IR 05000286/2001007

IR 05000286/2001-007, Indian Point 3 Nuclear Power Plant. on 07/18/2001 Related to Safety and Compliance. Non-cited Violations Noted

ML012750182
Person / Time
Site:	Indian Point
Issue date:	10/01/2001
From:	Eselgroth P Entergy Nuclear Operations, Reactor Projects Branch 2
To:	Barrett R
References
IR-01-007
Download: ML012750182 (22)

Text

October 1, 2001 Mr. Robert Vice President, Operations - IP3

Entergy Nuclear Operations, Inc.

Indian Point 3 Nuclear Power Plant

P. O. Box 308

Buchanan, NY 10511SUBJECT:INDIAN POINT 3 NUCLEAR POWER PLANT - NRC INSPECTION REPORT 50-286/01-07

Dear Mr. Barrett:

On August 18, 2001, the NRC completed an inspection at the Indian Point 3 nuclear power plant. The enclosed report presents the results of that inspection. The results were discussed

on September 10, 2001, with you and other members of your staff.

The inspection was an examination of activities conducted under your license as they relate to safety and compliance with the Commission's rules and regulations, and with the conditions of

your license. Within these areas, the inspection consisted of a selected examination of

procedures and representative records, observations of activities, and interviews with

personnel.

Based on the results of this inspection, the inspectors identified two issues of very low safety significance. These findings were determined to be violations of NRC requirements. However, because of their very low safety significance and because they have been entered into your

corrective action program, the NRC is treating these issues as Non-Cited Violations (NCVs) in

accordance with Section VI.A.1 of the NRC's Enforcement Policy. If you deny any of these

Non-Cited Violation, you should provide a response with the basis for your denial, within

30 days of the date of this inspection report, to the Nuclear Regulatory Commission, ATTN:

Document Control Desk, Washington DC 20555-0001; with copies to the Regional

Administrator, Region I; the Director, Office of Enforcement, United States Nuclear Regulatory

Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at the Indian Point

3 Nuclear Power Plant.

In accordance with 10 CFR 2.790 of the NRC's "Rules of Practice," a copy of this letter and its enclosure will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Record s (PARS) component of the NRC's document system (ADAMS). ADAMS is accessible from the NRC Web site at

http://www.nrc.gov/NRC/ADAMS/index.html (the Public Electronic Reading Room).

Sincerely,

/RA/Peter W. Eselgroth, Chief Projects Branch 2

Division of Reactor Projects Robert J. Barrett2 Docket No. 50-286 License No. DPR-64 Enclosure: Inspection Report 50-286/01-07

Attachment 1 - Supplemental Information cc w/encl:J. Yelverton, Chief Executive Officer M. Kansler, Senior Vice President and CEO

J. Knubel, Vice President Operations Support

F. Dacimo, Vice President - Operations

H. P. Salmon, Jr., Director of Oversight

D. Pace, Vice President - Engineering

J. Kelly, Director - Licensing

C. D. Faison, Director - Licensing

J. Donnelly, Licensing Manager

A. Donahue, Mayor, Village of Buchanan

J. McCann, Manager - Nuclear Safety and Licensing

C. Donaldson, Esquire, Assistant Attorney General, New York Department

of Law Chairman, Standing Committee on Energy, NYS Assembly

Chairman, Standing Committee on Environmental Conservation, NYS Assembly

R. Albanese, Executive Chair, Four County Nuclear Safety Committee

Chairman, Committee on Corporations, Authorities, and Commissions

The Honorable Sandra Galef, NYS Assembly

P. D. Eddy, Electric Division, New York State Department of Public Service

W. Flynn, President, New York State Energy Research and Development Authority J. Spath, Program Director, New York State Energy Research

and Development Authority

C. Hehl, SRC Consultant

C. Terry, Niagara Mohawk Power Corporation

R. Toole, SRC Consultant

R. Schwarz, SRC Consultant

County Clerk, Westchester County Legislature

A. Spano, Westchester County Executive

R. Bondi, Putnam County Executive

C. Vanderhoef, Rockland County Executive

J. Rampe, Orange County Executive

T. Judson, Central NY Citizens Awareness Network

M. Elie, Citizens Awareness Network Robert

SUMMARY OF FINDINGS

IR 05000286-01-07, on 07/01-08/18/2001, Entergy Nuclear Northeast; Indian Point 3 Nuclear

Power Plant.

The inspection was conducted by resident and regional inspectors. The inspectors identified two Green issues. The significance of most findings is indicated by their color (Green, White

Yellow, Red) using IMC 0609 "Significance Determination Process" (SDP). Findings for which the SDP does not apply are indicated by "No Color" or by the severity level of the applicable violation. The NRC's program for overseeing the safe operation of commercial nuclear power reactors is described at its Reactor Oversight Process website at http://www.nrc.gov/NRR/OVERSIGHT/index.html

.A.Inspector Identified Findings

Cornerstone: Physical Protection

Green.

During an NRC inspection, it was discovered that the submittal of Revision 20, April 4, 2001, of the Physical Security Plan did not meet the requirements of 10 CFR 50.54(p)(2), which permits only changes that do not decrease the effectiveness of the plan. This finding is considered a non-cited violation of 10 CFR 50.54 (p)(2). Corrective measures were initiated upon identification.

The finding was of very low safety significance because, although it indicated a vulnerability of safeguards systems or plans, no actual intrusion occurred; and there have not been greater than two similar findings in the past four quarters. (Section 3PP1)

Green.

During the conduct of the inspection, issues associated with contingency response equipment were identified. Specifically, the number of rounds of ammunition immediately available to some responders, and the lack of a non-lethal weapon, did not fully conform to the requirements of 10 CFR 73, Appendix B, paragraphs V.A.4(a)(3),

and V.A.5.8. The vulnerability was detected through a table-top drill, and consequently is not considered a violation of NRC requirements. Notwithstanding, corrective measures were initiated upon identification.

This issue was of very low safety significance because, although it indicated vulnerabilities in the safeguards program, no actual intrusion occurred, and there have not been greater than two similar findings in the past four quarters. (Section 3PP1)

B.Licensee Identified Violations

There were no licensee identified violations iii SUMMARY OF

PLANT STATUS

The plant was at 100% power at the beginning of the inspection period. On July 21, 2001, a circulating water pump motor failed due to insufficient cooling and had to be replaced. As a

result, the licensee reduced plant power on July 27, 2001, to approximately 95% to provide an

additional margin of vacuum above the minimum required for plant operation. After the pump

motor was replaced, the plant was returned to 100% power on July 28, and remained there for

the remainder of the inspection period.1.REACTOR SAFETY(Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity, Emergency

Preparedness )1R01Adverse Weather Protection

a. Inspection Scope

(71111.01)

The Indian Point site experienced unusually high ambient air temperatures during the week of August 6 - 10, 2001. The inspectors evaluated the licensee's implementation of

their adverse weather procedures and their compensatory measures for the affected

conditions during periods of high ambient temperatures. The temperature of the Hudson

River steadily increased from ~82F on Monday to ~86F on Friday (maximum design temperature for plant operation is 95F). During the subject week, the plant remained at

100% power, and no local grid instabilities occurred. However, due to record level

electricity demands, the area system operators requested that all plant trip risk activities

be suspended or deferred into the evening hours each day until the peak load demand

had passed.

The licensee complied with this request. The inspectors reviewed 8 to operations directive OD-37, "Seasonal Weather Protection," to verify

that actions taken to preclude heat buildup in plant spaces had been completed, and

that operator actions were defined in the procedure to maintain readiness of essential systems. The inspectors also selected for inspection the 480 volt-alternating current (VAC) system and the emergency diesel generators (EDGs) as two risk-significant systems that must be protected from adverse weather. These systems are required to function during a reactor shutdown, and their functionality could have been challenged by the unusually

high ambient temperatures The inspectors performed system walkdowns inside plant spaces to assess the functionality of these systems, and verified that they would be

available for performance of their shutdown functions. During the walkdowns, the

inspectors noted that temperatures above 95F in the 480 VAC Switchgear Room caused

control room alarms, and required operators to closely monitor equipment performance.

On August 9, the room temperature exceeded 104F and operators entered alarm response procedure ARP-13 (Panel SKF: "High Room Temp, Control Building, El. 15ft").

The procedure required operators to open all doors into the room, to disable the CO 2 fire suppression system and establish a fire watch, and to assure that active ventilation was

maintained inside the room. The room air temperature eventually reached ~108F; however, no equipment performance problems were noted and the room temperature remained below the maximum of 117F. The highest safeguard bus input transformer 2 winding temperature remained <210F (maximum limit = 347F) and the room temperature returned to <104F by 8:30 p.m. the same evening.

The inspectors observed that temperatures inside all three EDG cubicles remained slightly above 90F for most of the week, and that all cubicle ventilation fans operated

almost continuously. However, no alarm conditions existed, and no equipment

degradation resulted from high room temperat ures. The ventilation system was able to keep the cubicle temperatures from increasing further. During a routine surveillance on

the 33 EDG on August 9, a high jacket water temperature alarm occurred at 165F;

however the licensee determined that the alarm came in at a lower temperature than

expected, and was well below the maximum temperature (190F) for engine operation.

The inspectors verified that all three EDGs remained available throughout the high

temperature period.

b. Findings

No findings of significance were identified1R04Equipment Alignment

a. Inspection Scope

(71111.04)

Auxiliary Feedwater System Partial Walkdown On July 31, the inspectors performed a partial system walkdown of the auxiliary feedwater (AFW) system while the 31 motor-driven AFW pump was removed from

service for a scheduled maintenance outage. The inspectors verified that the redundant

32 and 33 AFW pumps were properly aligned to support normal and emergency plant

operations in accordance with check-off list COL-FW-2, "Auxiliary Feedwater System,"

and system drawings 9321-F-20173, -20183, and -20193. The inspectors also observed

whether any material conditions were present that could challenge the operability of the

two operable AFW pumps.

The system lineup inspection included a review of accessible portions of the AFW system components, valve positioning, and verification of remote operating status lights

and indicating instrumentation. The inspectors reviewed the AFW system performance

report, open work requests (WRs), and deficiency/event reports (DERs) to assess any

outstanding equipment and/or component deficiencies.

b. Findings

No findings of significance were identified 31R05Fire Protection

a. Inspection Scope

(71111.05Q)

On July 24, 2001, the inspectors conducted tours of the plant to verify the availability and material condition of fire protection equipment in areas that contain vital equipment for

mitigating the consequences of events, and support equipment that is needed to operate

other equipment important to safety. During these tours, the inspectors observed: 1)

licensee control of transient combustibles and ignition sources; 2) the material condition, operational lineup and effectiveness of fire protection systems, equipment and features;

and 3) the material condition and operational status of fire barriers used to prevent fire

damage or fire propagation. The inspectors also examined the programmatic controls

for combustible and flammable material that applied to the following areas toured:*Central control room, *31, 32, and 33 component cooling water pumps

• 31, 32, and 33 charging pump rooms

• 31 and 32 residual heat removal (RHR) pump rooms

• 10 CFR 50, Appendix R diesel generator The inspectors observed minor discrepancies that were brought to the attention of the licensee for resolution (DER 01-03071).

b. Findings

No findings of significance were identified1R11Licensed Operator Requalification

a. Inspection Scope

(71111.11).On August 6, 2001, the inspectors observed the simulator portion of an annual license examination for Crew E. The test involved two simulator scenarios:*Uncontrolled depressurization of all steam generators*Loss of instrument air followed by a reactor coolant system leak The simulator portion of the annual examination was observed and evaluated by the assistant operations manager (AOM) and training evaluators. No performance

deficiencies were identified by the AOM. The inspector attended the post-examination

critique conducted by the AOM and the training evaluators and verified that minor

performance improvements had been identified and discussed with the operating crew.

The inspectors noted that the requalification simulator scenarios were based on a recent change (Revision 16) to emergency operating procedure E-0, "Reactor Trip/Safety

Injection," which incorporated a configuration change made to the essential service

water header in June 2001. That change altered the source of cooling water to the

circulating water pump (CWP) motors and seals from the non-essential to the essential

header (see report section 1R15) to allow the CWPs to remain operating after a valid 4 safety injection (SI) signal, and keep the main condenser available for a plant cooldown.

Prior to Revision 16, E-0 required operators to close all main steam isolation valves (MSIVs) following an SI signal, and to use the atmospheric dump valves (ADVs) for the

cooldown. However, this would be unnecessary after the configuration change because

the condenser would be available for decay heat removal.

During this inspection period, the operations department issued a temporary procedure change (TPC 01-0454) to E-0 after the NRC discovered that the change to the essential

header was inadequately analyzed (see NRC inspection report 50-286/01-03). Also, the

safety evaluation (01-03-019) for the change did not adequately address the

consequences of a design basis seismic event to the essential header, and the safety

evaluation had to be rescinded. The essential header was then returned to its

configuration prior to June 2001, and the TPC was written to reverse the changes made

by Revision 16, requiring operators to manually shut the MSIVs in response to an SI.

The licensee anticipated that the configuration change to the essential header would be properly analyzed so that the essential header could be restored as the cooling supply to

the CWPs. Since requalification training proceeded in the mean time using E-0 without

the TPC, the inspectors verified that all operating crews were properly briefed on the

configuration change after completing requalification training, and were knowledgeable

of the TPC prior to standing watch duties in the plant's control room.

b. Findings

No findings of significance were identified1R12Maintenance Rule Implementation

a. Inspection Scope

(71111.12)

The inspectors reviewed problems involving selected in-scope structures, systems, and components (SSCs) to assess the effectiveness of the licensee's maintenance program.

The review included a sample of operating logs, system engineer data, system reports, deficiency reports, availability data, selected surveillance performance data, and

selected maintenance-related data. The reviews focused on proper maintenance rule

scoping, proper classification of SSC equipment failures, safety significance

classifications, 10 CFR 50.65 (a)(1) and (a)(2) classifications, and performance criteria

for SSCs classified as (a)(2). The inspectors reviewed Entergy's scoping documents, deficiency/event reports (DERs), and completed work orders.

The inspectors also reviewed the periodic evaluations required by 10 CFR 50.65 (a)(3)for the Indian Point 3 (IP3) Station, to verify that SSCs within the scope of the

maintenance rule were included in the evaluations, and that balancing of reliability and

unavailability was given adequate consideration. The inspectors reviewed the below

indicated sample of IP3 periodic system evaluation reports, covering the period from

October 2000 through June 2001, to ensure that 1) goals, performance criteria, and

technical justifications were appropriate, 2) industry operating experience was

considered, 3) corrective action plans were effective, and 4) performance was being

monitored. The following systems composed the sample:

5*Service Water System*125 volt vital DC and 120 volt AC Power Systems

• 32 Emergency Diesel Generator (EDG)

• Fuel Storage Building Ventilation System

• Boric Acid Heat Trace Sub-System of the Chemical and Volume Control System*32 Battery Charger

b. Findings

No findings of significance were identified1R13Maintenance Risk Assessment and Emergent Work

a. Inspection Scope

(71111.13)

The inspectors reviewed the plant risk assessments and corrective maintenance work request (WR) packages for the listed planned and emergent work. The inspectors also

discussed cognizant personnel the deficient conditions, and subsequent revisions to the

daily plant risk profiles (i.e, changes to the nominal core damage frequency) resulting

from rescheduled maintenance): *WR 01-03177-00; Core exit thermocouple H5 failure and troubleshooting

• WR 01-01913-xx; Westinghouse type "W2" switch replacements WR 01-01913-00; 31 containment recirculation pump WR 01-01913-02; 31 containment spray pump

WR 01-01913-04; 32 containment recirculation fan cooler

WR 01-01913-05; 33 containment recirculation fan cooler

WR 01-01913-08; 31 safety injection pump

WR 01-01913-09; 32 safety injection pump

WR 01-01913-13; 32 component cooling water pump

WR 01-01913-14; 33 component cooling water pump

WR 01-01913-15; 31 residual heat removal pump*WR 01-00-03241-00; Packing replacement on the 34 SW pump (rescheduled due to failures on the 32 main transform er auxiliary system, a positive ground on 31 battery charger, and 31 static inverter card failure on July 24, 2001.*WR 99-04394-00; B-Reactor trip bypass breaker preventive maintenance (deferred due to emergency core cooling systems motor-operated valves out of

service for testing)

b. Findings

No findings of significance were identified1R14Personnel Performance During Non-Routine Plant Evolutions and Events

a. Inspection Scope

(71111.14)

Partial Loss of Offsite Power On July 6, 2001, the inspectors observed control room operators respond to an unexpected loss of the normal 13.8 kilo-volt (KV) feeder circuit (13W93) due to a circuit

breaker failure that occurred during switchyard relay testing.

The loss did not interrupt

power to the 6.9 KV buses in the plant, since the station auxiliary transformer and the

unit auxiliary transformers continued to supply these buses, and no safeguard loads

were affected. However, the event caused a loss of the condensate polisher facility and

resulted in a minor secondary plant transient. The licensee was not able to realign the

13.8 KV source to its alternate feed since the cause of the failure was not known, and

troubleshooting of the failure was necessary. The inspectors observed operator and

control room supervisor performance in coping with the event. The inspectors reviewed

operator logs, plant system data, and control room strip charts to determine the scope of

the transient, and how the operators responded. The inspectors determined that

operator response was in accordance with the response required by their procedures

and training and that the plant responded within its current design basis.

Loss of 32 Main Transformer Auxiliaries On July 24, 2001, one bank of the auxiliary coolers on the 32 main transformer was lost due to a failed thermal overload in a power circuit on a cooling fan. The failure disabled

all fans in the bank and transformer temperatures started to rise. During troubleshooting

of the failure, operations personnel monitored the transformer temperatures and other

plant equipment while engineering and maintenance performed troubleshooting and

repairs.Plant operators had questioned different limits for the maximum temperature allowed in the main transformer windings as documented in operator logs and the high temperature

alarm response procedure. The operations department requested engineering

assistance to identify the temperature at which operators would be required to take

actions (95C or 120C) to reduce plant load (DER 01-02990). Operations temporarily

imposed the 120C limit for plant operation, but the actual temperature did not exceed

95C. Design Electrical Engineering subsequently initiated Action Commitment Tracking

System (ACTS) item 01-57747 to resolve this question for the main transformers, and for the station auxiliary and unit auxiliary transformers.

The inspectors also noted that the control room operators had not discussed a contingency plan to reduce power or to shutdown the plant in the event that the

transformer auxiliaries were not recovered before the temperature exceeded the 120C

limit. The inspectors discussed this situation with the shift manager and the operations

manager. The operating crew was subsequently briefed on the possibility of a plant 7 power reduction; however, by mid morning on July 24, operation of the auxiliaries were restored, and transformer temperatures were stabilized.

b. Findings

No findings of significance were identified1R15Operability Evaluations

a. Inspection Scope

(71111.15)

The inspector reviewed various DERs on degraded or non-conforming conditions that raised questions about equipment operability. The inspector reviewed the resulting

operability determinations (ODs) for technical adequacy, whether or not continued

operability was warranted, and to what extent other existing degradations adversely

impacted the affected systems. The following DERs, operability determinations, and

calculations were evaluated:*DER 01-0128

Degraded Grid motor protection.*OD 01-0124

Cell Switches on 480 VAC Westinghouse DS breakers. Most of the cell switches in these breakers exceeded the manufacturers recommended

number of total cycles (200). The OD concluded that all cell switches remained

operable because the failure only occurred when the breaker was removed from

its cubicle. The licensee developed an action plan to replace the switches during

the normal preventive maintenance cycle for each affected breaker. *DER 01-1652

The inspectors reviewed the operability evaluation which reviewed a problem involving water collection in the 32 auxiliary boiler feed pump (ABFP)

steam supply piping. *DER 01-03130

The inspectors reviewed the operability evaluation for a condition identified by the inspectors involving the installation of TRICO oilers used in

several safety-related pumps. Additionally, the inspectors reviewed DER 99-

01239, which evaluated the June 1999 catastrophic failure of the 33 component

cooling water (CCW) pump inboard bearing.

The inspectors reviewed these issues to ensure that the identified conditions did not adversely affect system operability or plant safety, and to verify that corrective actions taken were adequate to prevent recurrence. The inspectors

interviewed the system engineers and maintenance technicians, performed field

walkdowns, visually inspected the oilers removed from the 32 CCW pump and

other safety related pumps, and reviewed procedure LUB-001-GEN, "Lubrication

of Plant Equipment," and applicable completed maintenance activities.*Essential Service Water Header Past Operability

During the Problem Identification & Resolution (PI&R) inspection at Indian Point 3, the inspectors

determined that a safety evaluation written for a modification to the service water (SW) system was inadequate and caused the plant to be operated outside its 8 design basis for approximately two months (see NRC inspection report 50-286/01-03). The modification aligned the essential SW header to the circulating

water system (CWS) pumps through non-seismic piping connected to the

essential header. The safety evaluation did not evaluate the consequences of a

seismic event on the non-seismically qualified piping. The licensee subsequently

realigned the essential header to isolate the non-seismic piping until further

analysis could be performed.

In order to evaluate the past operability of the essential SW header, the inspectors reviewed the licensee's Calculation No. IP3-CALC-SWS-03523, "Evaluation of 8" Seismic Class III Pipe Inside the Intake Structure." This

calculation concluded that the non-seismic piping to the CWS pumps would not

rupture, and the essential SW header could continue to supply all vital heat loads

following a design basis seismic event. The inspectors noted that the licensee

performed the analysis and calculation assuming nominal pipe wall thickness in

accordance with normal code requirements. However, during discussions with

the licensee, the inspectors noted that several sections of SW piping were known

to have wall thinning with some locations below the code allowable thickness.

The inspectors considered that some of the SW piping analyzed in calculation

IP3-CALC-SWS-03523 may be in question if wall thinning below nominal

thickness existed. The licensee subsequently inspected the 8" piping in question

and discovered a pinhole leak in an pipe elbow weld downstream from valve

SWN-4. The licensee performed non-destructive testing in the area of the defect

to characterize the extent of the wall thinning. The licensee then analyzed this

condition and generated calculation IP3-CALC-SWS-05324, "Wall Thinning

Evaluation for 8" SW Pipe in Intake Structure." The inspectors reviewed this

calculation to verify that the identified defect did not invalidate the seismic

calculation.

The inspectors also reviewed the plant operating logs for the two months prior to discovery of the inadequate safety evaluation. No instances were documented

where any service water pump associated with the essential SW header had

been taken out of service, or where the essential header was declared

inoperable for other reasons. The emergency diesel generators which would

have powered the SW pumps during an emergency had been removed from

service for normal surveillance testing during the two month period. However, during that testing, the minimum number of SW pumps required by technical

specifications remained operable on the essential header.

b. Findings

No findings of significance were identified.

91R17Permanent Plant Modifications

a. Inspection Scope

(71111.17)

The inspectors reviewed Engineering Change Notice (ECN) 97-3-320, "PCV-1139 Solenoid Valve Tubing Modification." PCV-1139 is the main steam admission control

valve to the turbine-driven auxiliary bo iler feed pump (TDABFP). The modification reduced the size of the tubing from 1/2" to 1/4" from pressure transmitter PT-1139 to

pressure controller PIC-1139, and from PIC-1139 to the valve positioner. This change

was necessary to improve the response time associated with the PCV-1139 control loop.

The inspectors reviewed the modification to verify that the design basis and performance

capability of the risk significant turbine-driven auxiliary boiler feed pump (TDABFP) had

not been degraded, and that the modification would not place the plant in an unsafe

condition. The inspectors reviewed this modification with cognizant engineering

personnel, evaluated the post-installation testing requirements, and performed a post-

installation walkdown of the control loop hardware for PCV-1139.

b. Findings

No findings of significance were identified1R19Post Maintenance Testing

a. Inspection Scope

(71111.19)

The inspectors reviewed post-maintenance test procedures and associated testing activities to assess whether 1) the effect of testing in the plant had been adequately

addressed by control room personnel, 2) testing was adequate for maintenance

performed, 3) acceptance criteria were clear and adequately demonstrated operational

readiness consistent with design and licensing documents, 4) test instrumentation had

current calibrations, range, and accuracy for the application, and 5) test equipment was

removed following testing. The inspectors performed system and control room

walkdowns, observed operators and technicians perform test evolutions, reviewed

system parameters, and interviewed the system engineers and field operators.

The following post-maintenance test activities were evaluated:*Stroke test failure of steam admission valve PCV-1139 on the 32 ABFP (DER 01-02813)*Westinghouse W2 switch replacements on multiple plant components (WR 01-1913-00).

b. Findings

No findings of significance were identified 101R22Surveillance Testing

a. Inspection Scope

(71111.22)

The inspector reviewed surveillance test procedures and associated testing activities to assess whether 1) the test preconditioned the component(s) tested, 2) the effect of

testing was adequately addressed in the control room, 3) the acceptance criteria

demonstrated operational readiness consistent with design calculations and licensing

documents, 4) the test equipment range and accuracy was adequate with proper

calibration, 5) the test was performed in the proper sequence, and 6) the test equipment

was removed following testing.

The inspectors reviewed a sample of the periodic surveillance activities performed by Indian Point 3 Station, to verify that structures, systems and components (SSCs) were

reliable, available and/or operable. The following surveillances composed the sample:*3PT-M62, 480V Undervoltage/Degraded Grid Protection System Functional*3PT-Q092C, Service Water System Pump Train Operational Test

• 3PT-M033, Fuel Storage Building Ventilation System Functional Test

• 3PT-R32A, Fuel Storage Building Ventilation Differential Pressure Test

• 3PT-M079B, 32 EDG Functional Test

• 3PT-Q120C, "33 ABFP [Motor-Driven] Su rveillance and IST Monthly Operability Surveillance"*3PT-M79C, 33 EDG Functional Test During the test of the 33 EDG, the inspector noted that operators recorded the time for the EDG to achieve its minimum output voltage (10.66 seconds) and minimum frequency

(10.44 seconds) were both greater than the allowed acceptance criteria (10.0 seconds).

Operators continued to run the engine for approximately one hour despite a note in the

test procedure which stated that the minimum start time must be achieved in order to

declare the test satisfactory for technical specifications surveillance requirements.

Following the test, the EDG remained inoperable due to the apparently slow start (DER

01-02872), and the licensee's investigation determined that operators had used an

incorrect method for timing the minimum voltage and frequency.

Consequently, the

engine was started a second time, and both minimum voltage and frequency were

achieved within the required ten seconds using the correct methodology.

The inspector reviewed administrative procedure AP-19, "Surveillance Test Program,"

and discussed with operations and engineering personnel two conflicting requirements

contained in the procedure related to continuing or aborting a test of safety-related

equipment with out-of-specification conditions. The licensee also noted that AP-4, "Procedure Use and Adherence," contained guidance indicating that stopping a

surveillance tests with an out-of-specification condition was an example for stopping an

activity prior to completion. The licensee subsequently generated ACTS Item 01-57603

to evaluate the conflicting guidance and to develop consistent expectations to clarify

who and when it would be appropriate to abort a surveillance test with an out-of-

specification condition.

b. Findings

11 No findings of significance were identified.

1R23 Temporary Plant Modifications

a. Inspection Scope

(71111.23A)

The inspectors reviewed the licensee's administrative procedure AP-13, "Temporary Modifications," and packages for selected temporary modifications (TMs).

The inspectors reviewed packages and engineering evaluations for four contingency TMs. These TMs were used to support maintenance/replacement of Degraded Grid

Relays, and would install a jumper to maintain circuit continuity for the negative side of

the control power circuitry. The inspectors also evaluated the licensee's administrative

requirements and testing requirements associated with each TM.

TM 00-03002-25 , "Install Jumper to Maintain Continuity of Negative & Positive Side of DC Power Feed (Relay 62-2/5A Replacement)." TM 00-03002-26 , "Install Jumper to Maintain Continuity of Negative & Positive Side of DC Power Feed (Relay 62-2/2A Replacement)." TM 00-03002-27 , "Install Jumper to Maintain Continuity of Negative & Positive Side of DC Power Feed (Relay 62-2/3A Replacement)." TM 00-03002-28 , "Install Jumper to Maintain Continuity of Negative & Positive Side of DC Power Feed (Relay 62-2/6A Replacement)."

b. Findings

No findings of significance were identified.3.SAFEGUARDSCornerstone: Physical Protection3PP1Response to Contingency Events

a. Inspection Scope

(71130.03)

The following activities were conducted to determine the effectiveness of the licensee's Response to Contingency Events:

Beginning on July 23, 2001, a review was conducted of the licensee's defensive strategy, response time lines, target sets, contingency drill scenarios and relevant

implementing procedures. Upon completion of this review, on July 25, 2001, four table-

top drills (a simulated contingency response drill using a facility model) were conducted

with security shift supervisors and response team leaders. The table-top drills were

used to evaluate the licensee's capability to protect against the design basis threat.

12 A performance test of the licensee's Intrusion Detection System (IDS) was conducted on July 24, 2001.

A review of documentation associated with the licensee's drill and exercise program was conducted on July 26, 2001. This review included the documentation and critiques for

contingency response drills conducted in the prior four quarters.

b. Findings

1.The licensee's submittal of Revision 20, to the Physical Security Plan dated March 26, 2001, did not meet the requirements of 10 CFR 50.54(p)(2), which permits only changes

that do not decrease the effectiveness of the plan. The change made was to permit the

use of a non-picture badge for unescorted site access. This is contrary to 10 CFR

73.55(d)(4), which requires a picture badge to be used for all individuals authorized

unescorted access. This finding is considered a non-cited violation of 10 CFR 50.54 (p)(2). This issue is more than minor in that, if left uncorrected, the same issue could become a more significant safety concern. Specifically, the proposed submittal would reduce the

overall effectiveness of the program by allowing non-photo identification to be issued.

The issue affects the Physical Protection Cornerstone since it involved non-conformance

with a safeguards requirement related to Security Plans. This violation of 10 CFR

50.54(p)(2) is being treated as a Non-Cited Violation (NCV), consistent with Section VI.A.1 of the Enforcement Policy, issued May 1, 2000 (65FR25368). (NCV 50-286/01-07-01)

Applying the Physical Protection Significance Determination Process, the issue involved a potential vulnerability in access control. Notwithstanding, there was no malevolent act

and no actual intrusion occurred; and there have not been greater than two similar

findings in the past four quarters. Accordingly, this finding was considered to have very

low safety significance (Green).

Upon identification, the use of non-photo identification badges was terminated, and this issue was entered into the Indian Point 3 problem identification and corrective action

system as DER 01-03011.

2.During the conduct of the inspection, issues associated with contingency response equipment were identified. 10 CFR 73.55(b)(4)(i) requires response personnel to be

equipped in accordance with Appendix B to Part 73. However, response personnel were

not equipped as required relative to the number of rounds of ammunition immediately

available, and non-lethal weapons. Accordingly, the licensee did not fully conform to the

Requirements of 10 CFR 73, Appendix B, paragraphs V.A.4(a)(3), and V.A.5.8. The

vulnerability was detected through a table-top drill, and consequently is not considered a

violation of NRC requirements. This issue was of very low safety significance (Green)

because, although it indicated vulnerabilities in the safeguards program, no actual

intrusion occurred, and there have not been greater than two similar findings in the past

four quarters.

13 Upon identification, the licensee initiated action to review the condition and entered this issue into the Indian Point 3 problem identification and corrective action system as DER 01-03012 (FIN 50-286/01-07-02)

OTHER ACTIVITIES (OA)

==4OA1 Performance Indicator Verification

a. Inspection Scope

==

Emergency AC Power (Emergency Diesel Generators) System Unavailability and Auxiliary Feedwater Safety System Unavailability The inspectors reviewed the performance indicators for the emergency diesel generators (EDGs) and the auxiliary feedwater (AFW) syst ems. The inspectors verified accuracy of the reported data through reviews of performance indicators for the time period from

April, 2001 to July, 2001 against the applicable criteria specified in Nuclear Energy

Institute (NEI) 99-02, Regulatory Assessment Performance Indicator Guideline, Revision

1, to verify that all conditions that met the NEI criteria were recognized and identified as

performance indicators. The reviewed records included corrective action program

records, control room operators logs, and PI data summary reports.

b. Findings

No findings of significance were identified4OA2Identification and Resolution of Problems

a. Inspection Scope

(71111.12Q, 71111.22)

The inspectors reviewed the Indian Point 3 problem identification and resolution program related to selected plant equipment conditions and surveillances. The review was

conducted to verify that the licensee identified issues at the proper threshold and

entered them into its corrective action program, and to evaluate the adequacy of the

resultant corrective actions. The following inspectors reviewed the following DERs and

OD related to the maintenance rule process and surveillance performance samples

chosen for this inspection: *DER 01-00024, EDG Air Start Motor Failure*DER 01-00103, EDG Battery Charger Alarm

• DER 01-00688, Spent Fuel Pool

• DER 01-01064, Spent Fuel Pool Surveillance

• DER 01-02923, Spent Fuel Pool Charcoal Filters

• DER 01-02967, 31 Inverter Transferred Automatically Onto Its Backup Supply

• OD 01-0128, Motor Performance with Degraded Grid Calculations

b. Findings

No findings of significance were identified 144OA4Licensee Event Report Reviews

a. Inspection Scope

(Closed) LER 1997-021-01

One Train of Engineered Safeguards Equipment Out of Service The inspectors performed an in-office review of this LER Supplement. The Supplement was an update of a historical event reported to the NRC in October 1997. The corrective

actions were entered into the Indian Point 3 corrective action system, and the stated

corrective actions appeared to be adequate. This issue was previously addressed in a

NRC Inspection Report 50-286/97-11. This LER is closed

b. Findings

No findings of significance were identified4OA6Meetings

Exit Meeting Summary

The physical protection inspectors met with licensee representatives at the conclusion of the inspection on July 26, 2001. At that time, the purpose and scope of the inspection

were reviewed, and the preliminary findings were presented. The licensee

acknowledged the preliminary inspection findings.

On September 10, 2001, the inspectors presented the inspection results to Mr. R. Barrett and other Entergy staff members who acknowledged the inspection results presented.

The inspector asked Entergy personnel whether any materials evaluated during the

inspection were considered proprietary. No proprietary information was identified.

15 ATTACHMENT 1

SUPPLEMENTAL INFORMATION

a.Key Points of Contact

P. AsendorfSecurity ManagerJ. Barnes Acting Director, IP-3 Engineering

R. BarrettVice President, Operations - IP3

T. BarrySecurity General Supervisor

R. BurroniI&C Manager

R. CavaleriOutage and Planning Manager

J. ComiotesDirector, Safety Assurance

F. DacimoWhite Plains Administration

J. DonnellyLicensing Manager

J. DeRoyGeneral Manager of Plant Operations

R. DeschampsRadiological and Environmental Services Manager

C. GorgesOperations Shift Manager

P. GrossgoldFederal Bureau of Investigation

D. MayerHealth Physics/Chemistry Manager

L. OlivierSenior Vice President, Indian Point 3

J. PerrottaQuality Assurance Manager

K. PetersCorrective Actions/Assessment Manager

P. RubinOperations Manager

J. Russell Special Projects Manager

A. SmallOperations Shift Manager

A. VitaleMaintenance Manager

T. WeirDirector, Corporate Security

J. WheelerTraining Managerb.List of Items Opened, Closed, and Discussed

Opened and ClosedLER 1997-021-01One Train of Engineered Safeguards Equipment Out-of-

ServiceNCV 50-286/01-07-01Security Plan Revision not in accordance with 10 CFR 50.54 (p)(2)FIN 50-286/01-07-02Licensee's response equipment did not fully conform to the

requirements of 10 CFR 73, Appendix B, V.A.4(a)(3), and

V.A.5.8.

16c.List of AcronymsABFPauxiliary boiler feed pumpACTSAction Commitment Tracking System

ADVatmospheric dump valve

AFWauxiliary feedwater

AOMAssistant Operations Manager

ARPalarm response procedure

Cdegrees Centigrade

CCWcomponent cooling water

CFRCode of Federal Regulations

COLcheckoff list

CScontainment spray

CWPcirculating water pump

DERDeviation/Event Report

ECNengineering change notice

EDGemergency diesel generator

EOPemergency operating procedure

Fdegrees Fahrenheit

IDSintrusion detection system

IRinspection report

ISTin-service test

KVkilo-volts

LERLicensee Event Report

MSIVmain steam isolation valve

NCVNon-Cited Violation

NEINuclear Energy Institute

NRCNuclear Regulatory Commission

ODoperability determination

ODoperations directive

OEoperating experience

PIperformance indicator

PI&Rproblem identification and resolution

RHRresidual heat removal

SDPSignificance Determination Process

SSCsstructures, systems and components

SWservice water

TDABFPturbine-driven auxiliary boiler feed pump

TMtemporary modification

TPCtemporary procedure change

VACvoltage-alternating current

WRwork request