Text

Insp Repts 50-327/93-05 & 50-328/93-05 on 930131-0227. Violations Noted.Major Areas Inspected:Plant Surveillance & Licensee Event Rept Closeout
	ML20035A836
Person / Time
Site:	Sequoyah
Issue date:	03/15/1993
From:	Holland W, Kellogg P; NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:	;
Shared Package
ML20035A823	List: ML20035A822; ML20035A832; ML20035A836;
References
	50-327-93-05, 50-327-93-5, 50-328-93-05, 50-328-93-5, NUDOCS 9303300027
	Download: ML20035A836 (27)
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UNITED STATES

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NUCLEAR REGULATORY COMMisslON

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101 MARIETTA STREET, N.W.

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AT LANT A. G EORGI A 30323

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Report Nos.: 50-327/93-05 and 50-328/93-05

Licensee: Tennessee Valley Authority

6N 38A Lookout Place

1101 Market Street

Chattanooga, TN 37402-2801

Docket Nos.:

50-327 and 50-328

License Nos.: DPR-77 and DPR-79

Facility Name: Sequoyah Units 1 and 2

Inspection Conducted: January 31 through February 27, 1993

Lead Inspector:

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W. E. Holland, Senior Residen(Inspector Date Signed

Inspectors:

S. M. Shaeffer, Resident Inspector

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Approved by:

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Paul J. Ke}logg; Ch((f, Section 4A

Date Signed

Di' vision of Reactor' Projects

SUMMARY

Scope:

This routine resident inspection was conducted on site in the areas of plant

operations, plant maintenance, plant surveillance, evaluation of licensee

self-assessment capability, licensee event report closecut, and followup on

previous inspection findings. During the performance of this inspection, the

resident inspectors conducted several reviews of the licensee's backshift or

weekend operations.

9303300027 930315

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Results:

In the area of Radiological Controls, a strength was identified with

regard to licensee performance in this area over the past five months.

The performance indicated an aggressive ALARA attitude and resulted in

personrem expenditure and personnel contamination events being well

below established goals (paragraph 3.b).

In the area of Engineering / Technical Support, weaknesses were identified

involving poor material condition of plant equipment which placed

additional burdens on plant operating personnel (paragraphs 3.c, 3.d,

and 4.a).

In the area of Engineering / Technical Support, a weakness was identified

with regard to the adequacy reviews for compensatory measures taken for

degraded ventilation equipment servicing safety-related areas (paragraph

3.d).

In the area of Engineering / Technical Support, an unresolved item was

identified with regard to review of licensee justification and safety

evaluation for operation with a steam dump out of service (paragraph

4.b).

In the area of Maintenance, a weakness was identified with regard to

configuration control during corrective maintenance activities.

Additionally, poor root cause determinations were performed for a wiring

discrepancy associated with a heater drain tank bypass valve (paragraph

4.c).

In the area of Surveillance, an unresolved item was identified for

review of licensee corrective action for SQSCA920009 for deferral of

safety-related instrumentation calibrations (paragraph 5.a).

In the area of Maintenance, a Violation of Technical Specifications 3.6.1.1, 3.6.1.2.c, and 3.6.1.3.b was identified for a failure to

maintain primary containment integrity, containment bypass leakage

within required limits, and an operable containment airlock (paragraph

5.b).

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REPORT DETAILS

1.

Persons Contacted

Licensee Employees

R. Fenech, Site Vice President

R. Beecken, Plant Manager

L. Bryant, Maintenance Manager

J. Baumstark, Operations Manager

M. Cooper, Site Licensing Manager

R. Drake, Manager, Project Management and Controls

T. Flippo, Site Quality Assurance Manager

J. Gates, Outage Manager

J. Hamilton, Quality Audit and Assessment Manager

C. Kent, Chemistry and Radiological Control Manager

K. Meade, Licensing Engineer

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R. Rausch, Modifications Manager

H. Rogers, Acting Technical Support Manager

J. Smith, Regulatory Licensing Manager

R. Thompson, Compliance Licensing Manager

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P. Trudel, Nuclear Engineering Manager

J. Ward, Engineering and Modifications Manager

N. Welch, Operations Superintendent

NRC Employees

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P. Kellogg, Chief, DRP Section 4A

Attended exit interview.

Other licensee employees contacted included control room operators,

shift technical advisors, shift supervisors and other plant personnel.

Acronyms and initialisms used in this report are listed in the last

paragraph.

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2.

Plant Status

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Unit 1 began the inspection period at full power.

The unit operated at

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full power until February 4, when the unit commenced a shutdown to MODE

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3 to make repairs to secondary side piping.

On February 5, during the

shutdown, a manual reactor trip was initiated after the rod control

system experienced an urgent failure condition. The~ trip is further

discussed in paragraph 3.f(l). After repairs were completed, the unit

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was taken critical on February 8, and returned to power operation on

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February 9.

On February 10, the unit was stabilized at approximately 75

percent power to conduct modifications and testing on the # 3 HDT bypass

valves. During this testing, problems were identified which required

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the unit to remain at'approximately 75 percent power until February 13,

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when the unit began increasing power after repairs to the # 3 HDT bypass

valves were completed. The unit returned to full power on February 13.

On February 18, the unit experienced a reactor-trip due to personnel

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error. The trip is further discussed in paragraphs 3.a and 3.f(2).

After corrective actions were completed for the trip, the unit was taken

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critical on February 19 and returned to full power on February 21, 1993.

The unit operated at approximately full power for the remainder of the

inspection period.

Unit 2 began the inspection period in MODE 2 with startup evolutions

continuing. The unit connected to the grid on January 31 and resumed

full power operation on. February 2,1993. On February 10 the unit power

was decreased to approximately 73 percent due to concerns regarding

problems with the Unit 1, # 3 HDT bypass valves and the potential for

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similar problems on Unit 2.

After corrective actions were completed,

the unit returned to approximately 100 percent power on February 14.

The unit operated at approximately full power for the remainder of the

inspection period.

3.

Operational Safety Verification (71707)

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a.

Daily Inspections

The inspectors conducted daily inspections in the following areas:

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control room staffing, access, and operator behavior; operator

adherence to approved procedures, TS, and LCOs; examination of

panels containing instrumentation and other reactor protection

system elements to determine that required channels are operable;

and review of control room operator logs, operating orders, plant

deviation reports, tagout logs, temporary modification logs, and

tags on components to verify compliance with approved procedures.

The inspectors also routinely accompanied plant management on

plant tours and observed the effectiveness of management's

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influence on activities being performed by plant personnel.

(1)

On February 15, during a routine tour of the Auxiliary

Control Room, the inspectors identified that 1-LI-68-326C,

the Unit 1 RCS pressurizer level instrument, was indicating

approximately 34 %, while the CR indication was at

approximately 60 %.

The inspectors notified the CR

operator, who inspected the low indication. Having noticed

a small crack on the instruments plastic cover, the operator

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sprayed a static remover on the cover and after tapping the

cover, the indication went to the approximate actual value

(60 %). A WR was written to address the cracked instrument

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cover. The licensee previously had increased tours of this

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area due to a previous TS required instrument failure

identified by the NRC.

Also on February 10, the inspectors identified that the Unit

1, RCP 2, thermal barrier HX delta P was indicating 8 psid

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(steady), while all other CR RCP delta P indications were

indicating zero. The operators determined that all the

delta P switches were previously isolated due to a piping

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overpressurization concern. A WR was written to calibrate

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the affected instrument.

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Another instrumentation abnormality was also identified with

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the thermal barrier return temperatures for each unit. The

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temperatures for Unit I and 2 were approximately 70 and 60

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degrees F.

The Unit 2 indication was treated with anti-

static spray, tapped, and the indication rose to

approximately the same as Unit 1.

The inspector had no

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further concerns.

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(2)

Unit 1 Reactor Trip on February 18.

On February 18, 1993, at approximately 1:36 p.m., Unit 1

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experienced a turbine trip / reactor trip from approximately

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full power due to a loss of generator exciter voltage. The

loss of exciter voltage was due to a manual trip of the

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exciter breaker. The trip was caused by inadvertent

actuation of the trip lever on the exciter breaker by a

training instructor during a field training demonstration in

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the breaker cubicle.

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Initial inspection of the breaker cabinet by the inspectors

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identified that a light bulb in the cabinet was burnt out.

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Statements from the involved personnel indicated that a

flashlight was being utilized; however, the inspectors

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concluded that the lighting conditions may have contributed

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to the personnel error.

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The resident inspectors responded to the control room during

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the event and monitored licensee recovery actions. Overall

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plant response to the transient appeared to be good.

RCS

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temperature cooled to approximately 543 degrees F.

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safety systems functioned as designed; however,. operators

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did note that the pressurizer spray valves may not have

opened at 2260 psig as anticipated by the operations crew.

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This is discussed later in the inspection report. Also, the

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two running condenser circulating water pumps (CCW),

tripped. This subsequently caused loss of the steam dump

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interlock and the use of the steam dumps early in the event.

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The atmospheric reliefs were utilized to cooldown the unit

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until the CCW pumps were returned to service to allow use of

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the-steam dump. The steam dumps were placed back in service

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approximately 15 minutes after the reactor trip. After the

transient, the unit was stabilized in Mode 3 with AFW being

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supplied by motor driven pumps and decay heat being removed

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by steaming to.the condenser.

Operator actions shortly after the initiation of the event

were observed and appeared to be good. At the time of the

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event, two R0s were assigned to the unit.

During the

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recovery phase of the event, the SOS assigned a SRO to

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independently assess all of the control board indications,

- valve positions and annunciators to verify that all as-found

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discrepancies had been identified. The inspectors

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considered this to be prudent and conservative on the part

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of the 50S. The inspector also determined that the shutdown

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margin calculation was performed in a timely manner

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considering the near end-of-life conditions on the Unit 1

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core. Operators adequately reduced the AFW flow during the'

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event to preclude RCS overcooling. Unit 2 was operating at

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approximately 100 % during the event and was unaffected by

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the transient. The Unit 2 operators assisted in.the

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monitoring of the common unit parameters during the event.

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The licensee convened a reactor trip review team immediately

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after the event to review the transient and identify

abnormalities and corrective actions. The inspectors

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reviewed the functions of the post trip review team and PORC

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in paragraph 6.b.

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b.

Weekly Inspections

The inspectors conducted weekly inspections in the following

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areas:

operability verification of selected ESF systems by valve

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alignment, breaker positions, condition of equipment or component,

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and operability of instrumentation and support items essential to

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system actuation or performance.

Plant tours were conducted which

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included observation of general plant / equipment conditions, fire

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protection and preventative measures, control of activities in

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progress, radiation protection controls, missile hazards, and

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plant housekeeping conditions / cleanliness.

(1)

On February 23 and 24, 1993 the inspectors reviewed the

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licensee's performance in the Radiological Controls area for

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the last five months. During that period, the licensee

expended approximately 20 personrem on plant activities.

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This expenditure was well below the licensee's goal of less

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than 26 personrem for the period. Also, the licensee

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experienced 12 personnel contaminations which is also

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considered to be low. The inspectors toured the plant with

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radiological control management and noted continuing

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improvement in many safety-related areas with regard to

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radiological controls. Housekeeping in several safety-

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related pump rooms was considered to be very good. However,

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in other rooms, including the high head safety injection

pump rooms, continued management attention was warranted

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with regard to maintenance and housekeeping for correction

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of' support system leakage onto pump skids. The inspectors

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also noted that radiological control performance was

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reviewed each day in the plan-of-the-day meeting.

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Significant exposure jobs were specifically addressed with

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regard to dose expenditure.

The inspectors consider that

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licensee performance in this area over the past five months

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indicates an aggressive ALARA attitude and is considered a

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strength.

(2)

On February 22, the inspectors responded to the control room

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due to reports of a small fire in the 161 KV switchyard.

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The licensee had been conducting switching operations in the

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yard and during these operations, a motor operated

disconnect had failed to fully close, resulting in

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significant arcing at the disconnect after being loaded.

After the disconnect began arcing, the licensee indicated

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that customer group personnel opened the disconnect, under

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load, which was considered to be a hazardous evolution. The

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licensee initiated an incident investigation for the event.

Preliminary results indicate that licensee operations

personnel and customer group personnel did not perform to

management expectations. The inspectors determined that

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safety-related equipment had not been adversely affected

during the event, and considered that the licensee's review

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of this event appeared to be properly focused on personnel

performance expectations during abnormal operation of

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equipment.

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c.

Biweekly Inspections

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The inspectors conducted biweekly inspections in the following

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areas: verification review and walkdown of safety-related tagouts

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in effect; review of the sampling program (e.g., primary and

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secondary coolant samples, boric acid tank samples, plant liquid

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and gaseous samples); observation of control room shift turnover;

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review of implementation and use of the plant corrective action

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program; verification of selected portions of containment

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isolation lineups; and verification that notices to workers are

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posted as required by 10 CFR 19.

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On the morning of February 25, 1993 the inspectors were notified

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of a condition on Unit 2 which placed the unit in TS LCO 3.5.1.1

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ACTION a.

The ACTION was required due to # 4 Cold Leg Injection

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Accumulator boron concentration being at approximately 2,376 ppm.

The TS minimum limit was 2,400 ppm. The ACTION statement required

that the unit be in MODE 3 within the next 7 hours8.101852e-5 days 0.00194 hours 1.157407e-5 weeks 2.6635e-6 months if the ACTION

condition was not corrected.

Over the next 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months , the licensee

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conducted a fast drain / refill evolution on the # 4 Accumulator and

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reestablished boron concentration above 2,400 ppm.

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The inspectors reviewed licensee actions and past sampling

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frequencies and determined that due to check valve leakage from

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the RCS into the accumulator, the licensee has been draining the

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accumulator approximately every 12 days to maintain the TS

required boron concentration (between 2,400 and 2,700 ppm boron).

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The TS also requires that the accumulator boron concentration be

verified at least once per 31 days and within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months after each

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solution volume increase of greater than or equal to 1% of tank

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volume. The inspectors determined that the licensee was

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initiating sampling well within the 1% tank volume increase limit

as required; however, the increased sampling frequency was due to

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the fact that higher than normal check valve leakage of RCS water

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into the accumulator has been occurring for a relatively long

period of time (since June 1992).

The inspection period ended

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prior to the licensee determining why the boron sample was below

TS limits. The licensee initiated a PER (SQPER930049) to review

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the event and determine the cause of the problem.

The inspectors determined that the licensee appropriately entered

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the TS LC0 ACTION when they determined that the boron

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concentration was below TS limits, and were able to return the

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accumulator to OPERABLE status within the LC0 ACTION time.

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However, the inspectors concluded that the greater than normal

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check valve leakage was an example of poor material condition of

plant equipment which was placing additional burden on plant

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operating personnel. This material condition problem was

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considered to be a weakness.

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d.

Other Inspection Activities

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Inspection areas included the turbine building, diesel generator

building, ERCW pumphouse, protected area yard, control room, vital

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6.9 KV shutdown board rooms, 480 V breaker and battery rooms, and

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auxiliary building areas including all accessible safety-related

pump and heat exchanger rooms.. RCS leak rates were reviewed to

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ensure that detected or suspected leakage from the system was

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recorded, investigated, and evaluated; and that appropriate

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actions were taken, if required. The inspectors routinely

independently calculated RCS leak rates using the NRC RCS leak

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rate computer program specifically formatted for Sequoyah.

RWPs

were reviewed. and specific work activities were monitored to

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assure they were being accomplished per the RWPs.

Selected

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radiation protection instruments were periodically checked, and

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equipment operability and calibration frequencies were verified.

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On February 15, during a tour of the 125 volt vital battery rooms,

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the inspectors identified that the number III and IV rooms had a

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room temperature of 67 and 69 degrees respectively as indicated by

thermometers in the rooms. The thermostats in the rooms indicated

a slightly lower temperature (64 degrees F). The inspectors also

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noted an unusually high differential pressure between the subject

battery rooms and the adjacent 480 volt board room areas, such

that it was very difficult to open the battery room doors.

Warnir,g signs on the exteriors to the battery rooms stated that

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the rooms must be greater than or equal to 75 degrees F.

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inspector noted that no alarms exist for low temperature in the

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subject areas. The inspector informed the SOS of the

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observations.

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An operator was dispatched to investigate the inspector's

observations.

It was discovered that the low temperature in the

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battery rooms was being caused by an air handling unit (AHU)

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filter access door being open on the 2 BB 480 volt board room

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ventilation system. This system is located in a locked concrete

bunker on the roof of the control building. Due to the filter

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door being open, cold outside air was allowed to enter the

ventilation system for the associated 480 volt board rooms and the

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two subject 125 volt battery rooms.

Subsequently, the temperature

in the areas was lowered to the point where, if outside

temperatures were lower, it may have challenged the TS limit of 60

degrees F for the safety-related 125 volt battery electrolyte

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temperature.

In addition, to lowering the area room temperatures,

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the open filter door allowed the AHU fans to act as pressurization

fans, increasing the local pressure differential (delta P) as

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previously identified by the inspectors. The inspectors discussed

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the increased delta P conditions with engineering due to previous

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NRC concerns identified regarding pressurization of areas adjacent

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to the control room envelope and having a non-conservative effect'

on control room pressurization during an emergency.

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inspectors were informed that engineering personnel performed a

walkdown of the 480 volt board room and other areas to address the

concerns. The inspectors were informed that an increased pressure

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on the elevation of the 125 volt battery rooms would not affect

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the pressurization testing of the control room envelope.

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The inspector reviewed the requirements of TS Surveillance

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Requirement 4.8.2.3.2.b.3.

This surveillance requires

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verification that the average electrolyte temperature of 6

connected cells is above 60 degrees F.

The inspector discussed

the 75 degree F warning signs with site engineering.

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inspectors were informed that the warning sign was for operations

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guidance, installed only to alert operators to a potential problem

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if the temperature dropped below 75 degrees.

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During discussions with engineering personnel, the inspectors were

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informed that the filter door on the AHU was purposely opened as a

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compensatory action per JC0 92015. This JC0 addressed operation

for conditions where the subject area temperatures were too high

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due to the failures of ventilation equipment.

The inspectors

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noted that the controller for the 2BB 480 volt board room chiller

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was out of service since July of 1992.

Subsequently, engineering

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and operations personnel stated that the filter door was opened to

allow cooler air into the areas in the summer months to prevent

localized high temperatures. The inspectors reviewed the JCO. .It

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briefly addressed operation of the AHU with the filter doors open

during the winter months; however, this operation ielied on the

low limit of thermostats to.stop the AHU if the 480 volt board

room temperatures dropped below 70 degrees F. 'The inspector

reviewed data from 0-PI-0PS-000-606, BALANCE OF PLANT TEMPERATURE

MONITORING PROGRAM, Revision 7, which records the temperature of

the 480 volt board room areas on a shiftily basis.

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temperature of these areas directly affected the temperature of

the battery rooms.

The PI data for February 15 indicated that the

area temperatures which affect the # III and IV vital batteries

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was below 70 degrees F for all three shifts. This indicated to

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the inspectors that the thermostat relied on the stop-the AHU was

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not operating correctly. System engineering was informed and

stated that they would address the thermostat issue.

It appeared

to the inspectors that the warning signs on the battery room

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doors, in this instance, were ineffective in sensitizing operators

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to room temperature limits.

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The inspectors also concluded that although the TS limit was not

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exceeded, the configuration of the ventilation system may have

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challenged the TS limit if colder outside temperatures existed.

The inspectors also concluded that the JC0 was weak-in fully

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evaluating the operation of the AHU with the filter door open in

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the winter months, and the potential for additional pressurization

effects on the control room pressurization boundary. .In addition,

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this problem was an additional example of a weakness by which poor

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material condition of plant equipment was placing additional

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burden on plant operating personnel.

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e.

Physical Security Program Inspections

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In the course of the monthly activities, the inspectors included a

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review of the licensee's physical security program. The

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performance of various shifts of the security force was observed

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in the conduct of daily activities to include: protected and vital

area access controls; searching of personnel and packages;

escorting of visitors; badge issuance and retrieval; and patrols

and compensatory posts.

In addition, the inspectors observed

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protected area lighting, and protected and vital areas barrier

integrity.

f.

Licensee NRC Notifications

(1)

On February 5, 1993 the licensee made a notification.to the

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NRC as required by 10 CFR 50.72 with regard to entry into

site emergency plan. At approximately 5:07 a.m. on

February 5, during a routine shutdown to conduct maintenance

activities on the secondary side of the plant, the Unit 1

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rod control system experienced an urgent failure' condition

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during control rod. insertion. Operators and 1&C technicians

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attempted to determine the'cause of the failure; however,

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after troubleshooting the problem without success, operators

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initiated a manual' reactor. trip at 6:16 am from

approximately 1 percent power. All safety systems performed

as designed during the trip; however, one control rod did

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not indicate fully inserted per individual rod position

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indication. The rod bottom light did indicate that the rod

was inserted. After the trip, operators declared a

notification of unusual event based on having to manually

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trip the reactor (TS required shutdown to exit LCO ACTION

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statement). The-licensee will submit an LER for this event.

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(2)

On February 18, 1993 the licensee made a four hour

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notification to the NRC as required by 10 CFR 50.72 with

regard to a reactor trip on Unit 1.

The trip was determined

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to have occurred when an electrical training instructor

inadvertently tripped the exciter field breaker at the

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breaker compartment location. This action initiated a

turbine trip and subsequent reactor trip.

Post trip review

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is discussed in paragraphs 3.a (2) and 6.b of this report.

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The licensee will submit an LER for this event.

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(3)

On February 22, 1993 the licensee made a one hour

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notification to the NRC as required by 10 CFR 50.72 with

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regard to being outside of the design basis for exceeding

the overall allowable leak rate limit for the Unit I upper

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containment personnel air lock. The leakage was identified

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on the outer door side of the airlock.

Preliminary

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investigation indicated that the leakage had existed since

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maintenance was performed on February 16, 1993.

Subsequently, multiple entries and opening of the inner door

to the airlock have occurred which constituted a breach of

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containment integrity.

Repairs were promptly accomplished

for the identified leakage source. This event is further

discussed in detail in paragraph 5.b.

The licensee will

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submit an LER for this event.

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Within the areas inspected, no violations were identified.

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4.

Maintenance Inspections

(62703 & 42700)

During the reporting period, the inspectors reviewed maintenance

activities to assure compliance with the appropriate procedures and

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requirements.

Inspection areas included the following:

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a.

During this period, the inspectors continued with their review of

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licensee corrective actions associated with identification of

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leakage through steam generator blowdown' sample isolation valves.

This issue was discussed, in part, in inspection report 93-01.

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that report the inspectors had determined that the licensee had

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replaced two of the six identified leaking valves and intended to

refurbish the removed valves for replacement of other leaking

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valves.

The inspectors also were reviewing the licensee's

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corrective actions associated with SCAR No. SQSCA910017.

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On February 9,1993 the inspectors met with licensee personnel and

discussed or. going activities associated with corrective actions

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a

for the problems identified in SCAR SQSCA910017 for Target Rock

2

Valves.

These actions included:

]

- .

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-

.

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Review of sampling valve procedures to determine stroking

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frequency of components and chemistry composition of fluid

i

being passed through valves. Action was completed by

i

March 1, 1992.

'

,

.

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Review of collected data to determine if corrosion buildup

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on valve seats was possible cause of leakage problems.

Action was completed by June 15, 1992.

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Present study results to plant management. Action was

completed by August 1, 1992.

!

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Conduct design study to identify sampling valves not

!

sensitive to corrosion buildup.

Present findings to plant

improvement committee. Action was completed by December 15,

[

1992.

The inspectors noted that the SCAR included a conclusion which

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indicated that the evaluation consensus was that magnetite buildup

on the valve seats was the cause of the leakage. The study

,

!

recommended that the valves should be cycled during startup

following the Cycle 6 refueling outages and additional evaluations

.

be conducted to determine how to remove the magnetite.

If cycling

i

did not remove the magnetite, then new valve trim or a new valve

may be needed. The inspectors noted that the study included a

'

vendor submittal of a new trim design to minimize the leakage

i

problem.

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The inspectors also reviewed a listing of the number of valves

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which potentially have the leakage problem identified in the SCAR.

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The list included approximately 100 valves which were used in

,

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safety-related applications. The licensee stated that

approximately 20 of the valves listed had been identified as

leaking. They also concluded that root cause for the leaking

i

steam generator blowdown sample valves was improper valve

'

application. The other valves that had been identified as. leaking

.j

were mostly in the post accident sampling system. Maintenance on

!

4

these valves had corrected problems associated with their leakage..

l

On February 24, 1993 the inspectors met with plant technical

support personnel and were verbally provided with the proposed

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action plan for the steam generator blowdown line sample valves (8

!

valves) . This plan included procurement of new trim for the

valves based on the vendor's design to minimize the effect of

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magnetite buildup on valve leakage. The inspectors were not

provided with a date that corrective actions would be

accompl ished. However, engineering personnel stated that the new

!

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trim had been ordered and would be planned for replacement as soon

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as it was received.

!

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The inspectors reviewed the licensee's evaluations and corrective

!

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actions to date and considered them untimely.

The inspectors

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noted that the problem has been in existence for approximately 18

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months: yet, at the end of the inspection period, operator

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compensatory actions were being used to live with the problem.

This problem was an additional example of a weakness by.which poor

.

material condition of plant equipment was placing additional

burden on plant operating personnel.

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b.

On February 3,1993, during a plan-of-the-day meeting the

!

inspectors learned of a problem associated with Unit 2 Main Steam

i

Dump Valve 2-FCV-1-111. The inspectors noted that the valve was

,

identified as being isolated due to hanger damage. The POD stated

that the valve should remain isolated until SQPER931502 resolution

l

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is complete. Additional discussions with operations personnel

indicated that some type of event occurred which caused the steam

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dump line containing the 111 valve to move resulting in damage to

a hanger. The inspectors conducted a visual inspection of the -

valve and line and noted visible permanent deflection in the line.

They al.so noted visible damage to the steam dump valve air

'

operator.

!

The inspectors held a discussion with system engineering

,

supervision later the same day and were informed that an event

i

occurred during Unit 2 shutdown on January 29, 1993 resulting in

,

damage to the valve. The licensee stated that water hammer was

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encountered when the dump was placed in service during the

'

shutdown. The suspected cause of water in the line was attributed

i

to improper operation of the drain valve for the line. Additional

i

discussions with engineering supervision and plant management

!

indicated that an initial engineering evaluation was accomplished

i

on January 30, 1993, after identification of the line condition by

,

system engineering. The evaluation concluded that-the line was

'

structurally sound for unit operation.

PER No. SQPER931502 was

l

written on February 1, 1993 to document the adverse condition.

The inspectors obtained a copy of SQPER931502 and noted that the

,

preliminary engineering evaluation, which was attached to the PER,

!

did not provide any analytical or inspection documentation to

!'

support the conclusion. The inspectors met with licensee nuclear

engineering personnel on February 9,1993 and were provided with a

piping weak link evaluation for the issue. That evaluation

!

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concluded that the highest stress point in the piping, based on

observed piping deflection, was at the reducer connected to the

!

discharge side of valve 2-FCV-1-111. They also stated that the

!

valve was closed and tagged closed effectively eliminating any

additional dynamic forces on the line. The licensee further

stated that additional non-destructive testing was to be

accomplished on the weak link locations to look for degradation.

On February 18, 1993 the inspectors were provided with results of

l

non-destructive examinations for the weak link locations discussed

T

above. Specific locations inspected included piping weld areas-

[

both upstream and downstream of 2-FCV-1-111. The licensee

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concluded, based on the NDE results, that structural integrity of

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the main steam dump line was within required limits for continued

operation. However, they intended to maintain the line in a

static condition until the next appropriate outage when permanent

repair could be accomplished. The inspectors reviewed licensee

conclusions and considered that they were adequate. However, the

inspectors also requested that the licensee provide appropriate

!

justification and safety evaluation for operation with the steam

i

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dump out of service. This information had not been provided when

the inspection period ended.

Review of licensee justification and

safety evaluation for operation with a steam dump out of service

is identified as an unresolved issue (328/93-05-01).

c.

On February 10, the inspectors reviewed activities associated with

modifications to the Unit 1, 1-LCV-6-105 A and B valves (hereafter

known as 105 A and B). The activities involved corrective action

modifications for previous valve failure problems.

Specifically,

due to problems identified with the backing ring inside the 105 A

i

valve, a modification was performed to install a stronger ring and

l

to lock the valve disc to the stem. Also, a modification to

l

relocate regulators and replace copper and brass tubing and

!

fittings with stainless steel flex lines on the 105 a valve was

planned.

In addition, a modification to the 105 B valve was being

i

performed to eliminate the turbine runback from initiating

concurrent with the initial opening of the 105 B valve.

Problems

with the subject valves were previously discussed in Inspection

Report 327, 328/93-02. All of the above modifications were

previously performed on the Unit 2105 A and B valves.

By approximately 9:00 a.m. on February 10, licensee personnel

l

began to perform PMT for the activities. After work was

accomplished on the 105 A valve, it was to be stroked to assure

operability of the valve prior to working on 105 B to remove the

runback function. However, it was discovered that 105A could not

be stroked from the closed position. The licensee stopped the PMT

and presumed that the valve was stuck in the closed position

j

similar to previous problems with the 105 A valves on both units

in late 1992. The licensee decided to remove the valve for

I

inspection. Upon inspection, no internal damage was identified

and the valve was successfully stoked in a test configuration.

Discussions with the System Engineer, who was involved in the

troubleshooting activities, indicated that, given no problems were

,

'

identified with the valve, it would be reinstalled and the PMT

would be attempted again. At this time, it was suspected that the

air preload on the top cf the valve actuator may be too high and

was subsequently not allowing the valve to be opened. This was a

j

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recommendation from the valve vendor due to previous 105 valve

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issues.

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At approximately 4:30 p.m. on February 10, after the valve had

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been reinstalled and prior to PMT, the inspectors performed an

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independent inspection of the as-installed configuration of Unit 1

105 A in comparison to the Unit 2 configuration of the same valve.

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The inspectors identified that configuration discrepancies existed

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on the as-installed air supply piping which may have caused the

failure of the valve during the previously performed PMT. When

!

operations and maintenance personnel arrived at the valve location

!

to perform the PMT, the inspectors informed them of the air supply

piping and other discrepancies and asked them to confirm if the

i

105A valve air lines were misconfigured.

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Maintenance personnel delayed the start of the PMT and reviewed

the inspectors concerns. They confirmed that the air supply

piping to the 105 A valve was misconfigured.

In addition, an air

i

check valve was identified as being missing on the 105 A

,

accumulator tank for the 105 A valve.

The check valve was

i

inadvertently removed during the flex piping replacement.

l

Maintenance personnel immediately corrected the air supply piping

configuration. The check valve was not installed at this time.

.

The inspectors reviewed the pneumatics of the air supply piping

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with the licensee and concluded the specified PMT would have

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identified the air supply piping mis-configuration. However, it

was also determined that the PM1 would not have identified the

missing check valve on the accumulator for the valve.

The effect

!

of the missing check was later determined to change the failed

position of the valve on a loss of air supply.

With the check

'l

valve missing the valve would fail open instead of closed. The

!

licensee could not initially determine the preferred failed

,

position of the 105 A valve (ie. both the open and the closed

,

failure positions have advantages depending on the failure mode);

,

however, the licensee subsequently determined to replace the

!

missing check valve.

-

PMT for the 105 A valve was continued that evening. The results

f

indicated that the valve could be successfully stroked if the air

j

supply pressure to the valve operator was increased per vendor

i

recommendations.

Following adjustments and testing, the 105 A

valve was considered operable; however, due to the historical

trouble with the newly installed valve, the modification to the-

105 B valve was changed to retain the runback initiation at

approximately 75 percent open position instead of the initial

j

elimination of the runback from the 105 B valve as previously

designed. No other problems were encountered with the activities

l

and the valves were both declared operable. Although the Unit 2

105 A and B valve did not experience similar problems during the

modifications, the Unit 2 valve air supplies were subsequently

!

adjusted in the same manner to assure operability,

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In addition, during review of work plans, the inspectors noted

that a wiring error was discovered on the Unit 1, 105 A valve

i

indicating light switch.

This was discovered when troubleshooting

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was performed due to improper CR board valve position indications

for the valve during valve stroking. The inspector recalled that

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a problem with the runback signal and CR indications not occurring

'

simultaneously had been previously identified by the licensee.

However, the problem was improperly diagnosed as a cam out of

adjustment problem and the wiring discrepancy was not identified.

.

The licensee investigated the miswiring problem and determined

j

that it was most likely performed during the Unit I cycle 5

i

outage.

i

At the end of the inspection period, the licensee had initiated

.i

some corrective-actions for the above problems. These included:

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correction of the wiring error; correction of the tubing error;

replacement of the check valve; and inspection of other components

!

for similar problems. The licensee plans to address additional

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corrective actions in response to a PER (SQPER930035) which

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documented the problems. The inspectors will continue to monitor

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the licensee's activities associated with the subject valves.

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The inspectors concluded from the above observations that a

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weakness was identified concerning poor configuration control

i

during corrective maintenance activities. Additionally, poor root

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cause determinations were also performed for a wiring discrepancy

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associated with the HDT bypass valve (105 A).

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.

Within the areas inspected, no violations were identified.

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5.

Surveillance Inspections

(61726 & 42700)

2

During the reporting period, the inspectors reviewed various

surveillance activities to assure compliance with the appropriate

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procedures and requirements. The inspection included a review of the

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following procedures and observation of surveillances

<

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a.

On February 3,1993 the inspectors met'with licensee personnel and

'l

supervision to discuss the calibration status of safety-related

instrumentation. The inspectors were following up on an issue

which was identified in inspection report 327, 328/92-16.

In that

.)

report, the inspector had identified that calibration data sheets

i

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for containment spray flow loops FT-72-13 and FT-72-34 were not

provided for review during the inspection period. The inspector

noted that the resident inspectors would follow up on review of

the calibration data.

The inspectors were provided with copies of the calibration data

sheets for both Unit I and_ Unit 2 containment spray header A'and B

flow transmitters FT-72-34 and FT-72-13 'respectively. The sheets

indicated'that all four of the transmitters were calibrated

between May 12 and May 27, 1992. The~ inspectors noted that the

calibration results indicated that the instruments were in

calibration based on as-found data on the data sheets.

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However, based on the inspectors findings and other licensee

.

identified problems associated with timely performance of

calibrations, SCAR No. SQSCA920009 was written on June 15, 1992

identifying several instruments which were not being recalibrated

within the periodicity required by procedures.

On February 18, 1993 the inspectors again met with licensee -

Instrument Maintenance personnel and supervision. Additional

status of the licensee's progress for upgrading of calibraiion

procedures was discussed.

Past calibrations which were

accomplished in accordance with Surveillance Instructions were

being rewritten and transferred to Preventive Maintenance

Instructions. This program was approximately 50 percent complete

and when the inspection period ended, the program was being

reviewed as a part of the site improvement plan.

No date had been

established to complete the new calioration procedures.

During the period of identification of the untimely calibrations,

the licensee was deferring the calibrations in accordance with

SSP-8.2, SURVEILLANCE TEST PROGRAM, Revision 0.

This procedure

required that surveillance instructions which would not be

accomplished by the extension date be reported on an Appendix D to

work control. Appendix D required a reason be stated as to why

the SI would not be completed, and required concurrence on the

exception by Senior Plant Management. The inspectors. reviewed

several Appendix D extensions and noted that they had been

processed and approved as required by SSP-8.2.

The inspectors

also reviewed SSP-6.8, INSTRUMENTATION SETPOINT, SCALING, AND

CALIBRATION PROGRAM, Revision O.

This procedure required, in

'

part, "that compliance and safety-related instrumentation be

calibrated at least once per operating cycle...".

The inspectors

questioned the licensee as to whether SSP-6.8 and SSP-8.2 were in

conflict. The inspectors specifically questioned as to whether

any of the corrective action documentation had considered

administrative processes conflicts and what, if any actions were

being implemented to address this issue.

The inspectors were-

continuing their review of this issue when the inspection period

ended.

This item is identified as an unresolved item (327,

328/93-05-02), Review of licensee corrective action for

SQSCA920009 for deferral of safety-related instrumentation

calibrations. This inspection effort will continue during the

next inspection period.

b.

On February 22, during a review of surveillance activities in the

control room, the inspectors overheard discussions which pertained

to a potential leak on the Unit I upper containment personnel

airlock. The potential leak on the outer door bulkhead of

penetration PEN-X2B was identified by maintenance personnel during

performance of SI-159.2.I, AIRLOCK RESILIENT SEAL LEAK RATE TEST,

Revision 1.

During these activities, the outer door of the

airlock was closed, which created a slight vacuum inside the

airlock and allowed the opportunity for the maintenance personnel

__

_ _ _ _ _ _ _ _ - _ _ _ _ _ _

_ - -

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16

to hear a small leak and to identify the potential. problem. The

leak was identified on a test penetration located on the outer

bulkhead of the airlock, to the right of the air lock door if

facing containment. The test penetration blind flange was not

manipulated during performance of the above test. The penetration

consists of a four bolt, double 0-ring blind flange connection,

and is utilized to perform other TS required surveillance testing

of the air lock on a six month frequency.

(See Figure 1 for

details of the flange and 0-rings). The licensee satisfies

compliance with this required testing via Surveillance Instruction

SI-159.1.2, PERSONNEL AIRLOCK PEN-X2B OPERABILITY AND OVERALL

LEAKAGE TEST, Revision 3.

This test provides the steps necessary

to detect leakage from the electrical and mechanical penetrations

and other potential leakage paths for penetration PEN-X2B and

verifies the overall operability of the personnel airlock

penetration.

During this testing, the blind flange on the test

penetration is removed, and air connections are made to pressurize

the interior of the airlock to allow for leakage detection. Once

this is accomplished, the blind flange is re-installed and tested

to assure a leak free connection. The flange is tested via a air

connection on the face of the flange which allows the required

pressure (12.5 - 13.0 psig) to be applied between the two 0-rings

in the flange.

If no leakage is detected, the test on the flange

is considered successful and work in accordance with the SI is

continued.

After identification of the blind flange air leakage on February

22, operations was immediately notified. Operators entered TS 3.6.1.3 due to the potential operability problem of the

containment air lock and took actions in accordance with action

(a).

Immediate actions included chain locking of the inner

containment airlock door in the closed position. Action (a) of TS 3.6.1.3 requires, in part, the following with one containment air

lock door inoperable:

1.

Maintain at leart the operable air lock door closed and

either restore the inoperable air lock door to operable

status within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months or lock the operable air lock door

closed.

2.

Operation may then continue until performance of the next

required overall air lock leakage test provided that the

operable air lock door is verified to be locked closed at

least once per 31 days.

3.

Otherwise, be in at least HOT STANDBY within the next six

hours and in COLD SHUTDOWN within the following 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months .

Shortly after, the inspector reviewed the entry into the above

action of TS 3.6.1.3 and considered that the more applicable

action statement was action b.

This states, in part, that with

the containment air lock inoperable, except as a result of an

._

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inoperable air lock door, maintain at least one air lock door

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closed; restore the inoperable air lock door to operable status

!

within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months or be in at least HOT STANDBY within the next six

'i

hours and in COLD SHUTDOWN within the following 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months . The

-i

inspectors informed the SOS and plant management of the potential-

l

applicability of action b. of TS 3.6.1.3 and of the more-

>

restrictive LC0 time. The licensee subsequently entered action b-

of the TS. The LCO was entered as of 10:34 a.m. on february 22.

[

The inspectors observed as-found testing and corrective actions

r

for the leaking blind flange on the air lock on the afternoon and

evening of February 22. The licensee initially _ retested the

!

flange utilizing steps in SI-159.1.2. This was performed by

l

pressurizing the volume between the flange 0-rings via the flange

test connection. No leakage was identified via this method of

.!

PMT. The blind flange test connection leads through the outer

i

bulkhead of the air lock and is terminated as an open-ended pipe,

!

approximately 3 inches in diameter, with no fitting connections.

i

A idea was then suggested that the flange be pressurized from the

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inside of the air lock. The hole on the inside was sealed with

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tape and an air supply line. This testing confirmed that there

i

was a substantial leak through the blind flange connection.

!

Efforts were then made to quantify the leakage. A 3 inch

l

mechanical seal plug was installed. At approximately 12.5 psig,

l

the licensee observed a flow rate of 57.07 scfh which was-

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determined to exceed the allowable overall leak rate limit of the

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air lock (11.25 scfh). This leakage, when added to the previous

t

,

total containment bypass leakage (CBL), also was determined to

i

cause the CBL limit of 56.3 scfh to be exceeded.

The as-found

total CBL, as defined in TS 3.6.1.2, was initially determined by

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the licensee to be 61.24 scfh (this value was later modified as

described later in the inspection report). A subsequent one hour

,

notification to the NRC was made due to these findings as

'j

previously described in paragraph 3.f.3 of this report.

t

,

The inspectors noted that the flange separation to the seat of the

penetration did not appear to be equal all around. Measurements

were taken which confirmed the observation. The leaking flange

,

was then disassembled. The results indicated that several inches

!

of the outer 0-ring had come out of the provided groove and made

,

'

contact with the inner 0-ring. The inner 0-ring may also have not

been fully seated in the provided groove. The identified leakage

-

apparently originated at the point where the two 0-rings were in

!

contact.

This portion of the 0-rings was approximately 60 degrees

circumferential from the air supply inlet hole, used to pressurize

between the 0-rings during testing of the flange connection. With

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the 0-rings installed in this configuration (making contact with'

each other), the between the 0-ring testing, performed as PMT for

j

the flange seal, passed. However, as described above, a leakage

l

path still existed at the point where the two 0-rings were in

1

contact.

The inspectors concluded that, due to the incorrectly

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18

installed configuration of the 0-rings, the performed PMT (ie.

pressurizing between the 0-rings) was inadequate.

The licensee initiated an incident investigation into the event.

Immediate corrective actions included-the locking of the inner air

lock door during the troubleshooting activities. After the

problem was identified, the licensee similarly tested the three

other air lock blind flanges to assure that no other leakage path

existed. No other failure were identified and the original failed

0-ring connection was successfully repaired and returned to

operable status. The 11 should address other corrective actions

with regard to other potential occurrences of this 0-ring

installation / inadequate PMT problem.

Subsequently, on February 26, the licensee tested the mechanical

seal used to determine the as-found leakage rate for the failed 0-

ring seal. This was performed to attempt to quantify any leakage

through the mechanical seal plug which could have caused the

identified leaktge to be over conservative. The results indicated

that there was a potential for a small amount of leakage through

the seal. However; even with the mechanical seal leakage

accounted for, both the airlock and the CBL limits were exceeded.

The reanalysis performed utilized the most conservative total

leakage values and adjusted for the mechanical seal leakage. The

results indicated that the total containment bypass leakage, as.

defined by TS 3.6.1.2.c, was approximately 59.7 scfh, whereas the

TS acceptance criteria was 56.3 scfh.

The inspector reviewed the event with regard to safety and

regulatory significance.

Initial investigations indicated that

the 0-rings were not installed properly during restoration of the

blind flange connection on February 16, 1993 after testing of the

airlock was accomplished. According the licensee records, the

inner door of the airlock was opened eight times between February

16 and 22, until the leakage on the test flange located on the

outer airlock bulkhead was identified.

The inspectors concluded

that the leakage through the test flange on the airlock

(approximately 52.6 scfh) caused the licensee to be in violation

~

of TS 3.6.1.1 and 3.6.1.2.c during the periods of time when the

inner containment airlock door was opened. During these

instances, the licensee did not maintain containment integrity per

3.6.1.1 and also exceeded the allowable combined containment

bypass leakage rate for bypass leakage to the auxiliary building

as required by 3.6.1.2.c.

In addition, the inspectors also

concluded that TS 3.6.1.3.b was violated due to the allowable air

lock leakage rate of 11.25 scfh being exceeded resulting in the

inoperability.of the airlock for the period of February 16 through

February 22, 1993. The as-found airlock leakage was approximately

55.6 scfh. The above issues are identified as Violation

327,328/93-05-03, failure to Comply with the Requirements of TS 3.6.1.1, 3.6.1.2.c, and 3.6.1.3.b.

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Within the areas inspected, one violation was identified.

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6.

Evaluation of Licensee Self-Assessment Capability (40500)

During this inspection period, selected reviews were conducted of the

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licensee's ongoing self-assessment programs in order to evaluate the

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effectiveness of these programs.

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a.

On February 7, 1993 the inspectors attended the PORC meeting which

was held to review the Unit 1 post trip report for the unit trip

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which occurred on February 5, 1993. The review also addressed

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other activities required prior to restart of the unit.

The

l

inspectors obtained a draft copy of the' post trip review report,-

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Appendix H of SSP 12.9, INCIDENT INVESTIGATIONS AND ROOT CAUSE

ANALYSIS, Rev. 2, and noted the that following items were

addressed:

i

Two procedures, A01-2, MALFUNCTION OF REACTOR CONTROL

j

SYSTEM, UNITS 1 AND 2, Revision 14 and G01-3, PLANT SHUTDOWN

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FROM HINIMUM LOAD TO COLD SHUTDOWN, Revision 54-had been

identified as needing review. A01-2 was used during a rod

control system urgent failure condition. The team

determined that better guidance could be included in the

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procedure with regard to the use of a rod urgent reset

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switch. GOI-; was the governing procedure in use during

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unit shutdown. The team concluded that the G01 could be

clearer with regard to sequencing of the steam dump

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controller no-load setting of 84%, sequencing of removing #1

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and #2 feedwater heaters from service, and the time that the

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main turbine should be tripped.

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RPI for Shutdown Bank "D" Rod E-13 was stuck at~115 steps

1

with rod bottom light on after the manual trip. Work

'

request C174185 h&d been written to address this issue.

i

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Control rod urgent failure came in during manual shutdown

and rods would not move below 11% steps,

"D" bank.

Work

l

Request C130091 had been written to address this issue.

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Loop 2 PORV opened 6 minutes prior to trip.

Suspect

controller problem. Work request Cl32520 had been written

to address this issue.

IB MFP governor valves would not respond during attempt to

-

take pump out of service.

Work request C130144 had been

written to address this issue.

On February 8,1993 the inspectors reviewed the official copy of

Appendix H of SSP-12.9, which was in the control room.

The

Appendix addressed the disposition of the above items which were

required for restart.

The inspectors noted that both the' SOS and

-g.-

.

+

9-

.u

a .

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2.

_

-

.

'

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.

20_

j

Duty Plant Manager had to obtain additional documentation in order

!

to approve completed actions required to allow for reactor

!

startup. This additional Lactivity appeared to delay the startup.

!

for a few hours. The inspectors alsa noted that the disposition

l

for the control rod urgent failure problem indicated that no

L

problem was found in the hardware of the Rod Control System;

I

therefore, apparently a glitch caused a timing error in the system

resulting in the urgent alarm condition. System testing prior to

restart demonstrated that system operation was proper.

7

The inspectors also noted that the procedural issues identified by

f

the licensee in G01-3 indicated that this procedure needed

-

'

enhancement in providing for improved operator guidance during

transient operations. Other GOI procedural problems have been

identified by the inspectors during past operation. 'This

condition indicated that additional management attention was

!

i

I

warranted with regard to procedures.

i

b.

On February 19, 1993 the inspectors attended the PORC meeting

which was held to review the Unit 1 post trip report for the unit

j

trip which occurred on February 18, 1993. The-review also

i

addressed other activities required prior to restart of the unit.

The inspectors obtained a draft copy of the post trip report,

!

'

Appendix H of SSP-12.9, and noted that the following items were

j

.

identified as requiring disposition prior to unit restart:

l

i

l

-

Pressurizer spray may not have initiated'as designed on high

!

pressurizer pressure (operator observed pressure slightly

[

above spray set point).

-

The operating thermal barrier booster pump tripped during

i

transient and had to be restarted by_ operators.

1

-

The 18 main feed pump governor valve positioner did not

+

close. Work request C128044 written.

l

-

AFW bypass LCVs indicated full open at 110 gpm to each

l

generator. Operator able to manually bump open valves to

!

get an additional 50 gpm.

-

During trip rod bottom light E-13 did not light.

(Operators

replaced burnt out bulb after the trip.)

In addition, the following other issues were identified as

!

requiring disposition based on possible abnormal behavior;

!

however, they were not required to be corrected prior to unit

j

startup.

i

-

The 1A and IB condensate booster pump suction valves did not

'

automatically close. Work requests C174213 and C010533

written to address these items.

=

.

i

=

,

i

21

CCW pumps IB and IC tripped during transient. . Work requests

-

C046088, C046089, and C046090 written to address these

.

I

issues.

.

-

1A MFPT seal leakage excessive. Work requests C048683 and

C048694 written to address this issue.

-

The IA2 heater channel relief valve lifted. Work request-

,

0048450 written to address this issue.

-

The # 3 heater drain tank bypass valve 1-LCV-6-105A may not

have opened as expected on high level in the tank.

.

!

'

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Feedwater heater B1 LCV stuck in mid-position. Work request

,

C132401 written to address this issue.

-

PCB 5038 had a significant air leak.

(This problem was

[

worked by the customer group and corrected prior to unit

l

restart.)

-

Safeties on the MSRs on the turbine deck briefly lifted

during the event.

'

Later that evening the inspectors reviewed licensee disposition of

restart (MODE 2) items identified above by reviewing the official

copy of Appendix H of SSP-12.9, which was in the control room.

During the review, the inspectors determined that documentation of

disposition for two of the restart items did not provide

'

supplemental feedback for the operational concerns.

Specifically,

<

the pressurizer spray initiation issue had been addressed by an

!

engineering evaluation that concluded that the plant responded as

designed. However, nothing was discussed with regard to the

'

operator concern for the issue (i.e. training or simulator

,'

response). The other issue, concerning automatic tripping of the

operating thermal barrier booster pump, was also technically

reviewed and no cause for the problem was identified. A decision

had been made to operate with the condition at the PORC; however,

no information was provided to operators in the disposition of the

issue with regard to continued operation with this condition.

>

Within the areas inspected, no violations were identified.

7.

Licensee Event Report Review (92700)

The inspectors reviewed the LERs listed below to ascertain whether NRC

f

reporting requirements were being met and to evaluate initial adequacy

t

of the corrective actions. The inspector's review also included

followup on implementation of corrective action and/or review of

-

licensee documentation that all required corrective action (s) were

either complete or identified in the licenset's program for tracking of

outstanding actions.

'

l

s

I

'

..

,

l

f

22

,

t

(Closed) LER 327/92-20, failure to Perform a Fire Watch Within the

Minimum Timeframe Required by Technical Specifications. The issue

involved fire watch personnel not performing patrols as required by TS

'

and licensee procedures.

Licensee corrective actions included

disciplinary actions against involved individuals and additional

!

emphasis of management expectations to fire watch personnel.

This issue

l

was discussed in inspection report 327, 328/92-35.

i

Within the areas inspected, no violations were identified.

~

8.

Action on Previous Inspection Findings

(92701, 92702)

(Closed) VIO 328/92-22-01, Failure to follow Housekeeping and/or

.

Cleanliness Requirements During Maintenance Activities Around Safety-

Related Components. The violation involved a failure to adequately

I

control activities associated with floor stripping and component

.

painting around and on the safety-related Unit 2 TDAFW pump.

Immediate

corrective actions included suspending the ongoing coating and

preparation for coating activities. Walkdowns were performed by the

,

licensee to determine if debris from the floor stripping operations and

the component recoating evolutions had caused any other problems with

>

safety-related equipment. No other operability problems were

-

identified; however, minor discrepancies such as protective coatings

applied to portions of snubbers and threaded valve stems.

In addition,

'!

application of coatings on some stainless steel components were

!

identified (material was non-compatible with stainless steel). These

'

problems were corrected as appropriate. Other actions included craft

r

!

training and procedural revisions to MI-10.14, APPLICATION REPAIR OF

PROTECTIVE C0ATINGS IN THE REACTORS AND AUXILIARY BUILDINGS. The

inspectors reviewed the' licensee's violation response, procedural

'

enhancements, and inspected several final coating applications in the

facility for compliance.

Within the areas inspected, no violations were identified.

!

9.

Exit Interview

.

!

The inspection scope and results were summarized on March 1,1993 with

'

those individuals identified by an asterisk in paragraph I above.

The

!

inspectors described the areas inspected and discussed in detail the

inspection findings listed below.

Proprietary information is not

contained in this report. Dissenting comments were not received from

the licensee.

!

Item Number

Description and Reference

!

URI 328/93-05-01

Review of licensee justification and

safety evaluation for operation with

!

a steam dump out of service.

i

,

.

_

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--

-

,

'

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!

23

!

l

URI 327, 328/93-05-02

Review of licensee corrective action

i

for SQSCA920009 for deferral of

safety-related instrumentation

'

calibrations.

VIO 327/93-05-03

Failure to comply with the

requirements of TS 3.6.1.1,

'

3.6.1.2.c, and 3.6.1.3.b.

Strengths and weaknesses summarized in the results paragraph were

f

discussed in detail.

!

Licensee management was informed of the items closed in paragraphs 7

'

and 8.

I

10.

List of Acronyms and Initialisms

l

!

l

AFW

-

Auxiliary Feedwater

AHU

-

Air Handling Unit

ASOS -

Assistant Shift Operations Supervisor

'

AVO

-

Assistant Unit Operator

'

CAQR -

Condition Adverse to Quality Report

CBL

-

Containment Bypass Limit

l

CCW

-

Condenser Circulating Water

i

CR

-

Control Room

DRP

-

Division of Reactor Projects

EDG

-

Emergency Diesel Generator

ERCW -

Essential Raw Cooling Water

ESF

-

Engineered Safety Feature

FSAR -

Final Safety Analysis Report

GPM

-

Gallons per Minute

HDT

-

Heater Drain Tank

HX

-

Heat Exchanger

ISI

-

Inservice Inspection

JC0

-

Justification For Continued Operation

KV

-

Kilovolt

LCO

-

Limiting Condition for Operation

LCV

-

Level Control Valve

LER

-

Licensee Event Report

MDAFW -

Motor Driven Auxiliary feed Water

MFP

-

Main Feedwater Pump

MFPT -

Main Feedwater Pump Turbine

,

l

MSR

-

Moisture Seperator Reheater

NDE

-

Non Destructive Examination

NRC

-

Nuclear Regulatory Commission

PER

-

Problem Evaluation Report

PMT

-

Post-maintenance Test

PORC -

Plant Operations Review Committee

l

PORV -

Power Operated Relief Valve

o

PPM

-

Parts Per Million

l

PSID -

Pounds Per Square Inch Differential

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-

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.

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24

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!

PSIG -

-Pounds Per Square Inch Gauge

l

RCP

-

Reactor Coolant Pump

RCS

-

Reactor Coolant System

!

RHR

-

- Residual Heat Removal

i

Reactor Operator

j

R0

-

RPI

-

Rod Position Indication

Radiation Work Permit

!

RWP

-

SCFH -

Standard Cubic Feet Per Hour

SG

-

Steam Generator

l

SI

-

Surveillance-Instruction

-!

SIP

-

Safety Injection Pump

-!

SOS

-.

Shift Operating Supervisor

l

SR0

-

Seninr Reactor Operator

,

SSP

-

Site Standard Practice

i

TDAFW --

Turbine Driven Auxiliary feedwater

!

TS

-

Technical Specifications

!

TVA

-

Tennessee Valley Authority

f

URI

-

Unresolved Item

VIO

-

Violation

WP

-

Work Plan

WR

-

Work Request

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1

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UPPER CONTAINMENT AIRLOCK BLIND

FLANGE

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\\ LEAKAGE

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TEST PRESSURIZATION ORIFICE

!

FIGURE 1

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-

.

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.

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ML20035A836

Text

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