ML20149K888

Insp Rept 50-298/97-06 on 970518-0628.Violations Noted.Major Areas Inspected:Operations,Maint,Engineering & Plant Support

ML20149K888
Person / Time
Site:	Cooper
Issue date:	07/25/1997
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV)
To:
Shared Package
ML20149K879	List: ML20149K876 ML20149K881 ML20149K888
References
50-298-97-06, 50-298-97-6, NUDOCS 9707300215
Download: ML20149K888 (23)

See also: IR 05000298/1997006

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EtLCLOSURE 2 l

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U.S. NUCLEAR REGULATORY COMMISSION

REGION IV  ;

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Docket No.. 50-298

License No.: DPR 46

Report No.: 50-298/97-06

Licensee. Nebraska Public Power District

Facility: Cooper Nuclear Station

Location: P.O. Box 98

Brownville, Nebraska

Dates: May 18 through June 28,1997

Inspectors: Mary Miller, Senior Resident inspector

Chris Skinner, Resident inspector

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Anthony T. Gody, Senior Resident inspector

Tom Meadows, Reactor Inspector

Steve Burton, Resident inspector, Arkansas Nuclear One

Approved By: Elmo Collins, Chief, Project Branch C

Attachment: Supplemental Information ,

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MS730021597o72s

G ADOCK 0500o298

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EXECUTIVE SUMMARY

Cooper Nuclear Station

NRC Inspection Report 50-298/97-06

_Qoerations

• The inspector identified that the licensee approved ar instant non-intent procedure

change that moved the initial jet pump operability detendnation to af ter the mode

switch was placed in the startup position contrary to plant Tachr; cal Specifications.

Plant management demonstrated a lack of understanding of Technical Specification

requirements (Section 01.2).

• The licensee found increasing unidentified leakage in containment and took

conservative action to reduce power to fix the leak, well below the Technical

Specifications limits. The licensee promptly reduced the allowed leakage rate when

bypass flow to the torus was observed. The licensee requested and was granted

enforcement discretion from Technical Specifications for high primary containment

oxygen concentration, inspectors concluded that procedures for inerting the primary

containment were inappropriate in that they did not use the 24-inch valves. This is

a violation (Section 01.3).

• The immediate control room crew response to a reactor recirculation pump lockout

was appropriate. The inspectors found that the licensee did not document crew

briefings and the immediate compensatory action for a feed pump trip

(Section 01.4).

• The inspector identified a lack of procedures requiring corrective lenses appropriate

for self-contained breathing apparatus (SCBAs) use by licensed operators.

Nevertheless, the licensee identified that all licensed operators had the proper

corrective lenses (Section 03.1).

• The inspector found that the licensee did not implement turnover checklists which

listed critical parameters and specific components. Turnover checklists to verify

that safety components are properly aligned are required by NUREG-0578. The

licensee initiated switch checks and control board walkdowns. This item is

unresolved (Section 03.2).

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Maintenance

• Instrument and control technicians performed jet pump flow calibration in

accordance with approved procedures. Technicians demonstrated good selt-

checking and communications techniques during the evolution. Additionally,

technicians exercised proper control for trainees while properly conducting on the

job training (Section M1.3).

• The inspectors identified a potential weakness in that the surveillance procedure for l

automatic depressurization valve accumulator function did not provide appropriate )

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nonconservative time tracking. The licensee agreed to revise the procedure to

include better guidance (Section M1.4).

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• The licensee did not have clear ownership, or a process in olace to control plant

regulator settings and setpoints, resulting in reactive response to undesirable system

pressures during startup activities. Ownership of the plant regulator settings was

ambiguous (Section M4.1).

Enaineerina

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• Reactor engineering demonstrated a questioning attitude in identifying a lack of

documentation and understanding regarding the basis for rod groups. No procedure

documented reactor engineering expectations (Section E1.1).

Plant Supp.qtt

• The licensee demonstrated weak ownership in maintaining the material condition of

the alternate Operations Support Center ventilation status panel and system ,

walkdowns and rounds of ernergency response f acilities (Section P2.1). )

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• Inspectors identified that, during emergency drills, emergency planning did not verify

that emergency responders had proper lenses for SCBA use (Section 03.1).

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fleoort Details

i Summarv of Plant Status

The unit began this inspection period in the shutdown condition at the end of Refueling

Outage 17. During this inspection period, the licensee started up the plant and ran at

100 per :ent power until leakage was identified in the drywell. On June 14,1997, the

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licensee decreased power to 10 percent, entered the drywell, and repaired a feedwater

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! vent line leak. The licensee then returned the unit to 100 percent power, which was

maintained through the end of this inspection period.

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O1 Conduct of Operations

01.1 C,inaeIai Comments (71707)

l The inspectors conducted frequent reviews of ongoing plant operations both at i

power and during a routine refueling outage. In particular, the inspectors observed a

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routine plant startup following the seventeenth refueling outage. With few I

exceptions, plant operations were conducted in accordance with licensee

procedures, Technical Specifications, and the design bases. Noteworthy j

observations are discussed below. i

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01.2 Routine Startuo

a. insoection Scoce (71707)

The licensee performed a routine startup following the seventeenth refueling outage.

In preparation, the inspectors reviewed licensee Procedure 2.1.1, "Startup

Procedure," and other relevant system and operations procedures to determine if

they properly implemented Technical Specification requirements. The inspectors

observed the conduct of operations and management oversight throughout the plant

startup.

b. Observations and Findinas

The inspectors attended the shift briefing conducted by licensee management prior

to the reactor startup and noted that it appropriately contained discussions about

reactivity management, thoughtful deliberate conduct of operations,

communications, approach of evolutions with a questioning attitude, and teamwork.

1 Consistent with observations in previous inspection reports, operators demonstrated

clear three-way communications; good attentiver ess to the control boards; and

slow, controlled, and deliberate equipment manir>ulations in accordance with the

startup procedure.

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j The inspector observed that the licensca had difficult / obtaining good data for the

i daily jet pump operability check as required by Technical Specification 3.6.E. The

licensee indicated that new software installed during the efueling outage did not

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recognize that the Loop B recirculation pump was runnino The venoor-supplied

sof tware package utilized def ault recirculation pump amperage threshold values, to )

determine if a recirculation pump was running, that wm higher than the actual

Loop B pump amperage. Therefore, it did not recognize that both recirculation

pumps were running. The jet pumps could not be declared operable until jet pump l

integrity could be verified. l

While the problem with obtaining valid jet pump operability data was being

addressed, the shif t supervisor approved an " instant, non-intent" change to the

startup procedure that moved the daily verification of jet pump operability

requirement from Step 8.1.37 to Step 8.2.13. The inspector noted that the startup

procedure required operators to complete a review of Section 8.1 prior to beginning

Section 8.2, Recognizing that the daily jet pump operability check was required to l

be performed prior to placing the mode switch to the "startup/ hot-standby" position l

by Technical Specifications 1.0.J, the inspector immediately questioned the l

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operations manager, who was present observing the reactor startup, about the

appropriateness of the non-intent procedure change. The procedure, if implemented

as changed, would have resulted in a violation of plant Technical

Specification 1.0.J, which states, in part, that entry into an operational condition or

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other specified condition shall not be made when the conditions for this Limiting

Condition for Operation are not met, and the associated action requires a shutdown

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if they are not met within a specified time interval. Technical Specification 3.6.E.

requires a plant shutdown if jet pumps are not made operable within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. The

Operations Manager pointed out the Technical Specifications definition of

• " Surveillance Interval" which stated, "Tiie surveillance interval is the calendar time

between surveillance tests, checks, calibrations and examinations to be performed

upon an instrument or component when it is required to be operable. These tests

may be waived when the instrument, component or system is not required to be

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operable, but the instrument, component or system shall be tested prior to being

declared operable or as practicable following its return to service." The operations

manager indicated that, since the jet pumps were not required to be operable in the

shutdown mode, the daily jet pump operability test could be deferred until it was

practicable. The inspector informed that operation's manager that this interpretation

4 of Technical Specifications did not appear appropriate. Nevertheless, by the end of

the discussion with the operations manager, the inspector noted that the daily jet

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pump operability check had been run and the mode switch had been placed in the

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"startup/ hot-standby" position.

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Following the discussion with the operations manager, the inspector reviewed

Procedure 2.1.1 and found that the daily jet pump operability test in Step 8.2.13

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was documented as being completed 2 minutes after the mode switch had been

placed in the "startup/ hot-standby" position. When questioned, the licensee

indicated that this was an administrative error and that the jet pump operability test

had been performed prior to the mode switch being placed in the startup position.

The inspector reminded the licensee of the importance of maintaining accurate

records that document Technical Specification surveillances.

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The inspector determined that these findings were significant for several reasons:

(1) the instant, non-intent procedure change required operators to place the mode

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switch in the "startup/ hot-standby" position prior to performing the daily jet pump

operability check contrary to plant Technical Specifications, (2) licensee

management did not recognize that the jet pump operability was required to be i

verified prior to changing modes, and (3) had the procedure change been subject to  ;

a 10 CFR 50.59 screening,it should not have been allowed because it involved a

> procedure change affecting plant Technical Specifications. The instant, non-intent

procedure change was determined to be inappropriate. This is a violation of 10 CFR

Part 50, Appendix B, Criterion V (Violation 50/298-97006-01).

c. Conclusions

Other than the inspector identified violation, the startup was conducted well and in

accordance with procedures. The instant, non-intent procedure change which  !

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moved the initial jet pump operability determination to af ter the mode change was

inappropriate, because it resulted in not meeting plant Technical Specifications.

Licensee management failed to implement the Technical Specification requirements

properly. 1

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01.3 Correction of Leakaae in Containment Reauirina Notice of Enforcement Discretion

(EA 97-322)

a. Insoection Scooe (93702)

The inspectors reviewed the licensee's actions during the evaluation and correction

of increased unidentified drywell leakage. The inspectors attended the licensee's

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meetings on this subject, participated in the Notice of Enforcement

Discretion (NOED) process, and held discussions with the licensee's management

and staff.

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b. Observations and Findings

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On June 14,1997, the licensee requested enforcement discretion from Technical

! Specification 3.7.A.5. for a period of 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> from June 14,9:29 p.m. through

June 15,9:29 p.m. Technical Specification 3.7.A.5 involves maintaining the l

oxygen concentration levelin the primary containment less than 4 percent and

requires a plant shutdown if the oxygen concentration becomes greater than

4 percent.

On June 5, the licensee concluded that unidentified leakage in the drywell was

0.317 gallons per minute (gpm) and increasing, but was below the Tcchnical

Specification 3.6.C. limit of 5 gpm. On June 10, the licenser utili7ed cameras

installed in primary containment to identify that a portion of f he leakage was

bypassing the sump by traveling along the outside of a relief vcuve tailpipe

downcomer into the torus. As a result, some of the leakage was not being

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accounted for in the unidentified leakage rate. The licensee implemented a 2.5 gpm

unidentified leakage rate limit to account for this bypass flow. The inspectors

considered this limit appropriate and conservative.

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in a June 13 teleconference with the NRC, the licensee discussed plans to mak3 the

necessary repair and the possibility of a need to request enforcement discretion.

During the teleconference, the licensee stated that emergency procedures were in

place to quickly reinert primary containment. The licensee later determined this

statement to be incorrect. Although an emergency system for maintaining the

nitrogen level in primary containment was installed, this system (standby nitrogen

i injection) was not designed to be capable of reinerting from high oxygen levels.

On June 13, the licensee decreased power and deinerted. Oxygen concentration

rose above 4 percent by 9:29 pm. At that time the unidentified leakage rate

l measured by the drywell sump was 0.417 gpm. On June 14, the licensee made an

l entry into primary containment at 11 percent power and determined that the source

i of the leakage was through the valve seats of Reactor Feedwater Line A Vent

Valves RF-V-740 and -741. The vent line terminated with a quick disconnect fitting

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as depicted on controlled drawings, versus a plug or cap Maintenance technicians

! removed the quick disconnect fitting and installed a plug which stopped the leakage.

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To ensure against leakage on counterpart valves on Reactor Feedwater Line B, a

! plug was installed in the Line B vent, although no leakage was identified from that )

i location. The licensee stated that these valves have a history of seat bypass

l leakage.

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. At 9:05 a.m., on June 14, the primary containment inerting process began with the

i torus. At 9:18 a.m.,1 of the 12 drywell-to-torus vacuum breakers opened for l

7 minutes because of excessive purge rates while inerting. This was considered an '

unplanned engineered safety feature actuation and was appropriately reported tn the

NRC. Because of the difference in capacity between the 24-inch purge (supply) and

- the 2-inch bypass (vent) piping, operators had been tasked to closely watch the

purge rate in order to avoid opening the drywell-to torus vacuum breakers. The

i licensee's immediate corrective actions appeared appropriate.

- On June 14, the licensee and the NRC held a second teleconference, in which the

licensee asked for enforcement discretion from Technical Specification 3.7.A.5 for

j 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, in addition to the 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> time limit of the Technical Specification, to

extend the time allowed for operating the plant with oxygen concentration greater

than 4 percent. NOED 97-4-001 was verbally granted and a letter to the licensee

was issued on June 18. The licensee's submittal, dated June 14,1997, addressing

the low safety significance of this operational condition, discussed the f act that the

NRC had reviewed improved Techn'. cal Specifications and approved operation below

15 percent power with primary containment oxygen concentration greater than

! 4 percent for an irlefinite period. The !etter stated, "while the enforcement

discretion is in eltect, or until primary containment oxygen concentration is brought

to less than 4 percent, the District will maintain reactor thermal power less than

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$ 15 percent." At the time of the teleconference when the NOED was verbally i

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approved, reactor power was 18 percent and was not reduced to less than

15 percent until 2:12 p.m. Although plant Technical Specifications did not require

reactor power to be less than 15 percent, the licensee's letter stated that they

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would maintain reactor power less than 15 percent when oxygen concentration was I

greater than 4 percent. The inspectors questioned the licensee about their decision I

to allow reactor power to remain above 15 percent several hours after the staff )

approved the NOED. The licensee indicated that they intended to reduce reactor

power to less than 15 percent before implementing the NOED and agreed to be i

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more clear in their communications with the NRC, particularly when it involved a l

regulatory decision.

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The re inerting process, using the 2 inch vent pipe, reduced the torus oxygen i

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concentration from about 25 to 19 percent over a 5-hour period. At 2:22 p.m., a l

1 procedure change was approved that allowed the operators to use the 24-inch vent.

Using the 24 inch vent, the oxygen dilution rate was significantly increased and

a torus oxygen concentration was reduced from about 19 to 4 percent over a 4.5-hour

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period. At 11:59 p.m., the oxygen concentration within primary containment (torus

1 and drywell) was less than 4 percent and the Technical Specification was exited. i

i The licensee indicated that, md the 24-inch vent been approved before beginning

the re inerting process, primary containment would have been capable of being re-

inerted prior to the expiration of the Technical Specification Limiting Condition of l

Operation at 9:29 p.m. on June 14, making implementation of the NOED

I unnecessary. The inspectors reviewed the primary containment oxygen

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concentration data and concluded that the licensee was correct.

The failure to have a reviewed and approved procedure for using the 24-inch vent

during re-inerting appeared to result in not being able to re-inert the primary

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containment prior to the expiration of the Technical Specification Limiting Condition

of Operation. The inspector also noted that, had the 24-inch vent been available,

the engineered safety features actuation would most likely not have occurred.

Therefore, the re-inerting procedure was not appropriate for the operating

! circumstances and is a second example of a violation of 10 CFR Part 50,

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Appendix B, Criterion V (Violation 50-298/97006-01)(EA 97-322).

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c. Conclusions

The licensee found increasing unidentified leakage in containment, and took

conservative action to reduce power to fix the leak and deinert the primary

containment, well below the Technical Specification leakage limits. The installation i

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and use of cameras inside primary containment was considered a strength. The

licensee requested and was granted enforcement discretion from Technical

Specifications for high primary containment oxygen concentration. In accordance

t with the NRC policy on NOEDs, the inspectors reviewed all the circumstances i

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surrounding the need for an NOED and found the reinerting procedure to be

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inadequate. The inadequate procedure also appeared to contribute to an unplanned

engineered safety feature actuation during the initial phases of reinerting.

01.4 Lack of Documentation of Sianificant Activities and Immediate Comoensatorv Action

Instructions

a. [.asoection Scone (71707)

The inspector reviewed documentation and compensatory actions associated with a

lock-out of a reactor recirculation pump speed controller.

b. Observations and Findinas

On June 25,1997, at approximately 2:30 a.m., a lock-out of the Reactor

Recirculation Motor Generator B Set speed controller occurred. When the inspector

was notified by telephone at 3 a.m., the inspector questioned if the operations crew

had evaluated their response to a feedwater pump trip with the recirculation motor

generator set in locked-out configuration. The inspector noted that this scenario

could result in an automatic runback of one recirculation pump, but no change in the

speed of the locked out recirculation pump. The resulting reactor power and flow

would place reactor operations in or near the instability zone. When the inspector

arrived in the control room at 5 a.m., the shif t supervisor noted that the shif t crew

had been instructed to trip the reactor if a feed pump trip were to occur to avoid

operation in the instability zone. The inspector noted that neither these

compensatory actions to trip the plant, nor the crew briefings, had been 1

documented in the control room logs or in other documentation. The crew was ]

knowledgeable of the compensatory actions.

The inspector observed the crew turnover which provided verbalinstruction to the

oncoming crew, of the configuration of the locked-out recirculation pump, and the

need to trip the plant if a feedwater pump trip were to occur. The inspector noted

that no additional documentation of this compensatory action or the crew briefing

had occurred and raised the concern of lack of documentation to licensee

management. About 10 a.m., the licensee put a night order in place requiring that

the reactor be tripped immediately if a single feed pump trip were to occur, in order

to avoid operation in the instability zone. A procedure change was also made to

incorporate the compensatory actions.

Quality Assurance Emergency Surveillance E103 9701, dated July 1,1997, noted

that operations response actions were in accordance with approved procedures, and

appropriate abnormal and operations procedures were implemented and

documented. Quality Assurance concluded that the compensatory actions and

surveys were conservative and appropriate, but also noted that no log entries or

night orders were put in place regarding immediate compensatory actions or

briefings until later.

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c. Conclusions

The immediate control room crew response to a reactor recirculation pump lockout

of briefing crew members addressed relevant contingencies. Inspectors identified

that the licensee's documentation of the crew briefings and the immediate

compensatory actions for a feed pump trip was not timely.

O2 Operational Status of Facilities and Equipment

02.1 Shif t Communicator Procedure Not Prooeriv Imolemented for Nonemeraency Reoorts

a. Inspection Scooe (71707)

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The inspectors compared plant operations shif t crew procedures with observed

practices.

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b. Observations and Findings

On June 6,1997, during a review of operations shif t crew procedures, inspectors

noted that Procedure 2.0.5, Revision 14, " Reports to NRC Operations Center,"

stated in Step 8.1 that the shif t communicator would communicate 10 CFR 50.72

reports to the NRC Headquarters Operations Center, inspectors noted that more i

than 8 of the 50.72 reports received in the past 2 years were performed by either l

! the Shift Supervisor or the Shift Technical Advisor. When questioned by the

inspectors, the licensee stated that the shif t communicator duties were assigned in

' accordance with administrative instruction operations department expectations I

dated March 24,1997, Attachment U, which stated that the shift communicator

will be the reactor building station operator for all events except for fires. The

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licensee revised Procedure 2.0.5 on June 26,1997, to reflect the option that other

members of the shift crew could inform the NRC of 10 CFR 50.72 reports.

- c. Conclusions

The inspectors identified an inconsistent implementation of procedures governing

licensee management expectations in that operations procedures and instructions l

designated a different crew position for communicating NRC nonemergency reports

than the shif t technical advisor and shift supervisor, who had routinely performed

the notification. The inspector concluded that the practice of not following

procedures, in this case, procedures implementing expectations, was an example of

a potential program weakness. The licensee took immediete actions to correct the

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procedure problem and re-emphasized the management expectation that procedures

be followed or corrected.

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O3 Operations Procedures and Documentation

03.1 Failure to Reauire Corrective Lenses Acorooriate for SCBA Use

a. Insoection Scooe (71707)

The inspector reviewed program controls regarding the plant staff having proper

corrective lenses for use with SC8As.

b. Observations and Findinos

On June 23,1997, the inspector asked the licensee if corrective lenses designed for

use with SCBAs were available for personnel reouiring corrective lenses. The

inspector noted that no procedural controls for SCBA corrective lenses were in

place. The licensee indicated that the operations training program placed heavy ,

emphasis on operators obtaining proper corrective lenses for use with SCBAs, and l

procedural controls were most likely not necessary to have an effective program.

On June 27, the licensee stated that they would verify that licensed operators had

corrective lenses for use with SCBAs. On June 30, the licensee identified that an j

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auxiliary operator did not own corrective lenses appropriate for SCBA use. No

problem identification report was initiated to document this finding. After

discussions with inspectors concerning the lack of a program for this concern, the

licensee issued Pr/olem Identification Report CAQ 97-1235. On July 1, the licensee j

had checked r.c, ep:: rations crews and found that those licensed operators had 1

appropriate SCBA lenses. The licensee stated that no licensed operator would l

assume watch without required corrective lenses appropriate for use with SCBAs.

On July 11, the licensee confirmed the only operations staff member found without

proper lenses was the individual noted on June 30.

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During a licensee emergency drill, the inspectors noted that corrective lenses

appropriate for SCBA use by emergency responders were not verified. The licensee  ;

agreed to address that issue as part of their problem identification report,

c. Conclusions

The inspector identified that no procedures were ir, place to require corrective lenses

appropriate for SCBA used by licensed operators or for those individuals such as J

auxiliary operators or emergency responders. Nevertheless, the licensee's )

instructions and qualifications for operators was successfulin assuring that '

corrective lenses were available, as evidenced by the fact that alllicensed operators

had lenses available. l

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03.2 Failure to Provide Ooerations Checklist for Comoonent Verification for Shift

Turnoyar_s

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a. inspection Scoce (71707)

The inspectors reviewed the licensee's implementation of the operations shif t I

turnover checklist described by NUREG-0578, "TMI-2 Lessons Learned Task Force j

Report."

b. Qhsgry.ations and Findinos

On January 2,1980, the NRC issued a "show cause" order which required the

licensee to provide control room turnover checklists as described in NUREG-0578,

"TMI-2 Lessons Learned Task Force Status Report and Short Term

Recommendations." NUREG-0578 indicated that these checklists were for use by

operators at turnover to verify safety components were properly aligned and critical

parameters were properly checked. On January 11,1980, the licensee stated that

these checklists would be implemented, in April of 1980, the licensee indicated that

they had implemented checklists for review of specific component alignment during

turnovers.

The inspectors found that the turnover checklists did not list the critical parameters j

or specific plant components to check in the control room, which was inconsistent i

with the requirements described in NUREG 0578. In response to th.s concern, on

June 2,1997, the licensee initiated a night order requiring switch checks and

control board walkdowns early in each shift. In addition, the licensee initiated

actions to develop shift turnover checklists in accordance with the subject order and

NUREG-0578.

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The inspectors planned to review both the enforcement aspects of this issue and the

licensee's corrective actions as the resolution of an unresolved item. (Unresolved )

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item 50-298/97006 02).

c. C.onclusions

The inspector identified that the licensee did not implement checklists to verify i

control room indications during turnovers as described in NUREG-0578.

08 Miscellaneous Operations issues (92901)

08.1 (Closed) Violation 50-298/96007-02: The inspector reviewed the licensee's

response letter, NLS960136, dated July 22,1996, and related condition reports i

regarding a violation of 10 CFR Part 50, Appendix B, Criterion V. The licensee made  !

an on the-spot change to a design change. The original design change modified a

, diesel generator by removing the muffler bypass valve. The on-the-spot change '

stated operations could declare the diesel operable, although inspectors identified on

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March 15,1996, that postmodification testing was not completed, a section of the

essential exhaust path was suspended by chain f alls rather than supports, and a

valve in that section was removed, resulting in a pipe opening which was not

evaluated. This was a violation of Procedure 3.4.10, " Station Modification

Changes." The inspector reviewed the corrective action taken by the licensee to

i prevent a recurrence of this violation. The corrective actions included completing

the postmodification testing before declaring the diesel operable, counseling

, associated personnel, and developing Operating Instruction 16 to provide operational

guidance for returning safety systems to operable status. The inspector determined

that the licensee's actions were adequate and closed this violation.

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08.2 LClose.d) Violalign 50-298/96023-06: The inspector reviewed the licensee's

response letter, NLS960196, dated October 30,1996, and related condition reports

regarding multiple violations of 10 CFR Part 50, Appendix B, Criterion V. This

violation was issued because operators failed to notify the control room supervisor

and shif t supervisor of a mispositioned control rod per Procedure 2.0.3, " Conduct of

Operations," on January 7,1996. The inspector reviewed the corrective actions

taken by the licensee to prevent a recurrence of this violation. The corrective

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actions included removing the crew from license duties on January 8,1996, pending

assessment and evaluation of the event, taking disciplinary action against both

reactor operators, and initiating an independent investigation review team. The

4 licensee also had a station stand down on January 16,1996, to discuss these

issues and other items important to safety. The licensee determined the root cause

to be attributed to the operators involved. The inspector determined that the

licensee's actions were adequate and closed this violation.

08.3 (Closed) Violation 50-298/96023-07: The inspector reviewed the licensee's

response letter, NLS960196, dated October 30,1996, and related condition reports

regarding multiple violations of 10 CFR Part 50, Appendix B, Criterion V. This

.

violation was issued because, on January 7,1996, operators deviated from the

' approved rod saquence plant procedure without the approval of a reactor engineer or

a Station Operations Review Committee, required by Procedure 10.13, " Control Rod

1 Sequence and Movement Control." The inspector reviewed the corrective actions

1 taken by the licensee to prevent a recurrence of this violation. The corrective

actions included developing written management expectations of the roles and

responsibilities of the reactor operator and second checker during control rod

manipulations and developing Operations Instruction 7 to provide additional guidance

on concurrent verification. The licensee also initiated a station stand-down on

January 16,1996, to discuss these issues and other items important to safety. The

licensee determined the root cause to be attributed to personnel error. The

inspector determined that the licensee's actions were adequate and closed this

violaticn.

08.4 (Closed) Violation 50 298/96023-08: The inspector reviewed the licensee's

response letter, NLS960196, dated October 30,1996, and related condition reports

regarding multiple violations of 10 CFR Part 50, Appendix B, Criterion V. This

. .

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violation was issued because operators f ailed to implement a recovery plan for j

recovering mispositioned control rods with concurrence of the shift supervisor and l

j reactor engineering, per Procedure 10.13, Control Rod Sequence and Movement

Control," on January 7,1996. The inspector reviewed the corrective actions taken

^

by the licensee to prevent recurrence of this violation. The corrective actions

included taking disciplinary actions against the two reactor operators that were

involved. The requirements for compliance were discussed with operations

personnel to ensure a common understanding of Procedure 10.13. The licensee also

initiated a station stand-down on January 16,1996, to discuss these issues and

i other iterns important to safety. The licensee determined the root cause to be

attributed to operator misconduct. The inspector determined that the licensee's

actions were adequate and closed this violation.

08.5 (Closed) Violation 50-298/96025-01: Technical Specification 6.2.1. A.4.e. requires

~

I a review of station operation by the Station Operations Review Committee so

q

potential nuclear safety hazards could be detected. However, it was determined

,

that from July 2 through November 25,1996, the Station Operations Review

3 Committee did not review station operations for potential safety hazards. The

inspector reviewed the corrective action taken by the licensee to prevent recurrence

of this violation. The corrective actions included a revision of implementing

Procedure 0.3, " Station Operations Review Committee," clarifying duties in this

area. The licensee also initiated a station stand-down on April 5,1997, to discuss

i this issue and other items important to safety. The inspectors have since observed

'

appropriate reviews of potential safety hazards by the Station Operations Review

- Committee. The inspector determined that the licensee's actions were adequate j

and closed this violation.

08.6 (Closed) Insoection Follow-uo item 97002-01: Procedure for Disabling

Annunciators. Inspectors had noted that operations shift crew disabling of

annunciators was controlled by instructions which did not require review of the

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Updated Safety Analysis Report or abnormal procedure requirements to ensure the

3

plant configuration was not compromised with respect to these references. The

licensee acknowledged that the annunciator disabling procedure was weak and

stated that formal procedure controls for annunciator dhahling would be

implemented. The inspector had noted no safety issues associated with the

previous process as it was implemented over a 10-month period.

On June 6,1997, the inspector completed review of Procedure 2.3.1, Revision 16,

" General Alarm Procedure." This procedure had been revised to include a disabled

annunciator eva;uation process requiring evaluation of alarms with respect to

operability assessments, abnormal, emergency, emergency operating procedures,

and emergency plant implementing procedures, and Technical Specification

surveillance criteria. The procedure required that monitoring and compensatory

actions be evaluated and recorded. The procedure provided a table which identified

alarms called out in surveillance procedures, Technical Specifications, and the

i Updated Safety Analysis Report. Based on a sample inspection of alarms, the

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inspector found that, in general, the procedure properly identified alarms which were

credited for those controlled procedures and plant configuration requirements. The

inspector observed a significantly increased level of rigor in the process for disabling

annunciators. This procedure improvement addressed the inspectors' concern.

11. Maintenance  !

M1 Conduct of Maintenance

M 1.1 General Comments

,

a. Insoectio_0_Scoce (61726 and 62707)

The inspectors observed all or portions of the following work activities:

Procedure I 1112

14.15.1 Jet Pump Flow Calibration

6. ADS.302 Automatic Depressurization System (ADS) Accumulator

Test

6. AD S.202 ADS Manual Valve Actuation From Alternate Shutdown

Panel

MWR 97-0563 Replace Leaking Valve on ADS Accumulator

M 1.2 Jet Pumo Flow lDstrument CalibratioD

.

a. Insa.qction Scoce (61726)

On June 18,1997, the inspectors observed the calibration of one channel of reactor

jet pump flow instrumentation. Included in this observation was a review of the

procedure requirements, instrument and control technician knowledge, training

methodologies used for on-the-job training performed for two technicians, and

equipment calibration.

b. Ohservations and Findinas

The inspectors observed instrument and control technicians perform portions of

Procedure 14.15.1, Revision 7.2, " Jet Pump Flow Calibration." The inspectors

observed the initial venting and test rig installation in the reactor building as well as

instrument checks performed in the control room. Technicians were conducting on-

the job training for two unqualified technicians during the performance of calibration.

All of the technicians were knowledgeable of the procedural requirements. Good

f ace-to-f ace and phone communications were observed. Technicians utilized good

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self-checking techniques. The qualified technicians closely monitored trainee

performance throughout the procedure. Instrumentation used for the performance

of the procedure was within calibration dates. Technicians adhered to the

procedure and signed for eacn step upon completion,

c. Conclusions

Instrument and control technicians performed jet pump flow calibration in

accordance with approved procedures. Technicians demonstrated good self-

checking and communications techniques during the evolution. Additionally,

technicians exercised proper control of :rainees while properly conducting on-the-job

training.

M 1.3 ADS Accumulator Test

a. [nsoection Scone (61726)

I

The inspectors observed testing of the ADS accumulators and held discussions with I

the maintenance technicians and a maintenance supervisor. l

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b. Observations and Findinas

On May 13,1997, the inspectors observed the performance of Procedure

6. ADS.302, " ADS Accumulator Functional Test," Revision 2, which verified that the

accumulators retained required air pressure after 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />. The acceptance criterion

for remaining pressure was based on that sufficient to actuate the ADS relief valves

five times.

The inspectors noted a procedural weakness in that the procedure did not provide l

'

guidance on how the 1-hour time limit should be tracked. The maintenance

technicians noted the time prior to performing any steps in the procedure, entered

4

the drywell, and established the desired initial accumulator pressures by traveling

about the drywell from one accumulator to the next. The maintenance technicians

! waited 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> from the start time and then performed the procedural steps to check

i the accumulator pressures, again traveling from one accumulator to the next in the

i

same order as the test initiation. No times were checked other than the single start

and finish times. The inspectors noted that tracking the 1-hour time limit in this

manner could lead to a nonconservative error with regard to the time limit.

During this surveillance observation the inspectors did not identify any

i nonconservative implementation regarding the 1-hour time limit for each

i accumulator. Af ter discussions with the licensee, the licensee agreed that the

procedure should be revised to provide better guidance to the maintenance

technicians on how to track the 1-hour time limit. The licensee issued a problem

identification report to revise the procedure.

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c. Conclutisns

The inspectors identified a potential weakness in that the surveillance procedure for

automatic depressurization valve accumulator function did not provide appropriate

guidance on how to track the 1-hour time limit. The method used was vulnerable to

nonconservative time tracking. The licensee agreed to revise the procedure to

include better guidance.

M4 Maintenance Staff Knowledge and Performance

M4.1 Control of Plant Process Regulators

a. Insoection Scope (62707)

, The inspectors evaluated problems caused by improper regulator settings during the

reactor plant startup.

b. Observations and Findinas

The inspectors noted that, during the plant startup, a number of operational

difficulties were caused by improper regulator settings. The high pressure cc,olant

injection (HPCI) lubricating oil pressure regulator was found set below its band

during its first surveillance test on May 22,1997. Plant evaluation determined that

the installed oil pressure gauge had been used to set the regulator. Further, on

May 23, the main turbine generator unit gland seat flow hydrogen cooling was

inadequate as a result of an improperly set regulator. On May 24, the Automatic

Depressurization System Accumulator Low Pressure Alarm actuated, indicating

inadequate nitrogen pressure. Operators found the nitrogen pressure regulator

which supplies nitrogen to the accumulators was set too low. On June 3, operators

noted difficulties with main turbine gland sealing regulating valves.

Inspectors questioned whether processes for determining and setting regulators

were adequate. Inspectors also questioned if the use of installed plant equipment

for measurhg and test equipenent purposes was properly managed to ensure

calibration accountability.  ;

interviews with maintenance and operations personnelindicated that multiple ,

organizations set and maintained the various regulators. Responsibility for regulator l

setting was not clearly delineated. The licensee stated that a review of regulator i

requirements and plant processes would be done to better anticipate and control

regulator settings.

The licensee found that the HPCI oil pressure gage had last been set several months

prior and had drifted to the edge of its band. The inspectors noted that the

applicable problem identification report review was addressing only the HPCI

pressure issue, and did not address the measuring and test equipment control

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concerns with respect to use of installed plant gages. In response to this concern,

the licensee agreed the use of installed gages as measuring and test equipment

should be evaluated.

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c. Conclusions

The licensee did not have clear ownership, or a process in place to control plant

regulator settings and setpoints, resulting in reactive response to undesirable system

pressures during startup activities. Ownership of the plant regulator settings was

ambiguous. i

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M8 Miscellaneous Maintenance issues (92700) (92902)

M8.1 (Closed) License Event Reoort 50-298/96011: A technician found one nut finger ,

loose on the split coupler connecting the HPCI stop valve with its operator. The l

licensee found that coupling fasteners were wrench tightened during reassembly l

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without a specific torque value. The licensee revised HPCI system maintenance

procedures that affected the coupling to incorporate guidance for appropriate

coupling fastener torquing. The licensee also reviewed generic valve procedures and

system operating procedures to ensure that sufficient guidance for tightening split

couplings was provided. The inspector determined that the licensee's actions were

adequate. The failure to include torquing instructions in the maintenance procedure,

resulting in a safety system being inoperable, is a violation of 10 CFR Part 50,

Appendix B, Criterion V, which requires, in part, procedures or instructions

appropriate to the circumstance shall be implemented. This nonrepetitive, licensee-

identified and corrected violation is being treated as a noncited violation, consistent

with Section Vll.B.1 of the NRC Enforcement Policy (Noncited Violation 50-

298/97006-03).

M8.2 (Closed) Violation 50-298/96019-02: The inspector reviewed the licensee's

response letter, NLS960206, dated November 6,1996, and related problem

identification reports regarding two violations of 10 CFR Part 50, Appendix B,

Criterion V. Inspectors identified that the licensee had declared the HPCI system

operable without removing the lanyard potentiometer from the stop valve as

required. Also, on August 29,1996, inspectors identified that Procedure 7.2.53.7,

" Operation of Engine Analysis," did not adequately control the installation of test

equipment on the diesel generator even though the procedure stated that test

equipment should only be installed while the diesel generator is in an allowed outage

time or is not required to be operable. Inspcctors identified that the diesel generator

was returned to operable status with test equipment installed. The inspector

reviewed the corrective action taken by the licensee to prevent recurrence of this

violation. The corrective actions included an evaluation that concluded for both of

the system configurations, neither situation adversely affected component or system

reliability, that Procedure 7.2.53.7 was revised to ensure that the control room staff

is aware when the diesel generator testing equipment has been installed, and the

licensee's surveillsace test procedures were reviewed and edited as necessary to

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ensure that the installation and removal of test equipment is performed consistently

with operability requirements. The inspector determined that the licensee's actions

were adequate and closed this violation.

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M8.3 (Ocen) Violation 50-298/94016-02: Failure to implement Technical Specification

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surveillance requirements. During review of corrective actions for this violation, the ,

inspectors identified that many surveillance steps intended to verify Technical

Specification acceptance criteria were written in a manner that did not require

verification. In these cases, the licensee had used the term " ensure" rather than

" verify," which, by this licensee's definition, means that, if the required response is

not observed, the operator is to promptly adjust plant equipment to obtain the

response. This finding was documented in an earlier report. The licensee responded

on June 4 with a night order to provide expectations for the word " ensure" used in

surveillance procedures. It was to be interpreted as " verify" where acceptance

criteria were concerned. On June 25, the licensee changed four surveillance

'

procedures. The night order was stillin place, and licensee reviews were

continuing.

The licensee was continuing a validation of the Surveillance Test Verification i

Program to address multiple concerns raised by the inspectors. Inspector followup l

will resume when the licensee's corrective actions are more complete. l

111. Enaineering

E1 Conduct of Engineering

E1.1 Lack of Understandina of Rod Pattern Differences from Banked Position Withdrawal

Secuence (BPWS)

a. Insoection Scoce (37550. 37551)

Inspectors reviewed licensee actions associated with a difference between actual

rod pattern and vendor reference documentation. inspectors reviewed associated

documents and discussed actions with licensee staff.

b. Observations and Findinos

On May 30,1997, reactor engineering identified that the banked position

withdrawal sequence for the control rods had not been implemented consistent with

the positions documented in NEDO-21231,1977, " Banked Position Withdrawal

Sequence." This document prescribes which rods are to be assigned to which

withdrawal groups. A contract engineer questioned why the groups being used by

the licensee for rod control were different from those specified in the vendor

reference document.

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On May 30, the licensee initiated Problem identification Report (PIR) 2-23052, l

which identified that control rod group assignments do not meet the BPWS

'

sequence. The BPWS ensures that incremental control rod worths are maintained at

low values. This is of particular importance below 20 percent power. In response

l to this concern, the licensee promptly implemented night orders that the plant be

tnpped if power dropped below 20 percent. Inspectors noted that Technical j

I- Specifications required that the rod worth monitor be verified to contain correct j

Banked Position Withdrawal Sequence rod groups.

The NRC noted that the core reload report referenced use of the BPWS. During the

review of the control rod drive housing operability support evaluation, inspectors

'

identified that the notch-worth reactivity was considered to be bounded, based on

2 General Electric letter dated May 15,1997, which stated that the high negative

reactivity feedback would be negligible because the licensee adheres to the BPWS

1 for rod pattern control below the low power set point. The licensee later determined

j that the rod groupings currently used by the licensee had been approved by the NRC

'

on December 22,1992, in License Amendment 156, referencing the analysis of j

J General Electric Service Information Letter 316, dated November 1979. This letter

is referenced in the Technical Specifications and states that the licensee's j

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assignments for iod withdrawal groups are identical to the rod sequence control 1

system, which implements the reduced notch-worth procedure. This function was

later described in General Electric's report NEDO 21231. The NRC safety evaluation

! associated with Amendment 156 accepted the licensee statement that the licensee

employs the Banked Position Withdrawal Sequence control rod movement pattern,

'

which is a method that ensures control rod worths are maintained at low values.

.

When this was evaluated, the licensee retracted the night order and closed the

problem identification report. The inspector noted that this conclusion was

reasonable from an immediate safety standpoint and that reactor engineering had

identified significant questions, demonstrating an improved questioning attitude.

The inspector noted that Procedure 3.2, " System Engineering Program," required

that system engineers be system experts and be familiar with design and operation

of the system. The reactor engineering program did not appear to have

implemented this requirement with respect to the two recent issues. The licensee

'

stated that Procedure 3.2 did not apply to reactor engineers and that reactor

engineers were not controlled by procedure. The licensee stated that the engineers'

. training standards have been improved over the past year to comply with an industry

standard on reactor engineer training.

c. Conclusions

,

Reactor engineering demonstrated a good questioning attitude in identifying a lack

of documentation and understanding regarding the basis for rod groups. No

procedure documented reactor engineer expectations.

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IV. Plant Suppst!

P2 Status of Emergency Procedure Facilities, Equipment, and Resources

P2.1 Weak Ownershin of Emergencv ReSoonse Facilities Ventilation Systems

a. Insoection Scoce (71750)

Inspectors questioned the reasons for extinguished damper circuit lights in the

Alternate Operations Support Center (OSC) during a plant walkdown and followed

up with discussions with plant staff.

b. Observations and Findinas

On June 6,1997, inspectors observed that the alternate OSC ventilation indicator

lights for two dampers were extinguished. The licensee replaced the light bulbs and

identified that the old light bulbs had burned out. Inspectors noted that it appeared

that no routine walkdown of this status panel occurred. The emergency

preparedness director stated that he was not sure who was responsible for

monitoring the status of this panel since the panel was located in the

instrumentation and control spaces. The control room staff stated that they had not

been assigned that area. l

The inspector noted that the apparent lack of periodic walkdowns of the ventilation ,

system was not being addressed during discussions. Both engineering and l

emergency planning staff speculated that operations performed walkdowns, which j

the inspector pointed out was incorrect, based on the inspector's prior discussions

with operations. The emergency planning staff agreed to address this issue.

c. Conclusions

inspectors identified weak ownership in the monitoring of the alternate OSC

ventilation status panel and rounds of emergency response facilities.

V. Management Meetings

X1 Exit Meeting Summary

The inspectors presented the inspection results to members of licensee management at the

exit meeting on July 2,1997. The licensee acknowledged the findings presented.

The inspectors asked the licensee whether any materials examined during the inspection

should be considered proprietary. Information associated with the BPWS was considered

proprietary information and was returned to the licensee and not included in this report. No

additional proprietary information was identified.

\

ATTACHMENT

SUPPLEMENTAL INFORMATION

PARTIAL LIST OF PERSONS CONTACTED

Licensee

Mike Bennett, Nuclear Licensing and Safety Supervisor

Mark Bohling, Senior Quality Assurance Specialist

Dan Buman, Engineering Support Manager

Paul Caudill, Safety Assessment / Site Support, Senior Manager

Fadi Diya, Design Engineering Manager

Lisa Freeman, Licensing Secretary

Chuck Gaines, Maintenance Manager

Rick Gardner, Operations Manager

Phil Graham, Vice President, Nuclear

Mike Hale, Radiation Protection Manager

Beth Hannaford, Program Engineer

W. Jay Leininger, Engineering Consultant

Ole Olson, Pl ant Engineering Manager

Mike Peckham, Plant Manager

Jim Pelletier, Engineering Senior Manager

Bruce Toline, Quality Assurance Audit Supervisor

INSPECTION PROCEDURES USED 1

IP 37550: Engineering

, IP 37551: Onsite Engineering

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IP 61726: Surveillance Observation

j IP 62707: Maintenance Observation

IP 71707: Plant Operations

IP 71750: Plant Support Activities

IP 92901: Followup - Plant Operations

i IP 92902: Followup - Maintenance

IP 92700: Onsite Followup of Written Reports of Nontoutine Events at Power Reactor

Facilities

IP 93702: Prompt Onsite Response to Events at Operating Power Reactors

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ITEMS OPENED, OPENED AND CLOSED, CLOSED, AND DISCUSSED

ODantd

298/97006 01 VIO Failure to follow Technical Specification (Section 01.2)

and

inadequate procedure for re-inerting containment

(Section 01.3) l

298/97006-02 URI Turnover checklist (Section 03.2)

Closed  ;

298/96007-02 VIO Diesel Generator 2 inappropriately declared operable ]

1

(Section 08.1)

298/96011 LER Inoperable HPCI System due to loose nut on stop valve

(Section M8.1)

298/96019 02 VIO Inappropriate installation of test equipment on safety-

equipment (Section M8.2)  ;

298/96023-06 VIO Failure to notify control room of mispositioned rod

(Section 08.2)

298/96023-07 VIO Failed to use approved control rod insertion sequence

(Section 08.3)

298/96023-08 VIO Control rod sequence / movement control (Section 08.4)

298/96025-01 VIO Failure of SORC to review operations to detect hazards

(Section 08.5)

298/97002-01 IFl Review of administrative controls of disabled annunciators 1

(Section 08.6) l

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Ooened and Closed

298/97006-03 NCV Inadequate procedure caused inoperable HPCI system due to

loose nut on stop valve (Section M8.1)

Discussed )

298/94016-02 VIO Inadequate surveillance testing (Section M8.3)

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