given values depending on plant power level, in

the gross energy tracking (GET) sub-program. This includes a comparison of CTP to i

generator electrical output. If the plant efficiency is less than or greater than the limit, the

P-1 program will not produce an output. This is a possible indication of a failed sensor or a i

f aulty input.

Timeline

The following represents an approximate timeline of events, developed by the inspectors

from review of: operator and reactor engineer logs, Performance Enhancement Process

(PEP) documentation, plant computer print-outs and discussions with reactor engineering

and operations personnel. [ Inspector analysis of the issues is bracketed following timeline

entries.]

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October 7

e Initial Conditions: Unit 2 was in MODE 1 (RUN) operating at approximately 36%

power during power ascension. The 2C reactor feed pump (RFP) was inservice

supplying all the feedwater flow to the vessel (approx. 5.0 Mlbs/hr). j

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e At 3:58 p.m., the reactor operator placed the 2B RFP in-service, in preparation for

increasing reactor power. Through review of information the 28 RFP was

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developing approximately 0.5 Mlb/hr. The 2C RFP flow automatically decreased

from 5.0 to 4.5 Mlb/hr to maintain feedwater flow and reactor vessellevel j

constant.

Indicated CTP, as calculated by the 3D Monicore computer system decreased by

approximately 150 megawatts thermal (MWt).

The RE's log indicated that the RE was aware of the CTP decrease and attributed

the drop to starting the 2B RFP.

[The following did not change: reactor vessel level, generator electrical output, and

actual reactor power. The PMS computer places acceptance limits on the inputs to

ensure the data is valid. PECO's post-event evaluation found that the 3D Monicore

system assigned a value of 0.0 Mlb/hr to the 2B feedwater flow input since it was l

below the 0.7 Mlb/hr acceptance limit. Consequently, the indicated CTP was l

incorrectly calculated based on a total feedwater flow of 4.5 Mlb/hr rather than the

actual total of 5.0 Mlb/hr.]

At 4:00 p.m., the 3D Monicore routine automatically generated core thermal limits

printout did not run. The printout stated that the GET sub-program was terminating

due to a problem and that the automatic P-1 report scheduled for 4:00 p.m. could

not be produced.

[The P-1 report was not produced since the calculated plant thermal efficiency was

now greater (i.e., the same electrical power output for less CTP) and had exceeded

the GET sub-program limit for the given CTP.]

PECO's post-event review indicated that this P-1 printout failure was apparently not

noticed or evaluated by the RE or the RO.

e At 4:35 p.m., the AGAFs were reset to lower '..a APRM output to the lower (and

incorrect) CTP value indicated by the CPFL (i.e., all AGAFs on the CPFL indicated

less than 1.0).

[The plant data indicated, at this time, that all six APRMs were adjusted to read

approximately 130 MWt less than actual CTP (about 3.5% of rated CTP). This

l prevented the APRMs from meeting TS surveillance requirement (SR) 3.3.1.1.2

which required the APRMs to read within 2% accuracy of RTP.)

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[ Unknown M the operators, this placed Unit 2 into TS action statement 3.3.1.1.C

since failure to meet SR 3.3.1.1.2 made all APRMs inoperable per Functions 2b and

2c of TS Table 3.3.1.1 1. The action statement required PECO to reestablish the

APRM operability within one-hour.]

• At 4:50 p.m., after a control rod group was partially withdrawn, operators

requested a P-1 report to verify core thermal limits. However, the 3D Monicore -

failed to produce a P-1 report because the plant efficiency was beyond the

allowable range. Power ascension was halted until an official 3D Monicore P-1

could be produced.

• At 5:00 p.m., the reactor engineer initiated a PEP to document the problem with the

3D Monicore during the start-up.

• At 5:35 p.m., PECO did not meet TS action statement 3.3.1.1.C. TS action

statement 3.3.1.1.D then required PECO to enter TS action statement 3.3.1.1.F i

which required PECO to place Unit 2 in hot shutdown within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> (11:35 p.m.).

[PECO did not enter TS action statement 3.3.1.1.F, as required, because they had

not recognized the problem by this time.]

• At 8:20 p.m., based on previous discussions between the RE and the RE Manager,

PECO increased the 3D monicore plant efficiency upper acceptance limit, which

enabled 3D Monicore to produce a P-1 report to allow PECO to recommence power

ascension.

[This allowed P-1 to be run with ths inaccurate feed flow data, thus P-1 calculated l

the same incorrect CTP as the CPFL. The inspectors noted that PECO's assessment

that the 3D Monicore plant efficiency limits were toc m trictive was incorrect and

that a formal technical evaluation had not been performed prior to this modification.

Instead, the RE and the RE Manager based their decision to increase the upper

efficiency limit on an event that recently occurred at Limerick which they believed

to be similar.]

• From 9:00 to 10:30 p.m., as power ascension resumed, feedwater flow from the

28 RFP was increased from 0.5 Mlb/hr to 3.2 Mlb/hr.

[The inspectors noted that the 3D Monicore reported the correct total feedwater ,

flow and CTP on the CPFL as soon as feedwater flow from the 2B RFP increased

above 0.7 Mlb/hr.]

• At 10:36 p.m., all AGAFs were adjusted to indicate properly with correctly

calculated CTP values. l

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the APRMs outside their acceptance limits had not been exceeded.] l

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November 7

,

o During PEP review a reactor engineer identified that actual core thermal power had

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been 3.5 % higher than indicated following the AGAF change on October 7 at 4:35  :

p.m.

The inspectors noted the following concerns:

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The RE and operating crew did not properly diagnose the reason for the decrease in ,

indicated CTP Multiple plant indications were available such as feedwater flow,

, generator output, and the 4:00 p.m. P-1 report failure that should have caused  ;

'

these individuals to correctly determine the reason for the decrease in indicated j

CTP.

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The 3D monicore database was updated to raise the upper thermal efficiency j

acceptance limit without a formal engineering evaluation.  !

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There was no indication to the operator that a feed flow input was outside its i

allowable limit. The CPFL as discussed in the procedure for setting APRM gains is

supposed to have a failed sensor identification feature. A section of the procedure i

requires operators to verify that the CPFL does not have any failed sensor that does

not make sense for the given plant conditions. If a sensor is failed the procedure  ;

directs the operator to another routine test which allows the inputting of a

substitute value. The zero flow indication should have been recognizable to the RE

as a faulted value.

c. Conclusions

The RE and operating crew did not perform well at assessing and evaluating all available

plant indications. This led to an unidentified inaccurate setting of the APRMs outside of

the 2% RTP band allowed by TS. Further, while this condition was identified by a PECO

review, it was not timely with respect to identifying the poor RE and operator performance.

,

Technical specificatior, action statement 3.3.1.1.C required PECO to restore the APRMS to

within i 2% of RTP within one hour. TS action statement 3.3.1.1.D then required PECO

to enter TS action statement 3.3.1.1.F, which would require that the plant be placed in hot

shutdown in six hours if the APRM could not be returned to within the i 2% RTP limit.

Contrary to the above, on October 7, PECO did not restore the APRM accuracy to within

the SR 3.3.1.1.2 acc;.:recy limits within the one hour period and did not enter TS 3.3.1.1.F

as required. These conditions were unknown to the PECO RE and the reactor operators,

but finally identified by PECO. However, the inspectors determined that the RE and

! operators should have identified the condition at the time that it occurred. There was  ;

l sufficient information available including no change in generator electrical output and the

! inability of P-1 to calculate core thermal power to cause a review of APRM settings at the

time. On this basis, this violMion was cited (VIOLATION 96-08-02).

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PECO continued to revie- the controls over 3D Monicore database and whether the CPFL

should have indicated a failed sensor. These issues will remain unresolved pending review

of PECO's determination (URI 96-08-03).

E2.2 Core Shroud and Core Spray System inspections

PECO inspected selected accessible portions of the core shroud and the CS system during

2R11. The inspectors noted that two crack like indications were identified on the core

spray sparger T-box head. PECO performed a safety analysis of the indications and

determined that operation through the next operating cycle was acceptable. Additionally,

PECO inspected another CS T-box assembly and did not identify any other indications.

PECO submitted their analysis to the NRC as required by NRC Bulletin 80-13. The

appropriate NRC technical staff reviewed PECO's position and determined that the safety

analysis and the additional inspection activities were acceptable. The inspectors noted that

PECO engineering personnel were prompt and thorough in their response to this issue.

E2.3 Spent Fuel Pool Heat Load Control

Prior to 2R11 the inspector reviewed PECO's evaluation performed to determine the

maximum spent fuel pool (SFP) temperature during the refueling outage. PECO's analysis

utilized a number of conservative assumptions related to SFP loading and determined that

the design temperature limit of 150 degrees F would not be exceeded provided 2 of 3 SFP

heat exchangers were in-service. The inspector found PECO's analysis to be acceptable.

The inspector reviewed the 2R11 refueling operations and noted that the fuel movement

activities were bounded by PECO's analysis. The inspector performed several energy

balances and determined that the actual SFP heat loading was bounded by the analysis.

Additionally, the inspector noted that SFP temperature was always maintained well below

the design limit temperature.

IV PLANT SUPPORT

F1 Conduct of Fire Protection Activities

F1.1 Combustible Material Storage

The inspector identified that prior to the Unit 2 refueling outage PECO staged several

combustible materialitems inside an area located on the Unit 2,135' elevation marked as a

combustible free zone. The inspector discussed the storage of the items with the Fire

Protection System Manager and learned that PECO had not performed a specific analysis

prior to storing these materials. PECO promptly established a fire watch for the affected

area. The inspector determined that PECO's response was adequate, and did not observe

l any other examples of improper material storage during the period.

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P8 Miscellaneous EP issues

The following items, which were opened during the last Peach Bottom Emergency

Preparedness (EP) program inspection and were also applicable to Limerick (since the -

Emergency Plan is common to both facilities;, were closed during the recent Limerick EP

inspection (NRC Inspection Report 50-352,353/96-09).

P8.1 (Closed) inspection Follow Up item 50-277;278/95-14-01; Discontinuance of

emergency information brochure.

The licensee discontinued the distribution of emergency information brochures to

Pennsylvania residents within the 10-mile Emergency Planning Zone (EPZ). The licensee

currently provides emergency information to the public in local telephone directories for the

Limerick and Peach Bottom areas. The licensee also mails an information survey to EPZ

residents for both plants which provides the opportunity for people to express any special i

needs they may have, and to request an emergency information brochure if they so desire.

Information calendars are still provided to residents of Maryland. NRC review determined

that this practice meets the requirements of 10 CFR 50, Appendix E, IV.(d) for the l

distribution of emergency information to the general public.

P8.2 (Closed) Inspector Follow-up ltem 50-277:278/95-14-02: Emergency Plan errors. i

Inadequate quality control over the Plan and emergency response procedure (ERP) revisions

resulted in numerous omissions and typographical errors. The licensee committed to do a

review of the Plan and ERPs to correct these errors. 1

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During this inspection, the inspectors verified the licensee's review of the Plan and ERPs.

They also reviewed the Plan and spot-checked the ERPs for recurring errors; none were

identified.

P8.3 (Closed) Inspection Follow-Up item 50-277:278/95-14-04; Corporate EP training

deficiencies.

Although the corporate EP organization had been tasked with training and qualification of

emergency operations facility (EOF) responders, there was no documented plan to

complete the training. Additionally, numerous EOF responders had been granted waivers

to exceed their requalification dates for annual retraining.

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Inspectors reviewed the document that the licensee developed to specifically address the

corporate training issues, titled " Maintenance of the EOF ERO and Training Program."

They also reviewed the EOF training program plan, the course plan, qualification manuals,

and course handouts. These documents were appropriately detailed and specifically

described the training requirements for the emergency response organization (ERO)

responders in the EOF. Training, which included facility walk-throughs, classroom .

instruction, testing, and a mini-drill, was implemented. The inspectors verified that training I

4 was conducted in accordance with the training procedures in 1995 and 1996 for all six

ERO response teams.

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R1 Radiological Protection and Chemistry Controls

R1.1 Unit 2 Refueling Outage Radiological Controls (Program Changes)

a. Scope (83750)

The inspector reviewed selected radiological controls program changes implemented since

the previous inspection in this area. Areas reviewed included organization and staffing,

facilities and equipment, and procedure changes. ,

b. Observations and Findinas

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PECO implemented a radiological controls organization change in early September 1996  !

involving the departure of the current Radiation Protection Manager (RPM) and the

temporary promotion of the Radiological Engineering Manager to the RPM position. Tha

acting RPM met applicable qualification guidance of Regulatory Guide 1.8.

]

A new individual was assigned to provide training of station personnel in the area of

radioactive material shipping. This individual appeared to have limited experience and j

training in the area PECO was aware of this matter and initiated a plan to compensate for

the individual's limited experience and knowledge in radioactive material shipping.

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c. Conclusion

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No program changes were identified that would appear to reduce the effectiveness of the

radiological controls program.

R1.2 Unit 2 Refueling Outage Radiological Controls (Planning, Preparation, Emergent

Work Control and Review)

a. Inspection Scooe (83750)

The inspector reviewed the planning and preparation for the Unit 2 refueling outage

including control and review of emergent work. The inspector reviewed records, discussed

outage planning issues, and observed activities to verify proper radiological work controls.

b. Observations and Findinos

The ALARA exposure estimate review indicated effective planning and preparation for

planned and emergent outage radiological work activities. PECO closely tracked

conformance with pre-established ALARA goals. As of September 24,1996, the licensee

had accrued about 229 person-rem out of an expected year to date value of 266 person-

rem. The inspector noted very good ALARA plans for significant radiological work

activities (e.g., traversing incore detector replacemeni). PECO reduced its exposure during

lead shielding installation by about 50%, due to, in part, better efficiency and planning.

PECO was in the process of bench marking itself against similar facilities relative to

aggregate occupational exposure sustained for specific tasks (e.g., control rod drive

removal and replacement). Such an activity may allow for identification and use of

previously unidentified occupational exposure reduction methods.

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c. Conclusions

PECO implemented overall effective ALARA planning for the Unit 2 refueling outage

including emergent work.

R1.3 Unit 2 Refueling Outage Radiological Controls (Internal Exposure Controls)

a. Inspection Scoce (83750)

The inspector selectively examined the internal exposure control program. The inspector

reviewed records, discussed the program with cognizant personnel and observed exposure

control practices during tours of the RCA. The inspector independently calculstod

expected personnel exposure using estimated radioactive materialintakes.

b. Observations and Findinas

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The inspector observed work in progress and noted air sampling to be representative of air

in occupied zones. Also, DAC-hours were calculated and tracked, as necessary. The

inspector noted that, as of the end of the inspection (including the outage), no individual

had sustained any significant intake of airborne radioactivity.

The inspector noted that tha licensee performed a comprehensive particle size analysis to

support internal exposure assessment during outage turbine blade grit blasting activities.

c. Conclusions

PECO implemented an effective internal exposure control program.

R1.4 Unit 2 Refueling Outage Radiological Controls (External Exposure Controls)

a. Scope (83750)

The inspector selectively examined the external exposure control program. The inspector

reviewed records, discussed the program with cognizant personnel and observed exposure

control practices during tours of the RCA and observation of work activities. The areas

toured included: the Unit 2 drywell, reactor building, torus room, refueling floor, and

turbine building. The inspector reviewed high radiation area controls and general

radiological posting, implementation of the radiation work permit program, and

implementation of the dosimetry program.

The inspector also reviewed the radiological control of a troubleshooting activity conducted

during refueling operations on August 18 that was intended to correct minor leakage from

the Unit 2 refueling bridge pneumatic system,

b. Observations and Findinas

PECO maintained a real time exposure data base by use of an electronic dosimetry

l (ELD)/ access control system. Dosimetry alarms were conservatively set, including those

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provided for high radiation areas. PECO provided workers briefings, as required, by

applicable radiation work permits and 10 CFR 19.12. No workers (vendor or licensee)

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exceeded 2 rem calendar year exposure. Workers were observed to be wearing dosimetry

as prescribed and were noted to be generally knowledgeable of radiolugical work

conditions. However, although radiological conditions in the area were insignificant, two

workers questioned in the outboard main steam line isolation valve (MSIV) room on

September 23,1996, were not generally knowledgeable of ambient radiological conditions.

The workers overestimated conditions and were immediately reinstructed on the actual

radiological conditions.

The inspector reviewed PECO's radiological controls provided for removal of the drywell

personnel hatch, equipment hatch, and refueling floor shield blocks (first layer) while at

power. The licensee provided effective controls for this activity, including neutron

monitoring and surveys consistent with Regulatory Guide 8.14, " Personnel Neutron

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Dosimeters," dated August 1977.

The inspector noted that PECO's personnel dosimetry system was retested in August 1996

in accordance with National Voluntary Laboratory Program guidance, following a previous

failure of the dosimetry to meet test criteria in a testing category (category Vil). The

dosimetry passed the retest.

Areas (e.g., high radiation areas, radiation areas) were properly posted and locked (as

appropriate). However, the following observation was noted.

e During a tour of the Unit 2 drywell on September 23,1996, the inspector noted

that the licensee used posting and flashing lights to inform personnel of elevated

exposure rate locations. However, several areas were identified that exhibited

exposure gradients (i.e., personnel could pass from about a 20 mR/hr radiation field

to greater than 100 mR/her field in a short distance) that contained no such posting

or lights. Furthermore, it was not immediately apparent that one was entering into

such radiation fields due to the sharp gradients.

Regulatory Guide 8.38, " Control of Access to High and Very High Radiation in

Nuclear Power Plants," dated June 1993, indicates that high radiation area

boundaries may be established at locations beyond the immediate boundaries of the

high radiation area to take advantage of natural or existing barriers. The guide also

indicates that individual high radiation areas (except in relatively small areas) should

be barricaded and posted separately when this option is utilized. The inspector

noted that PECO was using the drywell personnel access hatch as the high radiation

area control point.

PECO subsequently toured the drywell and identified several areas for improved

postir.g and placed additional high radiation area posting within the drywell. The

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licensee also posted low dose wait areas on the lower elevations of the drywell.

The licensee initiated action to provide for review of drywell posting for future

outages.

PECO established " standing" radiation work permits (RWPs) for areas as well as

other types of RWPs (e.g., special). The inspector notea that the RWPs typically

permitted certain defined work and also included a statement (as work description)

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that other " approved work" was authorized. The inspector questioned personnel,  !

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including radiation protection control point personnel, as to what constituted )

" approved work." The inspector was not able to identify a consistent definition for

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approved work and was concerned that such a RWP statement might provide <

inadequate work control. PECO initiated a review of this matter.

The inspector observed one exampic where an individual, who attempted to tighten a

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fitting during troubleshooting of an air leak from the refueling bridge pneumatic system, did

j not comply with the scope of his RWP. The individual performed the work under the refuel

fluor at.3a standing RWP (PB0991003) which required the individual to discuss the intended

! work evolution with and receive a briefing from the health physics (HP) technician. The HP

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briefing only discussed performing a visualinspection of the fitting and did not address

tightening of the fitting. PECO health physics procedure (HP-C-310) requires that all work

performed under an area standing RWP be approved by health physics. The inspector

i noted that since the air system was reported to be free of contamination; tightening of the 4

] fitting would not have been expected to increase the radiological risk to the worker.

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f c. Conclusions

PECO implemented a generally effective external exposure control program. A few minor

j performance issues of low radiological consequence were noted.

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R1.5 Unit 2 Refueling Outage Radiological Controls j

i (Control of Radioactive Materials and Contamination) l

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a. Scope (83750)

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i The inspector selectively reviewed radioactive material and contamination control

, practices. The inspector reviewed the adequacy of supply, maintenance, and calibration

and performance checks of survey and monitoring instruments; and the use of personal

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contamination monitors and friskers, including the means used to identify hot particle

, contamination. i

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j b. Observations and Findinos l

PECO implemented generally effective contamination control work techniques and prompt

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correction and cleanup of contamination. Contaminated areas, including the Unit 2

drywell, exhibited generally low levels of contamination. Calibrated and checked survey

instrumentation was available and used throughout the station.

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, The inspector identified two 55 gallon drums on the refueling floor on September 23,

1996, that were not labeled consistent with the licensee's procedures or 10 CFR Part 20.

i The drums measured 80 mr/hr and 30 mr/hr on contact, respectively, and only exhibited a

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radioactive materiallabel. No additional information was contained on the label. Procedure

J HP-C-810, Rev.1, Section 5.1.5, specifies that radioactive material be labeled with

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information, as necessary to permit individuals handling or working ir; the vicinity thereof to

{ avoid or minimize exposure.

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3 The inspector noted that a sign was posted near the drums, and other drums, alerting

! personnel to general radiation fields in the area. Also, radiation protection personnel

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monitored work activities on the refueling fuel. The drums were immediately labeled and

parsonnel were re-instructed to properly label radioactive material.

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c. Conclusions

PECO implemented a generally effective contamination control program. A minor

performance issue was identified where two 55 gallon drums used to store radioactive

4 material on the Unit 2 refueling floor were improperly marked. This issue is considered a

i non-cited violation consistent with Section IV of the NRC Enforcement Manual.

R5 Training and Qualifications in RP&C

R5.1 Radiation Workers / Radiological Controls Personnel

a. Scope (83750)

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The inspector reviewed the training and qualification records of selected contractor

radiological controls personnel, and radiation workers. The training and qualification of

these individuals were reviewed relative to applicable TS and procedural requirements and

10 CFR 50.120. The review included training records, personnel resumes, and

qualification criteria.

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b. Observations and Findinas I

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PECO implemented a generally well-defined training and qualification program for  ;

contracted radiological controls personnel who were responsible for radiological oversight

during the outage. Job coverage standards (e.g., system breaches, reactor cavity

draindown, reactor disassembly, removal of items from fuel pools) were established and

implemented to provide guidance for radiological coverage of various significant work .

tasks. Contractors were provided training on new procedures and procedure changes. l

Contractors were evaluated on task performance capabilities using mock-up systems and l

remote controlled radiation survey meters. Radiological controls personnel were qualified

in accordance with applicable requirements and radiation workers were provided applicable

general radiation safety training. PECO provided a comprehensive refueling outage

handbook to all personnel, as well as, an outage organization chart.

c. Conclusions

PECO implemented an effective program to train and qualify contractor radiological controls

personnel providing radiological oversight of outage radiological work activities. Radiation

workers were provided appropriate training in radiological controls.

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R7 Quality Assurance in Engineering Activities

R7.1 Radiological incident Reports

a. Scope (83750)

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l Selected PECO radiological self-assessments were reviewed.

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b. Observations and Findinas

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j PECO took effective and timely action on self identified concerns. The inspector noted

generally good performance-based oversight of activities.

j c. Conclusions

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PECO implemented an effective program for self-identifying and correcting self-identified

issues and concerns.

j S8 Miscellaneous Security and Safeguards issues

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j S8.1 (Closed) LER 2-96-008, Revision 1: Weaknesses in the Control of Safeguards

i information

PECO revised LER 2-96-008, which discussed the inadequate control of safeguards

3 material, to include PECO's completed investigation of the event. This event was

i discussed in NRC Inspection Report 50-277,278/96-06 and a NRC specialist inspection is

}; scheduled to review the results of PECO's event investigation.

4

i V MANAGEMENT MEETINGS

X1 UFSAR Review

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A recent discovery of a licensee operating their facility in a manner contrary to the Updated

j Final Safety Analysis Report (UFSAR) description highlighted the need for a special focused

d

review that compares plant practices, procedures and/or parameter to the UFSAR

description. While performing the inspections discussed in their report, the inspectors

reviewed the selected portions of the UFSAR that related to the areas inspected. No

UFSAR discrepancies were identified during this review.

X2 Exit Meeting Summary

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At the conclusion of the report period, on November 26, the inspectors discussed the

findings and conclusions and the overall period conclusions with members of PECO

management. In all cases the findings and conclusions presented were acknowledged.

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X2 Management Meeting Summary

On September 12 and 13 the NRC Region i Administrator visited Peach Bottom. He held

discussions with a number of plant supervisors and management personnel and conducted

a plant tour.

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LIST OF ACRONYMS USED

APRM gain adjust factor (AGAF)

as-low-as-reasonably-achievable (ALARA)

average power range monitors - neutron (APRMs)

control rod drives (CRDs)

control room emergency ventilation (CREV) ,

core power and flow log (CPFL)

core spray (CS)

core thermal power (CTP)

diaphragm alternative response test (DART)

electro-hydraulic control (EHC)

eleventh refueling outage (2R11)

emergency core cooling system (ECCS)

emergency diesel generators (EDG)

emergency preparedness (EP)

emergency service water (ESW)

end-of-cycle (EOC)

engineered safety feature (ESF)

functional testing (FT)

general procedure (GP)

Generic Letter (GL)

health physics (HP) .

high pressure coolant injection (HPCI) l

high pressure service water (HPSW)

hydraulic control unit (HCU)

improved TS (ITS)

inservice inspection (ISI)

inspector followup items (IFis)

intermediate range monitor - neutron (IRM)

licensee event report (LER)

limited senior reactor operators (LSROs)

limiting conditions for operation (LCO)

load tap changer (LTC)

loss of coolant accident (LOCA)

loss of off-site power (LOOP)

low pressure coolant injection (LPCI)

motor generator (MG)

nuclear review board (NRB)

offsite power start-up source #2 (2SU)

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

performance enhancement program (PEP)

plant equipment operator (PEO)

post-maintenance testing (PMT)

primary containment (PC)

primary containment isolation system (PCIS)

rated thermal power (RTP)

reactor engineer (RE)

reactor feed pump (RFP)

reactor operator (RO)

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reactor protection system (RPS)

residual heat removal (RHR)

safety evaluation report (SER)

safety relief valve (SRV)

scram solenoid pilot valve (SSPV)

secondary containment (SC)

senior reactor operator (SRO)

source range monitor (SRM)

spent fuel pool (SFP)

standby gas treatment (SGTS)

standby liquid control (SLC)

station blackout (SBO)

surveillance requirement (SR)

surveillance test (ST)

systems approach to training (SAT) *

technical requirements manual (TRM)

technical specification (TS)

temporray plant alteration (TPA)

turbine bypass valve (BPV)

turbine control valve (TCV)

turbine stop valve (TSV)

undervoltage (UV)

unresolved item (URI)

updated final safety analysis report (UFSAR) j

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