ML18064A397

Insp Rept 50-255/94-14 on 940811-0927.Violations Noted. Major Areas Inspected:To Review & Categorize Licensee Response to Det Rept to Ascertain Whether Proposed Plans for Improvement Addressed Reported Weaknesses & Root Causes

ML18064A397
Person / Time
Site:	Palisades
Issue date:	09/28/1994
From:	Kropp W NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III)
To:
Shared Package
ML18064A395	List: ML18064A394 ML18064A396 ML18064A397
References
50-255-94-14, NUDOCS 9410070051
Download: ML18064A397 (44)

See also: IR 05000255/1994014

Text

U. s: NUCLEAR REGULATORY COMMISSION

REGION I II

Report No. 50-255/94014(DRP)

Docket No. 50-255

License No. DPR-20

Licensee:

Consumers Power Company

212 West Michigan Avenue

Jackson, MI

49201

Facility Name:

Palisades Nuclear Generating Facility

Inspection At:

Palisades Site, Covert, Michigan.

Inspection Conducted:

August 11 through September 27, 1994

Inspectors:

w.

J~

M. E.

D. G.

C. N.

R. M *.

D. S. Butler

A. Dunlop

Approved By:

• .~

• ... *

2A

Inspection Summary

Inspection from August 11 throuah Seotember 27. 1994

(Report No. 50255/94014CDRPl

Date

'

Areas Inspected: Special, u~announced safety inspection to revie~ and

categorize the licensee's response to the Di~gnostic Evaluation Team (DET}

report to ascertain whether the proposed ~lans for improvement addressed the

reported.weaknesses and the root causes.

Results:

The adequacy of the licensee'~ response to the DET report.will

. require additional review since a significant number of *the i~plementation

plans were still being developed by the licensee. Appropriate Inspection

Followup Items were identified to track the additional reviews.

Five

violations were identifi~d; two non-cited examples of a previous escalated

violation for inadequate corrective actions (paragr~phs 2.3.2.a ~nd 3) and one

non-cited licensee identified example that pertained to a pressurizer l~vel *

setpoint issue (paragraph 2.1.1.a). One cited violation pertained to the

failure to perform inservice testing on check valves (paragraph 2.2.2.5.a),

and the other pertained to a lack of a 10 CFR 50.59 evaluation for a change in

the maximum allowable condens~te storage tank temperature (paragraph 2.3.2.e) .

9410070051 940929 .

PDR

ADOCK 05000255

G

PDR

DETAILS

1.

Persons Contacted

2.

2.1

• Consumers Power Company CCPCo)

• R. A. Fenech, Vice President, Nuclear Operations

• T. J. Palmisano, Plant General Manager

• R. M. Swanson, Director, NPAD

• D. W. Rogers, Safety & Licensing Director

• R. B. Kasper, Maintenance Manager

• K. P. Powers, Engineering Manager

• D. J. Malone, Radiological Services Supervisor

• Denotes those attending the exit interview conducted on

September 27, 1994.

Follow-up of Licensee Response to DET Report for Palisades Nuclear

Generating Facility (92701. 92700)

By letter dated June 15, 1994, the Executive Director of Operations,

Mr. James M. Taylor, forwarded the Diagnostic Evaluation Team {DET)

Report for the Palisades Nuclear Generating Facility to the licensee.

That letter requested the licensee to evaluate the report.and provide a

written response.

The licensee's response, dated August 11, 1994,

provided the licensee's evaluation and response to the DET report. The

licensee's response identified.long term actions to 'improve performance

which are defined in the Palisades Performance Enhancement Plan {PPEP).

During this report period, the inspectors reviewed the DET report and

the licensee's response. This review identified issues that required

further NRC review and evaluation. These items were identified as

either violations or Inspection Followup Items.

To fa~ilitate ~asy

cross referencing to the issues identified by the DET, this report

matches the format and paragraph numbers of the DET report. The

following are the results of the inspectors' review of the DET issues

and the licensee's response to those issues:

OPERATIONS AND TRAINING

2.1.1 Poor Planning and Direction By Operations Management

Operations management poorly planned or directed various plant

evolutions, process controls, and job assignments contributing to

instances of poor operator performance and operational events.

The DET

identified the following examples in this area:

a.

As discussed in a licensee corrective action report, Operations

management failed to properly plan and prepare for a pressurizer

level change during a major maintenance evolution at power.

The inspectors reviewed this issue and determined that on

January 25, 1993, in order to perform charging system maintenance,

2

the pressurizer level was raised to 67 percent indicated level for

approximately one hour.

This was accomplished by making a minor

change, using MRN-0-93-010, to the system operating procedure,

SOP-2A.

The normal operating program level was 57 percent for

full power.

The pressurizer level used in the FSAR Chapter 14

loss of external load analysis was approximately 60.25 percent.

The 67 percent setting was due to an error by a NECO engineer

providing pressurizer level information and the operations staff

in converting plant parameter data in inches to instrument

readings in percent. A review for a subsequent similar change

identified the pressurizer level discrepancy and D-PAL-93-039 was *

issued on March 2, 1993.

A reanalysis was performed using a level of 67.8 percent which

showed that maximum primary pressure would not exceed the limit of

2750 psia (110 percent of system design pressure). The level of

67.8 percent was the hot, full power pressurizer high level alarm

setpoint of 62.8 perceni plus 5 percent for instrument

uncertainty. Further evaluation by the licensee and fuels vendor

concluded that a level of 72 percent, the 67 percent indicated

level that was*temporarily used plus 5 percent instrument

uncertainty, would not have exceeded the primary system pressure

limit. This evaluation. wa~ based on conservatism included in the

analysis.

,

Failure to properly translate pressurizer level parameters used in

the accident analysis of the FSAR into system operating procedure,

SOP-2a, is considered a violation .of 10 CFR 50, Appendix B,

Criterion Ill, Design Control.

This criterion states that

measures shall be established to assure that applicable regulatory

requirements and the design basis, as defined in 10 CFR 50.2 and

as specified in the license application, are correctly translated

into specifications, drawings, procedures, and instructions.

_

However, a violation was not issued, because this violation met

the criteria for enforcement discretion in 10 CFR 2, Appendix C,

paragraph VII.B.(2). The specific corrective actions were taken

by the licensee through D-PAL-93-039 and a response to Diagnostic

Evaluation Observation (DEO) ENG-047.

The*review of the

-

corrective actions to DEO ENG~047 is considered an Inspection

Followup Item pending further NRC review (50-255/94014-01).

b.

In May 1993, station management failed to properly prepare for

flushing a hot radiation particle through a shutdown cooling heat

exchanger drain valve and filter rig. This issue was inspected

and reviewed in Inspection Report 50-255/93012.

--c.

In an attempt to shorten the time required to perform control rod

uncoupling activities, Operations management decided to perform

the evolution with two tools and two teams.

Several factors

contributed to the crew not uncoupling one control rod* in

3

June 1993 and lifting that control rod with the reactor head

during head removal.

This issue was inspected and the subject of

enforcement in Inspection Report 50-255/93016.

d.

For the control operators (COs), auxiliary operators (AOs), and

licensed AOs (LAOs) who periodically switched roles, operations

management failed to compensate through additional training,

coaching, or supervisory oversight for these personnel performing

unfamiliar licensed duties. This contributed to several operator

errors documented in the licensee's corrective action system.

The performance of operations management in the planning and direction

of plant evolutions, process controls, and job assignments is a broad

issue requiring long term evaluation. This matter is considered an

Inspection Fol.lowup Item pending further NRC review and evaluation of

the licensee's PPEP Action Plan 1.4 (50-255/94014-02).

2~1.2 Occasionally Poor Onshift Supervisory Oversight and Direction

a.

During some evolutions, onshift supervisors provided poor

oversight and direction. The DET identified the following causal

factors:

1)

Job responsibilities were not fully understood by the

onshift supervisors. There were two or three supervisors

assigned to a shift with one of the supervisors always.being

the shift supervisor (SS).* The delineation of roles and

responsibilities among the three positions was not clear,

especially for the Shift Engineer position. This matter is

considered an Inspection Followup* Item pending further NRC

review and evaluation of the licensee's PPEP Action Plans

1.2 and 1.4 (50-255/94014-03).

2)

Onshift supervisors received limited supervisory training

and coaching. This matter is considered an Inspection

Followup Item pending further NRC review and evaluation of

the licensee's PPEP Action Plans 1.4 and 3.1 (50-255/94014-

04).

.

3)

Operations management overburdened onshift supervisors with

4)

. collateral duties that potentially distracted them from

licensed responsibilities. This matter is considered an

Inspection Followup Item pending further NRC review and

evaluation of the licensee's PPEP Action Plan 1.2 (50-

255/94014-05).

.

The location of a food preparation area in the control room

was disruptive to onshift duties and the SS's cognizance of

control room activities. Also, the noise produced by the

control room ventilation was distracting to control room

personnel.

The licensee has removed the food preparation

area from the control room and has significantly reduced the

4

number of non-essential personnel passing through the SS's

office into the control room.

The noise produced by the

control room ventilation that distracts control room

personnel is considered an Inspection Followup item pending

further NRC review {50-255/94014-06).

b.

The following were examples of poor onshift supervisory oversight

and direction documented in licensee corrective action reports and

NRC inspection reports:

1)

In several instances, shift supervision performed only

cursory reviews of surveillance test results. Supervision

did not verify that all the acceptance criteria were met.

The specific examples had no safety significance.

The

adequacy of the shift supervisor's reviews of surveillance

test results is considered an Inspection Followup Item

pending further NRC review and evaluation of the licensee's

PPEP Action Plan 1.2 (50-255/94014-07).

2)

In May 1993, the SS did not effectively review operating

procedures concerning minimum reactor vessel temperature

while the head was tensioned.

The SS directed the cos to

cool the primary cooling system below the minimum

temperature limit of 70°F while the head was tensioned.

This matter is further *discussed .in an Inspection Followup

Item opened in paragraph 2~3.2.d of this report. .

3)

In September 1993, 1he SS did not monitor, control or

delineate control room responsibilities for a plant cooldown.

in response to a primary coolant system leak.

The operators

exceeded the maximum allowable cooldown rate during the

evolution. This matter is further discussed in paragraphs

2.1.5.2.c and 2.3.2.d of this report. This event was

inspected and the subject of enforcement in Inspection

Report 50-255/93030.

4)

In May 1993, three SSs in succession failed to direct the

COs to respond to a control room low hydrazine tank level

annunciator.

One of the two tank level instruments was

indicating below the *annunciator and Technical Specification

(TS) limit. Also, operators did not question the alarm

during shift turnover or take corrective action for three

shifts.

The overall performance of onshift operations shift superv1s1on

providing oversight and direction is considered an Inspection

Followup Item pending further NRC review and evaluation of the

licensee's PPEP Action Plans 1.4 and 5.1 (50-255/94014-08).

5

2.1.3 Low Expectations of Performance by Operations Management

Operations management established low or incomplete standards and

expectations for operators and did not reinforce established standards

and expectations with onshift supervisors or operators.

Some of the

areas of low standards and expectations included procedure adherence and

procedure quality, control of extraneous material within containment,

control of transient equipment, involvement in operability decisions,

material deficien*cy reporting by auxiliary operators, and log keeping

practices. This matter is considered an Inspection Followup Item

pending further NRC review and evaluation of the licensee's PPEP Action

Plans 1.3, 2.3, 2.6 and 4.1 (50-255/94014-09).

The DET re~ort identified that Operators routinely failed to maintain

configuration control due to a lack of adherence to procedures and

process controls. Furthermore, operations management did not foster

procedural adherence.

The licensee's ability to foster an environment

of procedural adherence is considered an Inspection Followup Item

pending further NRC review and evaluation of the licensee's PPEP Action

Plans 1.3, 4.1, and 4.2 (50-255/94014~10) *

. a.

The DET report identified that the procedure change process was

ineffective and not integrated. The adequacy of the procedure

change control process is considered an Inspection Followup Item

pending further NRC review (50~255/94014-11). The following were

examples where the procedure change process was ineffective:

1)

In July 1993, Operations procedure writers did not revise

the daily surveillance test procedure to include monitoring

the diesel generator (DG) 1-1 fuel oil belly tank level

after changing Standing Order 62 "Technical Specification

• interpretations/Guidance." This matter is considered an.

Inspection Followup Item pending further NRC review (50-

. 255/94014-12).

2)

In April 1992, Operations procedure writers revised system

operating, abnormal and emergency operating procedures to

direct operators to maintain the alternate steam supply

valve to 'the turbine driven auxiliary feedwater pump in the

open position. However, the governing document for valve

and breaker configuration, the system checklist, was not

revised.* Also, the piping and instrumentation diagram was

not revised. The inspectors have no further concerns with

3)

4)

this issue.

The SS inappropriately revised the operator data sheet for

the maximum temperature limit for the condensate storage

tank to 130°F. This issue is further discussed in paragraph

2.3.2.e of this report.

In March 1994, onshift supervision did not revise the fuel

oil transfer system checklist after revising the system

6

operating procedure. This matter is Gonsidered an

Inspection Followup Item pending further NRC review (50-

255/94014-13).

b.

The DET also identified in this section of the report the

following issues that require NRC followup action:

1)

2)

3)

4)

5)

Despite numerous NRC generic communications-on containment

sump blockage, the DET and later the licensee, found

substantial amounts of unrestrained and extraneous material

within the containment.

The licensee's written guidance on

containment housekeeping contained vague criteria.

An

Unresolved Item was issued pertaining to containment

housekeeping and closeout in Inspection Report 50-255/94008.

Operations supervision and ~ersonnel were generally unaware

of administrative controls involving transient equipment

• within the facility. This control of transient equipment is

considered an Inspectfon Followup Item pending further NRC

review (50-255/94014~14).

Operations management expectations regarding operability

decisions were inconsistently im~lemented and incomplete.

The licensee has initi.ated improvements in determining

operability of degraded components.

These improvement~

include defining the Shift Supervisor as the person

responsible for operability determinations. The new process

also requires more timely decisions concerning operability.

Training was also conducted to ensure site personnel were

knowledgeable of the process requirements.

The role of

Operations department personnel in the operability process

is considered an Inspection Followup Item pending further

NRC review of the effectiveness of the new process (50-

255/94014-15).

Auxiliary operators did not critically assess plant material

conditions during rounds partially due to the lack of

management*standards and expectations relative to

identifying and documenting such deficiencies. This matter .

is considered an Inspection Followup Item pending further

NRC review and evaluation of the licensee's PPEP Action

Plans 1.3, 1.4, 2.3, and 4.1 (50-255/94014-16).

Operations management had established guidance for log

content, but onshift p~rsonnel routinely omitted required

events and information as shown by three examples in the DET .*

report. The operators not maintaining logs in *ccordance *

with management expectations is considered an Inspection

Followup Item pending further NRC review and evaluation of

the licensee's PPEP Action Plans 1.4 and 5.1 (50-255/94014-

17).

7

2.1.4 Repetitive Problems with Protective Tagging

There were repetitive problems_ with personnel protective tagging.

Operators hung tags on the wrong components, prepared deficient

switching and tagging orders {STO}s for the work performed, failed to

perform required independent verifications, and made unauthorized

changes to STOs.

There were over ten examples documented in the

licensee's corrective action system of significant tagging problems

within the last two years.

The inadequate protective tagging of

equipment is considered an Inspection Followup Item pending further NRC

review and evaluation of the licensee's PPEP Action Plans 1.3, 4.1, and

5.1 {50-255/94014-18}.

2.1.5 Poor Support to Operations

2.1.5.1

2.1.5.2

Engineering Support Problems

The issues involving engineering support to operations are

discussed in paragraph 2.3.1 of this report.

Training Support Problems

Certain areas of licensed operator training were poor or

ineffective. Also, training for some duties not strictly covered

by the licensed program were poor.

The Operations department has

established a Department Master Action Plan that provides

responsibility clarification and ~ersonnel development training.

Problem areas identified by the DET in this area were:

a.

Supervisory training and coaching for Operations supervisors

were limited. This issue was previously identified as an

Inspection Followup Item in paragraph 2.1.2.a.2} of this

report.

b.

During the 1993 refueling outage, individuals qualified to

operate the spent fuel handling machine did not receive

formal proficiency evaluations prior to handling fuel. This

is considered an Inspection Followup Item pending further

NRC review (50-255/94014-19}.

c.

Before September 1993, training in operating the reactor

within allowable pressure and temperature operating regions

was ineffective, contributing to several plant overcooling

events. The overcooling events are further discussed in *

paragraph.2.1.2.b.3} of this report.

d.

OnshiTt Operations supervision received limited root cause

and event investigation training. Supervision investigated

the majority of the operational deviation reports. This is

considered an Inspection Followup Item pending further NRC

review and evaluation of the licensee's PPEP Action Plan 2.7

{50-255/94014-20} .

8

2.1.5.3

e.

Operators received limited training and written guidance on

NRC notification requirements. This is considered an

Inspection Followup Item pendin~ further NRC review and

evaluation of the licensee's PPEP Action Plan 3.1 (50-

255/94014-21}.

Licensing Support Problems

a.

Licensing provided poor*support to Operations in the areas

of technical guidance and NRC reporting.

Due to omissions,

inconsistencies, and the lack of detail identified over the

years in the original TS, the licensee developed

supplementary technical guidance to ensure operators acted

consistently when various 5ituations occurred.

The

combination of customized TS and the supplementary technical

guidance was complex and occasionally.made conservative

operating decisions by operators more difficult. Although

plant and Operations management were aware of the problem

with the TS as well as the impact on operators, aggressive

action was not taken to fully resolve the problems with TS.

This matter is considered an Inspection Followup Item

pending further NRC review and evaluation of the licensee's

PPEP Action Plan 2.6 (50-255/94014-22}.

• b.

Recommendations from Licensing were occasionally

nonconservative.

For example, the team identified that the

NRC was not notified when:

l}

The reactor vessel temperature dropped below the

minimum design requirement in May 1993. This is

further discussed in paragraph 2.1.2.b.2} of this

report.

An Inspection Followup Item is identified in

paragraph 2.3.2.d

2)

The condensate storage tank temperature increased

above the maximum assumed in the transient and

accident analysis in October 1992. This is further

discussed in paragraph 2.3.2.e of this report.

The quality of Licensing's recommendations to Operations for

reporting events is considered an Inspection Followup Item

pending further NRC review and evaluation of the licensee's -

PPEP Action Plans 1.3 and 4.1 (50-255/94014-23).

2.1.6 Weak Operations Self Assessment and Corrective Action

Operations self aJsessments as well as corrective actions to problems

identified by these self assessments were weak.

The weak Operations

self assessments is considered an Inspection Followup Item pending

further NRC review and evaluation of the licensee's PPEP Action Plan 2.3

(50-255/94014-24).

9

2.2

MAINTENANCE AND TESTING

2.2.1 Some Component Testing Was Weak

Weaknesses were noted in the licensee's testing program for

demonstrating equipment operability.

a.

The licensee's lack of understanding regarding DG starting

circuitry resulted in a failure to meet the monthly testing

requirements of TS 4.7.1 and potential undetected mechanical and

electrical component problems. This matter is further discussed

in paragraph 2.3.1.1.c and 2.3~1.2.c of this report.

b.

Root cause evaluations performed by Maintenance and Engineering

for slow DG start times were superficial. See paragraph

2.3.1.2.c.

c.

The following weaknesses were identified by the DET during a

monthly test of DG 1-1:

1)

Preconditioning of DG 1-1 which included cranking the engine

twice for 5 seconds prior to the start of the test, without

acquiring relief from the TS, or waiting for a period of

time after cranking to ensure the diesel is not

preconditioned.

_2)

The pressure gauge used for determining the differential

pressure (dp) across the lube oil strainer on the DG engine

was over-ranged.

The instrument range.was 0 to 100 psi,

while the extrapolated reading was -103 psi with no

acceptance criteria identified for the dp across the lube

oil strainer ..

The above matters .are considered an Inspection Followup Item

pending NRC review (50-255/94014-25).

d.

During a review of a containment air cooler (CAC) performance test

T-318, the licensee identified questionable testing practices.

This issue was reviewed in Inspection Report 50-255/94011,

paragraph 3.2.3. The licensee concluded that the effects of test

problems on the system were not significant and returned the CACs

to a leak free condition.

The inspectors had no further concerns.

2.2.2 Pump and Valve Testing Weaknesses

The following weaknesses were identified by the DET in the testing of

some pumps and valves under the inservice testing (IST) program required

by Section XI of the American Society of Mechanical Engineers Boiler and

Pressure Vessel Code (Section XI).

10

2.2.2.1.

Acceptability of Some Inservice Pump Test Parameters and Results

Not Confirmed

a.

The DET had a concern with the inservice testing of

component cooling water (CCW} pumps (P-52A, B and C} during

testing of one-pump or combined two-pump tests (Q0-15} that

had been judged to be acceptable by the licensee. The

licensee's acceptance was based on comparing d/p values

across the CCW heat exchangers and relating the values to

CCW flow rates from curves developed in 1988 from a special

CCW test (T-213).

The inspectors reviewed the testing of the CCW pumps.

The

T-213 test was run with one pump and one heat exchanger,

which produced a curve to correlate system flow with heat

exchanger d/p. This d/p was then used as the fixed

reference point in the IST test and compared to pump d/p.

For the two pump combination, the flow rate was doubled as

the heat exchanger d/p should remain approximately the same

with two heat exchangers in service. The specific reference

value selected when at some substantial flow was not

relevant as long as the test results were repeatable since

the test was performed to identify pump degradation. Heat

exchanger degradation should be minimal since the CCW flow

was on the heat exchanger shell side rather than though the

tubes, which would not cause tube fouling or plugging.

The licensee also performed test procedure T-223, which was

a flow balance of the CCW system each refueling outage to

verify proper flows to different components during several

scenarios.

The test method was adequate to test the CCW pumps as

required by the Code for determining pump degradation.

Rerunning T-213 should provide verification for the heat

exchanger d/p and CCW flow correlation. The licensee agreed

to rerun T-213 this year.

The DET also identified that during a licensee review in

late 1993, two questions were identified with the curve

developed by T-213.

These were documented on D-PAL-93-272

in January 1994.

First, the curve did not take the expected

hyperbolic shape, but was more of a straight line.

1The

second question concerned the lack of verification of valve

positions in the test flow path.

The inspectors concluded that the curve developed by T-213

was only a partial curve, especially at the *1ower end

(starting at 2800 gpm}, possibly accounting for the loss of

curve shape.

The difference between the actual curve

developed and the calculated hyperbolic curve was not

significant.

To bound the design requirements of the CCW

11

pumps~ a 20 percent pump flow degradation was taken for the

contafnment cooling analysis that showed the pumps were

capable of removing ~esign heat loads. The re-performance

of T-213 should develop a new curve having the proper shape

and verify the positions of the CCW inlet valves to the

heat exchanger.

Based on the bounding analysis, the

corrective actions for the 0-PAL was not required to be

completed until December 1994.

Pending the re-performance

of T-213, this matter is considered an Inspection Followup

Item (50-255/94014-26).

b.

The DET identified that test procedure Q0-15 did not specify

an acceptance range for pump discharge pressure, pump

differential pressure, pump flow, or motor amperage.

The

test data showed flow values (using instrumentation which

the licensee concluded produced erroneous results) over the

last two years that were considerably less than the pump

reference values. However, the licensee appropriately

relied on the d/p readings across the CCW heat exchangers as

in indication of valid test results.

With the exception of pump discharge pressure and motor

amperage, the data points identified were recorded during

the test performance for information only as stated in the

basis document for Q0-15.

An acceptance criteria was not

required for pump discharge pressure~ which was used to

determine pump d/p in Attachment 1 of Q0-15 .. The attachment

did have acceptance criteria for pump d/p as required by the

Code.

Recording motor amperage was not a Code requirement,

although an acceptance range may be appropriate.

As stated

by the DET, heat exchanger d/p w~s the fixed reference value

in lieu of pump flow and the test procedure contained

adequate acceptance criteria for this value. No further

action is required.

c.

The DET identified a concern that certain pumps were not

tested at full design flow during inservice testing .

The Code does not require IST to be performed under full

design flow conditions. Specifically, IWP-4100 states that

"where a pump cannot practically be tested in its regular

circuit, a bypass loop may be used."

As such, the inservice

testing performed was in accordance with Code requirements,

although the pumps may degrade to a point where they would

not meet their design requirements, but pass the IST test.

Testing at the higher flow rates was scheduled to be

performed every 10 years. The LPSI pumps were tested in

1989 per procedure T-261, which indicated that pumps P-67A

and B were capable of meeting their design function.

The CS

pumps were tested in 1992 at 1000 gpm (design capacity is

1340 gpm at 450 ft (injection) and 1800 gpm at 405 ft

(recirculation)), which provided a data point beyond the

12

flat portion of the curve to ensure the pumps were capable

of meeting their design function.

Unresolved item (50-

255/92028-01 (DRS concerned a similar issue and was. being . addressed by NRR. No further action is required. d. The DET identified a concern with inconsistencies between the pump vibration results of the IST program and the predictive maintenance program. The inspectors reviewed the inservice test program and determined that the velocity vibration measurements obtained for pumps were in root-mean-square (RMS} inches per second values. The acceptance criteria in the IST procedures are based on RMS values. The Predictive Maintenance Program uses spectral analysis for a more complete vibration analysis which reads in inches per second peak rather than RMS. RMS values, compared to peak values, are the peak values times the sin of 45 degrees, or 0.707 x peak. The examples. listed above would be compared as follows:

• pump*

IST !RMS} PM !PEAK} PM CRMSl P-55C . 31 ips . * .43 i ps . .30 ips P-54A .255 ips .35 ips .25 ips P-548 .286 i ps .43 ips .30 ips_ P-54C .268 ips .35 ips .25 ips Therefore, the concern appea~s to be based on the differenc~ in the units of vibr~tion. The vibration inst~~ment used * has bar codes that select RMS or peak and displays the units, such as "RMS IN/S." The same accelerometer was used for both measurements. The spectra analysis identified the peaks at all the frequencies while the RMS value takes all the peaks and II averages II the peaks' thus an RMS value will always be less than a peak value. A review of EM-30, "Plant Predictive Maintenance Program," indicates that Section 5.1.4.d. specified that if overall vibration levels indicate a potential problem (> 0.3 inches per second or 100 percent increase), vibration signatures should be evaluated for cause. A new paragraph had been added to Section 5.1.6, "Corrective Action and Follow-up," to require initiation of a condition report based on vibration of> 10 mils for the main turbine and the P-50 pumps and > 0.6 inches per second for all other equipment. The fourth quarter predictive maintenance report was issued March 10, 1994. The report notes low to medium severity vibration levels on five pumps in the IST program. For the 13

• ,

2.2.2.2 pumps listed above with vibration meas~rements of 0.43 ips {P-55C and P-548), the report indicates planned action of "continue to monitor." There is no requirement to tie the predictive maintenance program to IST. When the maintenance rule {10 CFR 50.65) becomes effective in 1996, there will be advantages to consolidating programs and relying on data from each type of testing to "monitor" components. Additionally, the ASME O&M Committee is currently working on a Code case that will allow the use of spectral analysis to remove a pump from increased frequency testing under certain conditions. Also of note is that the upper limit for vibration in inches per second-peak as specified in OM-6, "Inservice Testing of Pumps in Light-Water Reactor Power Plants," is 0.700 ips. No further action is required. Motor-Operated Valve Inservice Testing Weaknesses lhe DEJ identified the following issues pertaining to the IST program for MOVs. a. Engineering had not effectively pursued the root causes {not specifically required by Section XI, but a good practice) of mariy MOVs that experienced highly varying stroke times for several months, although the valves did not reach the alert range. The.valves were placed on increased frequency testing when the variations were noticed. Examples included M0-3082, M0-3083, M0-1042A, and M0-1043A. Eventually the stroke time trends stabilized without the need to perform repairs and the testing frequency was changed to quarterly. The test results recorded on July 19, 1993, for the above - mentioned valves and many additional valves were inconsistent with previous and subsequent measurements. It appeared that-the data recorded on this day was erroneous. The licensee was unable to identify the cause of the erroneous data. Since the timing data returned to normal for most valves after this test, no further action was required. The IST stroke time trending database, especially the note section, needs to better reflect conditions and problems as when identified. Also, investigations into the problems should be addressed and documented. b. Based on incomplete information from the licensee, the DET concluded that the ISi group was unaware of a modification which changed operator gear ratios on some HPSI MOVs {M0- 3062, M0-3064, M0-3066, and M0-3068) in June 1993. The inspectors reviewed this issue and determined that the gear changes were performed under Specification Change SC- 93-050. IST engineers did review the post-modification test 14

..

procedure Q0-5 results that placed the valves back in service in August 1993. There was no increase in stroke time during the test or the subsequent quarterly test in September that would require the reference values to be changed. Thus the ISi group was aware of the post modification valve configurations through test results, although they may not have received the SC memo concerning the gear change. The actions taken by the IST coordinator were appropriate based on the test results. The valve stroke time for two of the valves went into the alert range in December 1993. The licensee is reviewing the data to determine the cause of the timing increase. The root cause of the stroke time increase is considered an Inspection Followup Item (50-255/94014-27). The database for IST, especially the note section, needs to better reflect conditions as they arise. For example, a note after the post-modification test should indicate the SC change and that the reference value did not require changing was reverified as required by the Code. The process for ensuring that the ISi group receives and reviews test results was not very formal. The work order cover sheet contains a reference to ISi, "yes/no". There were no required signoffs that the ISi group reviewed the initial package to determine what testing was required or that the completed test results were acceptable. The WO, however, did contain the required testing and the test results were reviewed by ISi for acceptability and placed in the IST database. c. The DET was ~oncerned that. there was not a defined and clearly documented relationship between the safety analyses and the valve stroke times. All reference values had been established as the mean stroke time for each valve. During the evaluation, the licensee indicated that the acceptance criteria used in the tests were bounded by assumptions made in the safety analyses. d. A more in depth study was to be completed by January 1995. In addition, stroke times achieved were within indicated design allowable. No further action is required. The DET identified that the MOV trending database was incomplete and not integrated. Engineering could not easily determine from the trending data when a recorded stroke time was performed to document a new reference test or when increased testing had been performed. Trend data also did not indicate whether the alert or action ranges had been exceeded. The licensee had planned to update their data management capabilities for IST parameters . 15

2.2.2.3 The inspectors reviewed MOV trending data in either tabular format or graphs. The computer software is limited in that previous reference values cannot be shown graphically. However, the graphs do indicate acceptance criteria for alert and action leveli. The inspectors concluded trending of the*IST stroke times was available. Air~Operated Valve Testing Weaknesses The DET was concerned that the licensee did not have a coordinated plan for the maintenance and testing of AOVs. The licensee had accumulated some information over the last two years on AOVs prior to issuing an AOV Program Plan on March 22, 1994. Completion .. dates for the milestones ranged from December 1994 through April 1998. Several of these milestones have the potential to initiate new or revised AOV testing and maintenance requirements. The inspectors reviewed the status of the licensee's ADV program and determined that the AOVs which were ASME Code Class 1, 2, or 3, and have active safety functions would be within the scope of the IST program. The litensee has been active in establishing a AOV program. The following is a history of the licensee's AOV program: 08/92 10/92 04/93 05/93 07/93 35 AOVs walked down this month and information entered into the AOV program database. Only one control valve

• listed for repair for the 1995 ref~eling outage

remains to be walked down. A total of 149 AOVs have been walked down for installed verification and collection of design data. ADV program is being applied in an effort to reduce the number of unnecessary AOV diaphragm replacemerits. ADV program evaluated "qualified life" of diaphragms installed in AOVs. The new AOV program database has had all the data from the old database transferred. A personnel requisition was requested January 7, 1994, for an ADV engineer. On May 31, 1994, an engineer was named ADV Program Manager for Palisades and management approved membership on the O&M working group on AOVs {OM-19). The AOVs were in a database and could be trended. The DET was concerned that for those AOVs that were tested in the IST program there was not a defined and clearly documented relationship between the safety analyses and stroke times. Approximately 180 AOVs were in the IST program. 16

t. 2.2.2.4 2.2.2.5 a.

The inspectors reviewed Section 5.3.l(c) of .the Palisades IST Program and determined that the program addresses the limiting stroke times for valves, stating that the limiting value shall be_ the lesser of the minimum Technical Specification or FSAR value or a calculated value based on the valve reference stroke time, . consistent with Position 5 of Generic Letter 89-04. However, subsequent to this issue* being identified by the DET, the licensee identified that feedwater regulating valves (FRVs), CV-0701 and CV-0703 had limiting stroke times above the limiting value of an analysis performed by the safety analysis group following steam generator replacements. The stroke time for valve closure in the analysis was assumed to be 20.5 seconds or less, b~t Test Procedure Q0-6 included a limit of 24 seconds based on the reference values of the two valves. The licensees verified that in* all conditions when the valves were required to be operable, the measured stroke times were less than 20.5 seconds. The license determined that the cause was the valve stroke time information submitted to the IST group by the design engineer after the installation and testing of modification FC-906

• (5/10/90), pertaining to the flow controlle*r for the feedwater

regulating valves. The information stated that the "stroke times are well below the 30 second stroke time assumed in the Chapter 14 analysis." The valves were added to the IST prqcedure (prior to the* modification, these valves were ~ot in the IST program) a~d the limiting stroke time was based on the calculated value from the reference stroke time because 24 seconds was lower than 30 seconds, which was b~lieved to be the li*it in the SAR. Test

• Procedure Q0-6 has been revised to include the.correct limiting
• stroke time of 20.5 seconds.

Because no other valves were identified with limiting stroke times above the.technical specification or SAR limit, this one instance was considered an. isolated event and wa~ adequately resolved. Incomplete Relief Valve Testing Data The DET noted that extensive information regarding relief valve design and testing was developed by the licensee in 1992. However, the licensee was unable to recover this data for its own use or the team's review. 'Although no specific concerns were identified, the licensee should* verify that relief valve data sheets accurately reflect their design requirements. This matter is considered an Inspection Followup Item pending licensee review of relief valves in the IST program (50-255/94014-28). Instances of Check Valve Testing and Maintenance Scope Weaknesses In the IST area, the DET identified an instance where the licensee failed to test, at full-flow conditions, check valves CVC2138 and 17

. b. 2.2.2.6

CVC2139, which were located in the flow patn from the boric acid injection to charging pump suction. The IST program indicated Q0-18 performed the required test, however, a revision to the procedure changed the flow path. Because of the change, full-flow testing of the check valves was not performed as required by Section XI. This did not appear to indicate a programmatic problem, but rather an error related to the attempts to instrument the lines. Failure to test the check valves to the full flow open position is considered a violation of the ASME Code, Section XI (255/94014-29). Q0-18 was revised and successfully completed in May 1994 to full- stro~e these check valves as required for inservice testing. *The licensee developed, as* part of its performance enhancement plan, an action to review test procedures to ensure that check valves were adequately tested .. There was also an ongoing effort by the.licensee as a result of an earlier NRC inspection to verify that all check .valves were appropriately tested. Since corrective action~ have been implemented or were in process,* no r~sponse will be required to the violation.

The Check Valve Program focused primarily on disassembly and inspection requirements for safety-related and nonsafety-related check valves. In April 1994, the licensee identified several problems with check valves in the reactor cavity dratn lines and * in the AFW and EOG rooms. This issue was reviewed in Inspection Report 50-255/94011, paragraph 3.2.4. and the licensee's corrective actions were found adequate. Many Important Manual Valves Not Periodically Tested The DET identified one manual valve relied on in EOPs that was not tested to verify it would function. The licensee reviewed the EOPs and identified 16 additional manual valves that were relied upon. The inspectors reviewed this issue and determined that manual valves in Code Class 1, 2, or 3 systems were required to be in the IST program if the valves were credited in the safety analysis (Q) for the capability of being repositioned to shutdown the plant, to maintain the plant in*a safe shutdown condition, or to mitigate the consequences of an accident. Valves that were included in EOPs were not necessarily credited in the safety analysts .. EOPs were written with several levels of actions beyond the analyzed actions. Periodic stroking of manual valves in the EOPs that were not in the IST program would be a good practice. The licensee reviewed the 17 manual valves in the EOPs for safety functions with the following results: 18

MV-FW-150 MV-FW-750A MV-FW-759 MV-FW-750 MV-FW-774 MV-FW-775 MV-FW-504 MV-DMW-138 MV-DMW-142 MV-DRW-774 MV-FP-131 MV-FP-130 MV-AE-100 MV-CD-136 MV-CD-133 MV-CD-130 MV-CD-138 "Q" for open and closed function "Q" for open and closed function -" Q" for c 1 osed function "Q" for open function "Q" for open function "Q" for open function "Q" for closed function ~Q" for open and closed function "Q" for open and closed function No "Q" function "Q" for open and closed function "Q" f6r open and closed function No "Q" function No "Q" function No "Q" function No "Q" function No "Q" function Valves FW-750/750A/759 were exercised by procedure Q0-21, "Auxiliary Feedwater System Valves, Inservice Test Procedure." FP-130 and 131 were exercised per procedure R0-52, "Fire Suppression Water System Functional Test and Fire Pump Capacity Test." Valves FW-504, *774 and 775 were stroked on May 10, 1994 under procedure T-345 and added to Q0-21. *The remaining Q and non-Q manual valves on the list were stroked on May 11, 1994. The safety function of FW~l50 was evaluated and the v~lve was declared inoperable. FW~l50 was then stroked prio~ to ~eclaring the valve operable. . . With the exception of FW-150, the other valves have been added to the preventive maintenance program or are included in a test . procedure* to exercise the valve. FW-150 was exercised during this outage and a determination will be made if it needs to be included~ in the IST program or a PPAC. These actions appear to adequately address the issue. The resolution of FW-150 is* considered an Inspection Followup Item pending determination of s*afety.

• classification (50-255/94014~30).

2.2.3 Weak Maintenance Work Practices Oversight of maintenance activities by supervisors and managers through observing in-process work was consistently low. This contributed to; procedural adherence problems by personnel performing maintenance * activities and ,a failure to acquire engineering assistance to evaluate problems in some instances. This matter is considered an Inspection ' Followup Item pending further NRC review and evaluation of the lic~nsee's PPEP Action Plans 1.3, 1.4, 4.1, and 5.1 (50-25~/94014-31). In addition, poor support from Engineering contributed to inadequate maintenance work procedures and poor root cause evaluations. This matter is considered an Inspection .Followup Item pending further NRC 19

review and evaluation of the licensee's PPEP Action Plans 2.3 and 2.7 (50-255/94014-32). The following were considered of weak maintenance work practices: a. Poor procedures and work reviews resulted in an unapproved pump modification which permanently installed alignment plates and adjusting bolts on multiple safety and nonsafety-related pumps. This issue was resolved during the DET. b. While completing a work order (WO) to adjust the stroke of a main feedwater regulating valve on March 24, 1994, I&C craft completed the calibration sheet inaccurately. The DET noted several weaknesses and poor practices in calibration sheet accuracy and control of design basis information, technician understanding of and management guidance on calibration sheet "control action" sections, appropriate questioning attitudes among maintenance personnel, and adequacy of administrative reviews. This was reviewed in Inspection Report 50-255/94011, paragraph 3.1.5 with no further concerns identified. c. In February 1993, during repair of #3 cylinder for the variable speed charging pump (P-55A), several broken parts were found throughout the system, but a thorough search and complete parts inventory was not conducted. The issue of foreign material exclusion is considered an Inspection Followup Item pending further NRC review (50-255/94014-33). d. The AFW alternate steam supply valve (CV-0521) *was sometimes rapped with a 3-pound hammer (determined as an acceptable practice by a system engineer) to help the valve move to the open position when the disk became stuck in the seat. The licensee's corrective action included specifying that the valve be kept *normally open. This item is discussed further in paragraph* 2.3.1~2.b. e. The DG 1-1 engine-driven fuel oil (FO) pump was replaced without using the design-required alignment dowels. As a result of the DET's concern, a 50.59 was performed that determined the modification of the FO pump was acceptable. The inspectors have no further concerns in this area. 2.2.4 Some Material Condition Deficiencies Not Identified and Documented Several material deficiencies existed due, in part, to not communicating performance standards and expectations. This matter is considered an Inspection Followup Item pending further NRC review and evaluation of ~he licensee's PPEP Action Plan 2.6 (50-255/94014-34). The examples identified by the DET included the following: a. The color of the bearing sight glass oil was significantly darker than the oil in the bubbler for containment spray pump motors (P- 54A and P-548). The licensee issued a deficiency report to revise the PM activity for performing the oil analysis preventive 20

Q maintenance (PM) on all associated motors o~site. The licensee changed the oil in pumps P-54A and P-548. The licensee's root cause for the darker oil will be reviewed by the NRC and is considered an Inspection Followup Item (50-255/94014-35). b. There were multiple hanger deficiencies including loose or missing hanger fasteners, loose base plate bolts, tracks in a wall caused by embedded support bolts, and missing fasteners on large structural supports in the CCW room. This issue was reviewed in Inspection Report 50-255/94011, paragraph 3.2.1, with no new concerns identified. c. There were several hardware deficiencies on EDGs 1-1 and 1-2 such as insufficient fastener engagement on the air intake ~ilencers, missing or loose fasteners and broken brackets connected to the jacket cooling water lines and the DG exhaust shroud, and a leaking DG exhaust manifold. The inspectors verified that the licensee corrected these hardware deficiencies prior to the June 1994 plant startup. d. Some spring can hanger supports were loose, did not have cold and hot settings marked on the can, or appeared improperly set. These items were included in the inspector review in paragraph b. above. e. Main steam isolation valves were missing actuator support fasteners, presumed by the licensee to have not been reinstalled after completing a modification several years ago. This issue was addressed in Inspection Report 50-255/94011, paragraph 3.2.1, with no additional concerns being ideritified. f. An AFW pump was missing a support bracket for the bearing cooling water line. The licensee has installed a support bracket. The licensee determined that the cooling water line was still operable with the missing bracket. The licensee will be conducting a training program to increase the sensitivity of plant personnel to identify deficiencies during plant tours. The inspectors had no further concerns on this matter. g. Vendor rep.orts regarding degraded material condition concerns for

• the EDGs and AFW turbine driver were not formally documented and

evaluated. The Vendor Information Program did not ensure that updated vendor information was routinely requested, evaluated, or incorporated into maintenance activities. This matter is further discussed in paragraph 2.3.5.d of this report. 2.2.5 Poorly Controlled Warehouse Storage of Safety-Related Material Numerous fundamental weaknesses were identified regarding material control and supply of parts from the warehouse because of a lack of adequate management oversight of the warehouse facility. This matter is 21

considered an Inspection Followup Item pending further NRC review and evaluation of the licensee's PPEP Action Plans 1.4 and 5.1 (50- 255/94014-36). 2.2.6 Poor Support for Preventive Maintenance Impacted Equipment Performance Poor support for PM activities was evidenced by identified equipment problems and lack of control of the licensee's program. The licensee will be performing a. PM opt imi zat ion on three pil at systems. * An evaluation of PM optimization will be performed prior to proceeding with other systems. The effectiveness of the licensee's PM program is considered an Inspection Followup Item pending further NRC review and evaluation of the licensee's PPEP Action. Plan 2.5 (50-255/94014-37). The following issues were identified by the DET and will be further evaluated by the NRC during the followup of the preceding identified Inspection Followup Item: a. Reac~or cavity drain check valves (having no PM) were found clogged with debris causing them to be declared inoperable. This issue was reviewed.in Inspection Report 50-255/94011, paragraph 3.2.4. b. A CS pump was found with contaminated oil and was declared inoperable. This issue is further discussed in paragraph 2.2.4.a of .this report. c. A charging pump experienced a catastrophic failure in 1993 after a PM (which was originally issued to prevent a repeat failure of an* earlier similar occurrence) was eliminated in 1990. This issue is d. further discussed. in paragraph 2.2.3.c of this report. Inverter transformers were imbalanced because of reduced voltages and lack of PM. Licensee tests of the inverters in 1994 indicated that they could perform adequately provided their associated transformers were kept balanced through periodic maintenance. e. Three of four inverters were operating with insulation that had exceeded its specified life by several years. f. EOG air receiver b1owdown valves were found clogged with scaling. g. A General Electric model SMB hand switch failed because of oxide buildup which led to identification of six Class IE hand .switches installed in various systems with similar accumulated oxide. h. An emergency escape airlock equalizing valve stuck open because of the lubricant becoming tacky from infrequent use. i. Temperature controllers for the containment air coolers were not properly calibrated and maintained. 22 '*

j. The motor bearing for a CAC air cooler was being allowed to run to failure (according to work package documentation) rather than performing the PM activity to grease the bearing. 2.2.7 Weak Maintenance Work Order Tracking And Reporting The licensee's work control process exhibited weaknesses in tracking and reporting. The licensee's work control process is considered an Inspection Followup Item pending further NRC review and evaluation of the licensee's PPEP Action Plans 1.3, 1.5, 2.2, and 2.5 (50-255/94014- 38). The following issues pertaining to the work control process were identified by the DET and will be further evaluated by the NRC during the followup of the preceding identified Inspection Followup Item: a. Some work requests were not entered into. the Advanced Maintenance Management System (AMMS) in a timely manner as required; among otheri, a group of 28 work requests (25 were Q-listed), pertaining to thermal overload settings for breakers for various equipment. The issue of thermal overloads was reviewed in Inspection Report 255/94011, paragraph 2.Z. *This item was the subject of enforcement in 1993 and .Inspection Report 50-255/93016. b. More than two-thirds of the WO backlog (approximately 1650) were not ready to be worked. This issue was reviewed in Inspection Report 50-255/94011, paragraph 3.5. c. The licensee's management information system indicated that similar numbers of preventive and corrective maintenance (CM) activities were performed. However, the number of PM activities was actually lower because the licensee considered many corrective maintenance activities on degraded (but not failed) equipment as PM. This resulted in a more favorable PM-to-CM ratio than was actually occurring. 2.3 * ENGINEERING AND TECHNICAL SUPPORT The roles and responsibilities of the two onsite engineering organizations and the interfaces between them were not well defined.

• Authority was not clear and accountability was not maintained.

Some system engineers assumed total ownership of systems, while others exercised very little. Standards and expectations were not effectively developed and communicated. This matter is considered an Inspection Followup Item pending further NRC review and evaluation of the licensee's PPEP Action Plans 1.2, 1.3, 4.1, and 4.2 (50-255/94014-39). 2.3.1 Plant Support From Engineering Often Weak Support to the plant from both Nuclear Engineering and Construction (NECO) and Systems Engineering (collectively referred to as Engineering) was often weak. Causes of weak plant support by Engineering were historically incomplete design basis information, and a tendency to perform evaluations and institute administrative controls as corrective 23

...

actions instead of correcting plant hardware deficiencies. These causes of weak engineering support are considered an Inspection Followup Item pendi~g further NRC review and evaluation of the licensee's PPEP Action Plans 1.3, 4.1, 4.2, and 6.1 (50-255/94014-40}. 2.3.1.1 Evaluations in Support of Operability Determinations Untimely and of Poor Quality in Several Instances Factors which contributed to poor engineering evaluations were a poorly defined operability process and engineers' lack of understanding of the design bases. There was a general weakness at all levels concerning training of engineers in evaluating degraded equipment for operability. This matter is considered an Inspection Followup Item pending further NRC review and evaluation of the' licensee's PPEP Action Plans 2.3, 2.6, 3.1, and 4.2 {50- 255/94014-41}. The following were examples that demonstrated weaknesses in Engineering's evaluations. a. On February 10, 1994, during a walk-down of cable trays, as part of an Appendix R review, the licensee discovered tha~ the separation barriers were missing for the reactor protection system {RPS} channels 1 and 3 for cables located in the same cable tray .. The original operability determination was flawed and potentially incorrect. This issue was reviewed in Inspection Report 255/94011, Section 3.1.1, with no further concerns identified for cable separation. b. Operability .eva 1 uat ions of the emergency di es el generator {EOG) fuel oil transfer system performed in October of 1993 and while the OET was onsite in April of 1~94, were untimel1 and of poor quality. This issue was reviewed in Inspection Report 255/94011, Section 3.1.8 b., and .resolution was . documented in licensee submittals to the NRC dated May 23 and June 3, 1994, that specified. the compensatory.actions taken and proposed actions towards restoration of full system qualification. c. The OET found that the design of the EOG dual air start circuits, that were intended to be redundant on each .EOG, made both EOGs susceptible to loss of automatic start capability following certain single failures when the "A" start circuit of either one of the EOGs was already* degraded. The inspectors reviewed this issue and determined that Technical Specification {TS) 4.7.1.a required each diesel

• generator to be manually started each month and to be ready

for loading within 10 seconds. The signal initiated to start the diesel was varied from one test to another to 24

(' verify that "A" and "B" starting circuits were operable. In October 1993, Diesel Generator {DG} No. 1-2 was started using the "A" start circuit. The DG start time was 10.5 . seconds which exceeded the TS. However, the licensee did not declare the DG inoperable. The DG was restarted using both starting circuits in 7.08 seconds. The inspectors concluded the licensee lacked* a full understanding of the DG's starting circuit. The DET inspection identified that losing Battery No. 1 {single failure} would fail DG No. 1-1 and the 'B' start circuit for DG No. 1-2. Only the "A" start circuit would be available to start DG No. 1-2. The increased DG loading time {10.5 .seconds} would increase safeguards loads starting times assumed in FSAR Table 8-7, "Diesel No. 1-2 Sequence Start." DG load sequencing ensures the DG can start and accelerate safeguards loads, and that initial operating times, such as pumps at full flow conditions, meet the times assumed in FSAR Chapter 14, "Safety Analysis." The "A" start circuit acceptance criteria was 9.5 seconds. This provided a 0.5 second margin for relay and testing personnel response time. Therefore, the worst case October 1993 DG No. 1-2 start time would be 11 seconds. The following table compares the actual starting times for safeguards equipment identified in FSAR Table 14.18.1-2, "LOCA Analysis Engineered Safeguards Equipment Alignment," for a DG No. 1-1 failure. FSAR SURVEILLANCE FSAR TABLE EQUIPMENT Table 8-7 MEASURED 14.18.1-2 TIME Spray Pump P-54A 12.0 12.994 60.5. Air Cooling Fan V-3A 12.0 12.994 16.0 HPSI Pump P-66A 16.0 16.993 30.0 LPSI Pump P-67A 23.0 23.987 30.0 Air Cooling Fan V-lA 29.0 30.003 33.0 Air Cooling Fan V-2A . 29.0 30.003 33.0 o Table 8-7 includes 10 second maximum DG start time plus ideal sequencer times. o Table 14.18.1-2 are the initial equipment operating times. 25

2.3.1.2. o Surveillance measured time includes 10.5 second DG 'A' start circuit time plus 0.5 second testing personnel response time plus actual sequencer times .. For the above equipment, the times assumed in the safety analysis (Table 14.18.1-2} were not exceeded. The inspectors concluded the degraded 'A' start circuit would start DG No. 1-2 in time to mitigate the design basis accidents analyzed in the safety analysis. In a letter dated June 1, 1994, the licensee changed the acceptance criteria in Surveillance Procedure No. M0-7A-l, "Emergency Dies~l Generator 1-1 (K-6A}" and No. M0-7A-2, "E~ergency Diesel Generator 1-2 (K-68)," to declare the DG inop~rable if tha 'A' start circuit time was > 9.5 seconds. If the elapsed time was >*9.5 seconds for the '8' start circuit, then a second start was required using only the 'A' circuit. These changes were acceptable to the inspectors. A modification to change the air start motors actuation circuits was proposed for the 1995 refueling outage and is considered an Inspection Followup Item pending review by the NRC (50-255/94014-42). This issue is further discussed in paragraphs 2.2.1.a and 2.3.1.2.c .of this report. d. NECO, in late 1992, found a safety-related inverter had signi.fican~ harmonic distor:tion on its AC output. The inspectors reviewed this condition in Inspection Report 50-255/94011, Section 3.1.2, and concluded that the licensee's corrective action was adequate. The inspectors had no further concerns. e. Inservice Test (IST) surveillance tests for LPSI pump P-678 using procedure Q0-20 on January 22, 1993, and for AFW pump P-BC using procedure M0-388 on December 16, 1993, were

performed with the subject pumps not being run for a minimum of five minutes prior to taking data. The licensee identified these in their corrective action system, evaluated the occurrences as ~ot affecting the surveillance data, and took corrective actions. *The inspectors reviewed the actions taken and had no further concerns. Root Cause Analyses Often Weak or Untimely Multiple repeat failures of safety-related equipment often occurred before the root cause was identified. A lack of training on root cause analyses and a lack of emphasis and resource

allocation by. management were contributing causes for weak or untimely root cause analyses~ This matter is considered an 26

2.3.1.3

Inspection Followup Item pending further NRC* review and evaluation of the licensee's PPEP Action Plans 2.2, 2.6, 3.1, and 4.2 (50- 255/94014-43}. a. A DG operated for at least 20 months with a faulty voltage regulator. The faulty regulator was corrected. The licensee identified the cause as a loose solder connection that was repaired. The loose solder connection was a result of vibration and thermal aging. This matter is considered an Inspection Followup Item pending further NRC review of the licensee's preventive maintenance program for the voltage regulator (50-255/94014-44}. b. The AFW alternate steam supply valve, air-op~rated valve (AOV} CV-0521, had been unreliable, on both opening and closing, since 1988. This issue was reviewed in Inspection Report 255/94011, Section 3.2.7.f, which identified that the licensee now maintains the valve in the open position. One function of the valve was to provide a low suction pressure AFW turbine trip. The licensee has established interim measures that include operator action to close another supply valve when low suction pressure occurs. The licensee plans to modify the low suction pressure trip in the next refueling outage. This matter is considered an Inspection Followup Item pending the installation of the modification for the low suction pressure trip (50-255/94014~45}. c. Root cause evaluations, by Systems Engineering, of the slow DG start times associated with EOG 1-2 air start motor "A" were* poor. This issue is discussed in paragraph 2.2.1.b of this report. The root cause evaluation for the slow starts is considered an Inspection Followup Item pending NRC review (50-255/94014-46}. Poor Support for Procedures and Instructions Engineering support for revising the plant operating and maintenance procedures was poor. Management expectations on procedural compliance and reporting of inadequate procedures were unclear and inconsistent. This matter is considered an Inspection Followup Item pending further NRC review and evaluation of the licensee's PPEP Action Plans 1.3 and 4.1 (50-255/94014-47). Poor procedural support had the potential to result in plant* transients or damaged equipment, questionable operability of equipment, and confused guidance to operators, as well as other problems. Examples were:

a.

• The engineering controls for assuring that operating

procedures were appropriately revised following plant modifications were weak. Certain modifications were installed and placed in service without the development of 27

2.3.1.4 the associated operating procedures. This matter is considered an Inspection Followup Item pending further NRC review and evaluation of the licensee's PPEP Action Plan 2.4 {50-255/94014-48). b. In November 1992, Engineering identified as part of its. design basis reconstitution effort that the EOPs needed to be revised in three different areas due to concerns with the . size of the cross-connect line between two tanks {T-81 and T-2) that supplied water to the AFW pump suctions. This matter is considered an Inspection Followup Item pending NRC review of the EOPs {50-255/94014-49). c. Prior to March 1994, when a .new procedure was issued, there were several questionable maintenance practices during the installation of the new turbine driver for AFW pump P-88. This was reviewed in Inspection Report 255/94011, paragraph 3.2.7., with no concerns being identified. d. The fuel oil transfer pump surveillance test procedure M0-7C did not verify pump operability because the procedure lacked . quantitative.acceptance criteria. The licensee planned to. revise the procedure. This matter is considered an Inspection Followup Item pending further NRC review {50-

• . 255/94014-50).

e. The modification {SC-92-127) in mid-1993 to solve the speed and pressure oscillations of the turbine-drivei AFW pump was only partially effective. Incorrect installation caused by poor installation instructions from Systems Engineering resulted in improper response of the AFW flow instrumentation under actual flow conditions. These conditions were corrected and the inspectors have no further concerns. Poor Contractor Control bv Engineering There was often poor oversight over contractors' work, including ineffective technical reviews of work products. This matter is considered an Inspection Followup Item pending further.NRC review and evaluation of the licensee's PPEP Action Plans 1.6 and 3.1 (50-255/94014-51). 2.3.2 Resolution of Some Equipment and System Problems Untimely and Ineffective Many problems were identified to Engineering; however, Engineering was often slow to evaluate these problems and did not recognize the safety significance and effectively resolve the problems. This matter is considered an Inspection Followup Item pending further NRC review and evaluation of the licensee's PPEP Action Plans 1.3, 2.3, 2.7, 4.1, and 4.2 (50-255/94014-52). 28

a. In 1992, Engineering had identified through *the AFW design basis documentation {DBD) program a concern as to whether, during accident conditions, adequate AFW would gravity flow to the AFW pump suctions from the condensate storage tank {CST) and primary makeup water tank {PMWT). This issue is further discussed in Jnspection Report 50-255/94011, paragraphs 3.2.5, 3.2.7.b, and paragraph 2.3.1.3.b of this report. The inspector's review of this issue determined that on April 15, 1992, A-PAL 92-126 identified that "physical piping conditions cannot provide required water for EOPs 3.0, 6.0, and 7.0 requirements." This documented the condition that the 3" line between the primary water makeup tank, T-81, and the condensate storage tank, T-2, could not *transfer water fast enoug~ for auxiliary feedwater {AFW) requirements of 300 gpm. Technical Specification 3.5.1.e requires that there be a minimum rif 100,000 gals combined between T-2 and T-81 whenever the plant was above 325 degrees F. The bases for this requirement was to provide for eight hours of AFW pump operation. In December 1993 the .. corrective action specified in A-PAL-92-126 was extended to December 1994. Until questioned by the DET, no action had been - taken* on the A-PAL. On April 7, 1994, E-PAL 94~019 was issued to resolve this issue. The licensee also issued LER 94-009 on May 9, 1994. The eight hours of supply to the AFW pumps appears to be.an original plant design intention.* However, the ability to transfer . enough water appears not to have been established. In addition, - on a loss of air or power to the 3" connecting valves, only the. 1 1/2" bypass lines were available. Analysis by the licensee determined that for the 3" lines, a minimum of 60 percent level should be maintained in the CST*and 80 percent in T-81 in order to meet the 100,000 gallon requirement. A review by the licensee of available records on CST tank levels showed that on six occasions in July and Aug.list of 1992, the CST levels were below 60 percent.* * However, the *fire protection system was always available as the backup supply to the AFW .pumps. - 10 CFR 50, Appendix B, Criterion XVI, Corrective Action, states, in part, that measures shall be established to assure that conditions adverse to quality, such as deficiencies, deviations, and nonconformances are promptly identified and corrected. The. failure to promptly correct A-PAL-92~126 that identified the inability to meet the Technical Speci f-i cation for 100, 000 ga 11 ons through gravity transfer from tank T-81 to tank T-2 was a violation of this requirement. However~ because the circumstances of this violation met the criteria for ~nforcement discretion as specified in 10 CFR 50.2 Appendix C paragraph VII.B.{5), a violation will not be issued. This violation is an example of the violations cited in the escalated enforcement for the findings of a service water system 29

b. c. d. e. operational performance inspection by letter- dated May 6, 1994. The DET in~pection raising this issue began on March 14, 1994. Therefore, although not licensee identified, the licensee had no opportunity to identify and correct the issue identified in the A~ PAL-92-126 in response to the escalated enforcement. Specific corrective actions were taken to resolve E-PAL 94-019 and were reviewed in inspection report 50-255/94011, paragraph 3.2.7.c, and emergency operating procedures inspection 50-255/94013. The long term, broad scope, corrective actions are encompassed in the licensee's reply to the Notice of Violation issued for the service water system operational performance inspection 50-255/94002. The 1991 EDSFI conducted by Region III identified 17 thermal overloads (TOls) which were not sized in accordance with planned corrective actions determined from a 1986 coordination study. This item was the subject of enforcement in 1993 and Inspection Report 50-255/93016. In September 1992, an auxiliary operator inadvertently left the air supply valve to an AOV (CV-0880) in the service water "A" supply header to the CCW system closed for two days. The single failure aspect of this valve was discussed in Inspection Report 50-255/94002. The primary coolant system (PCS) was cooled to below the temperature limit of 70 degrees F (21 degrees C) on two occasions ~ith the reactrir vessel (RV) head bolts fully tensioned, and the PCS cooldown rate limit was exceeded on severi occasions while going into shutdown cooling. An evaluation by Engineering during the DET showed that no ASME code limits for the RV had been exceeded. Consequently, there were no cumulative effects on the ductility or integrity of the RV. This matter is considered an Inspection Followup Item pending NRC review of the licensee's engineering evaluation (50-255/94014-53). This issue is also discussed in paragraphs 2.1.2.b.2) and .3) of this report. In late 1992, the condensate storage tank (CST) water temperature was found to be 10 degrees F above the assumptions used for accident analyses in the UFSAR. The inspectors reviewed this issue and determined that on October 3, 1992, a high temperature of 130 degrees was noted on the CST. The FSAR Chapter 14 used 120 degrees in the analysis for a loss of normal feedwater-event. Deviation report, 0-PAL 92- 247, was written and analyses done to determine the causes and effects of the increase in temperature. Modifications as part of the steam generators replacements resulted in reduced dilution of hot water sent to the CST resulting in higher temperature transients in the tank. An analysis of AFW performance concluded that the safety function of the system to cool down the plant on a loss of feedwater could still be achieved. Resolution of the O- PAL concluded that the system should be operated below 120 30

• -

degrees, but that actual temperatures to 130 degrees were acceptable. Accordingly, more controls were added on the CST temperature that consisted of shiftly operator rounds which added acceptable temperature criteria of 40-120 degrees. A high temperature alarm was established a year later of 125 degrees to provide for instrument error and operator action prior to reaching 130 degrees. The system operating procedure SOP 11 was changed to specify that the CST be maintained between 40 and 120 degrees. When the system modification from 120 to 130 degrees was questioned by the DET, D-PAL-94-098 was issued on March 18, 1994. 10 CFR 50.59, "Changes, Tests and Experiments," states that a licensee may make changes in the facility without prior Cammi ssion approval, unless the proposed change involves an unreviewed safety question. A proposed change shall be deemed to involve an unreviewed safety question if the probabiltty of occurrence or the consequences of an accident or malfunction of equipment important to safety previously evaluated in the safety analysis report may be increased. The increase in temperature had nonconservative impact on several accident analyses in Chapter 14 of the FSAR that were not evaluated as part of the change. Therefore, modifying the plant by allowing the CST to operate above 120 'degrees without fully evaluating the effects on plant operation or the design basis is considered a violation of 10 CFR 50.59 (50-255/94014-54). Because the corrective actions restored tank temperature limits to 120 degrees and included appropriate short term and long term corrective actions in D-PAL-94-098, no response is required to this violation. Short term corrective actions were reviewed and * found acceptable in Inspection Reports 50-255/94011, paragraph 3.2.7.b., and 50-255/94013. Broad scope corrective actions were also addressed through the* PPEP in the licensee's response to Diagnostic Evaluation Observation (DEO) ENG-010, "Quality and Scope of Engineering Evaluations." 2.3.3 Over-Reliance on Operator Actions to Compensate for Some Design Conditions There was an over-reliance on operator actions to meet design basis ac~ident requirements in some cases. Although these operator actions were in a procedure, these actions coul~ potentially complicate the operators' response to off-normal plant conditions. The DET found instances where Engineering did not provide a balanced view to plant - management and endorse modifications when Engineering believed that a modification was the most effective way to resolve a problem. This matter is considered an Inspection Followup Item pending further NRC

• review and evaluation of the licensee's PPEP Action Plans 1.3, 2.4, 4.1,

4.2, and 6.1 (50-255/94014-55). The DET identified the following examples: a. Operator action would be required to protect the TDAFW pump from failure if the low pump suction trip signal was received when 31

operating with the AFW pump turbine supplie~ from the alternate steam supply line. b. For the loss of main feedwater event, operators would be required to manually operate the non-safety-related atmospheric dump valves (ADVs) or turbine bypass valves (TBVs) in order to reduce.the steam pressure in the SG to 885 psig (6102 kPa) to allow the C AFW train to meet design flow rates. c. For the steam generator tube rupture (SGTR) and the main steam line break (MSLB) events on steam generator A (SG-A), the alternate steam flow path for AFW pump P-88 (from SG-B) would have to be manually initiated because operators must blow down this line to remove condensation prior to starting the AFW pump. The above examples are considered an Inspection Followup Item pending further NRC review (50-255/94014-56). * 2.3.4 Control and Quality of Plant Modifications Sometimes Deficient The design, implementation, and control of plant modifications we~e sometimes deficient, which occasionally resulted in modifications that* did not achieve the intended result. The licensee was aware of problems with the modification process. Just prior to the DET, the licensee established that NEC~ was the owner of the plant design basis and would be.cognizant of all modifications, both major and minor. This matter is considered an Inspection Followup Item pending further NRC review and evaluation of the licensee's PPEP Action Plans 2.4, 3.1~ and 4.2 (50- 255/94014-57). Examples of deficient modifications identified by the DET were as follows:

a. b. c. There were instances where the temporary modification (TM) process should have been used but was not. This matter is considered an Inspection Followup Item pending further NRC review and evaluation of the licensee's PPEP Action Plans 1.3, 4.1, and 4.2 (50- 255/94014-58). In response to DET questions, Engineering found that modifications that involved mounting equipment on safety-related masonry block walls had not been controlled. This matter is considered an Inspection Followup Item pending further NRC review (50-255/94014- 59). The example in the DET report pertaining to the structural calculations to demonstrate the integrity of safety-related masonry block walls surrounding the emergency class IE battery room is discussed in Inspection Report 50-255/94011, paragraph 3.3. The licensee's resolution was found acceptable, and no further concerns were identified. A design modification, SC-92-093, to a safety-related instrument bus inverter was made in 1992. This issue is discussed in Inspection Report 50-255/94011, paragraph 3.1.2. The licensee's 32 t.

resolution was found acceptable, and no further concerns were identified. The causes for the weaknesses included a historical lack of design basis information, lack of clearly defined roles and responsibilities between NECO and System Engineering, ineffective technical reviews (quality verification), and an ineffective process to assure documents, processes, and activities affected by the modification were appropriately revised. This matter is considered an Inspection Followup Item pending further NRC review and evaluation of the licensee's PPEP Action Plans 1.2, 2.4, and 4.2 (50~255/94014-60). 2.3.5 Ineffective Configuration Control by Engineering Despite the licensee's effort to improve its control of plant configuration since 1986, weaknesses still existed in the program. Insufficient management attention, and lack of attention to details, contributed to performance problems. This matter is considered an Inspection Followup Item pending further NRC review and evaluation of the licensee's.{PPEP) Action Plans 2.4, 4.2, and 5.1 {50-255/94014-61). Examples of these weaknesses were: a. The DET noted several weaknesses in the implementation of the licensee's program to control electrical load growth. This issue was reviewed in inspection report 50-255/94011 in paragraph 2.1.8.c and the issue of DG loading was concluded to be acceptable. The adequacy of the licensee's program to confrol electrical load growth is considered an Inspection Followup Item pending further NRC review and evaluation of the licensee's PPEP Action Plans 2.4, 4.2, and 6.1 {50-255/94014-62). b. On July 20, 1993, both DGs started on undervoltage signal due. to the de-energization of Bus IC, partially caused by incorrect reconfiguration of an auxiliary switch. This issue will be reviewed during closure of LER 93-005.

• c..

The.licensee's fuse control program, established in 1990-91 in. response to findings of an NRC inspection in 1990, was found to have several weaknesses and was still incomplete. The weaknesses included incorrect fuse types and labelling, lack of design basis. short circuit calculations for DC circuits, and lack of control of vendor-supplied fuses inside vendor-supplied cabinets. The implementation of the licensee's fuse control program is considered an Inspection Followup Item pending further NRC review and evaluation of the licensee's PPEP Action Plans 2.2, and 4.2 {50-255/94014-63). d. Weak control and maintenance of vendor manuals {VM) caused problems while performing plant work. This matter is considered an Inspection Followup Item pending further NRC review and 33

evaluation of the licensee's (PPEP) Action ~an 1.3 (50-255/94014- 64). Examples of the problems associated with vendor manual control included:

• 1) *

The reactor tripped in 1992 because of a wiring error inside an inverter resulting partially from fail~re to revise plant drawings and VMs after parts were replaced (LER 92-038). 2) Early in 1993, safeguards transformer 1-1 feeder breaker tripped and both DGs started while the feeder breaker was replaced with a spare breaker because of the circuit configuration differences in the breakers (LER 93-005). 3) Vendor recommendations regarding material condition of the DG and regarding bearing lube oil requirements for the AFW turbine driver were not fully evaluated by Systems

Engineering before deciding that no action would be taken. This matter is considered an Inspection Followup Item pending further.NRC review (50-255/94014-65). .4) The Vendor Information Program did not ensure that updated vendor bulletins were routinely requested. Approximately 70 DG vendor bulletins which were informally received by the DG system* engineer were not formally reviewed for site-specific applicability or introduced into the Operating Experience , Review {OER) program for review. The .. control of the DG vendor manual was reviewed and documented in Inspection Report 50-255/94011, Section 3.1.9. The DG Bulletins were being evaluated by the licensee, and an investigation to identify additio.nal unreviewed vendor inforn:iation had been performed. The licensee has revised the procedures used to -- control vendor manuals. The lic~nsee's control of DG vendor bulletins is considered an Inspection Followup Item pending further *NRC review {50-255/94014-66). ~) The Operating Experience Review. {OER) program did not require NECO to be involved in decisiohs rega~ding applicability of vendor recommendations. The licensee had initiated action to ensure appropriate engineering involvement in decisions regarding vendor recommendations.

• 2.4

MANAGEMENT AND ORGANIZATION Significant weaknesses were identified in many areas of the organization. Lack of integrated programs and processes and clearly defined roles.and responsibilities, poor communication, poor resource allocation and utilization, inadequate attention to human performance, ineffective corrective action processes, and ineffective quality overlight and self assessment resulted in poor performance and numerous repetitive events. 34

• ~:.

2.4.1 Ineffective Management Oversight and Control Examples were identified by the DET to demonstrate that management oversight and control was ineffective. The ineffectiveness of management to provide adequate control and oversight, as demonstrated by the examples above, is considered an Inspection Followup Item pending further NRC review and evaluation of the licensee's PPEP Action Plans 1.1, 1.2, 1.3, 1.4, 1.5, 2.5, 2.6, 2.7, 4.1, 5.1, and 6.1 (50-255/94014- 67). 2.4.1.1 2.4.1.2 2.4.1.3 2.4.1.4 Lack of Integrated Programs and Processes The DET identified several examples that pertained to the licensee's failure to provide integrated programs and processes. The licensee's inability to integrate programs and processes is considered an Inspection Followup Item pending further NRC review and evaluation of the licensee's PPEP. Action Plans I.I, I.2, I.3, I.4, I.5, 2.2, 2.3, 2.4, 2.5, 2.6, 4.I, and 4.2 (50-255/940I4-68). Lack of Clearly Defined Roles and Responsibilities . The DET identified several examples that pertained to the licensee's failure to provide clearly defined roles and responsibilities. The licensee's inability ~o provide* clearly. defined roles and responsibilities is considered an Inspection: Followup Item pending further NRC revie~ and evaluation of the licensee's PPEP Action Plans 1.1, 1.2, 1.3, 1.4, 4.1, 5.2,.and 5.3 (50-255/940I4-69). . Problems During Normal Operations Continued Through Outage Periods The DET identified that the causes for problems and events observed during outages were not unique to outage periods. The causes included ineffective communication, coordination, scheduling, planning, supervisory oversight, project management, and poor implementation of lessons learned. These causes, ~long with weak oversight of work contributed to the problems during normal operations and outages. Problems during normal.operations that continued under outage management included procedure adherence, lack of configuration controls,. human performance issues, and lack of a questioning attitude. . The licensee's corrective action to address the above concerns is considered an Inspection Followup Item pending further NRC review and evaluation of the licensee's PPEP Action Plans 1.2, I.3, 1.4, 1.6, 2.2, 2.3, 2.4, 2~7, 4.1, 4.2, and 5.1 (50-255/940I4-70) . . Poor Resource Allocation and Utilization The DET identified issues that pertained to the licensee's failure to provide proper resource allocation and utilization. The licensee's corrective actions to ensure proper resource allocation 35

-~*

and utilization is considered an Inspection followup Item pending further NRC review and evaluation of the licensee's PPEP Action Plans 1.2, 1.4, 1.5, 2.1, 2.2, 2.3, 2.5, 2.7, and 3.1 (50- 255/94014-71). 2.4.2 Inadequate Attention to Human Performance The DET identified that the licensee was not effective in addressing problems associated with human performance. The licensee's corrective actions to resolve issues in the HPES area is considered an Inspection Followup Item pending further NRC review and evaluation of the licensee's PPEP Action Plans 1.3, 1.4, 2.3, 2.7, 3.1, 4.1, and 4.2 (50- 255/94014-72). 2.4.3 Ineffective Corrective Action Process The DET identified that the licensee's corrective action process was ineffective. The licensee's corrective actions to resolve the issues with the corrective action process is considered an Inspection Followup Item pending further NRC review and evaluation of the licensee's PPEP Action Plans 1.3, 1.4, 2.3, 2.4, 2.7, 3.1, 4.1, 4.2, 5.1, 5.2, 5.3, and 6.1 (50-255/94014-73). 2.4.4 Ineffective Oual\\tv Oversight and Self Assessment Ineffective quality oversight and self assessment was identified by the DET. The licensee's corrective actions to improve the quality oversight and self assessment area is considered an Inspection Followup Item

pending further NRC review and evaluation of the licensee's PPEP Action Plans 1.3, 1.4, 2.3, 2.4, 2.7, 3.1, 4.1, 4.2, 5.1, 5.2, 5.3, and 6.1 (50-255/94014-74). 3. Action on Previous Inspection Findings (Closed) Unresolved Item C255/94011-02CDRS)): The licensee had identified in July 1991 that the RPS thermal margin monitor (TMM) contained a lOK ohm resistor between signal common and earth ground. This was contrary to FSAR Section 7.2.7, "Effects of Failures," where the RPS circuits were designed to be ungrounded. This design was to ensure that a single ground would not effect RPS. E-PAL-91-014K (LER No. 91-012) was issued to evaluate the event and the circuit configuration. The E-PAL concluded that a single additional ground could cause certain protective trips to trip nonconservatively. However, a single ground would only effect one TMM channel. The remaining three channels would be able to perform their safety function. In response to the LER, the licensee proposed to evaluate a method to isolate the TMM. The licensee identified numerous other isolation concerns during the 1994 refueling outage. These discrepancies as well as the TMM were 36

.. >

corrected. Qualified input isolation devices were* added to each TMM channel. This returned the TMM to the RPS configuration analyzed in FSAR Section 7.2.7. 10 CFR 50, Appendix B, Criterion XVI, Corrective Actions, stated, in part, that measures shall be established to assure that conditions adverse to quality, such as deficiencies, and nonconformances are promptly identified and corrected. The failure to promptly correct the E-PAL identifying the TMM grounding concern, when discovered in 1991, is a violation of this requirement. However, because the circumstances of this violation met the criteria for enforcement discretion as specified in 10 CFR 2, Appendix C, paragraph VII.B.(5), a violation will not be issued .. This violation is an example of the violations cited in the escalated enforcement for the findings of a service water system operational performance inspection by letter dated May 6, 1994. The DET inspection raising this issue began on March 14, 1994. Therefore, althoµgh not licensee identified, the licensee had no opportunity to identify and correct the issue identified in the E-PAL-91-014 in response to the escalated enforcement. The specific corrective actions taken to resolve this issue were r.evi"ewed in inspection report 50-255/94011, paragraph 3.1.7. The long term, broad scope, corrective ~ctions are encompassed in the licensee's reply to the Notice of Violation issued for the . service water system operational performance in~pection 50-255/94002. 4.. Inspection Follow-up Items Inspector follow-up items are matters which have been discussed with the licensee, which will be reviewed by the inspector and which involve some action on the part of the NRC or licensee or both. *seventy two Inspection follow-up items disclosed during the inspection are discussed in section 2 -of this report. Attached to tnis report is a cross

reference of Inspection Followup items to the specific paragraphs of

this report. - 5. * Exit Interview The inspectors met with the licensee representatives denoted in paragraph 1 during the inspection period and at the conclusion of the inspection on September.27, 1994. The inspectors*summarized the scope and results of the inspection and discussed the likely content of this inspection report. The licensee acknowledged the information and did not indicate that any of the information disclosed during the inspection could be considered proprietary in nature . 37

*

1 , ITEM NO. 50-255/94014- 01 02 03 04 05 06 07 08 09* 10 LIST OF OPEN ITEMS TYPE PARAGRAPH SUBJECT IFI 2.1.1.A Corrective actions to DEO ENG-047. IFI 2.1.1.D Performance of operations management in the planning and direction of plant evolutions, process controls, and job assignments. IFI 2.1.2.A.1) Delineation of roles and resporisibilities not clear among ops supervisors. IFI 2.1.2.a.2) Onshift supervisors received limited supervisory training and coaching . IFI 2.1.2.a.3) Operations management overburdened onshift supervisors with collateral duties. IFI 2.1.2.a.4) Noise level in control room. IFI 2.1.2.b.l) Reviews of surveillance test results IFI 2.1.2.b Ove~all performance of onshift operations *shift supervision providing adequate oversight and direction IFI 2.1.3 Operations management established low or incomplete standards and expectations for operators IFI 2.1.3 Ability to foster an environment of procedural adherence 38

' :> ... LIST OF OPEN ITEMS 11 IFI 2.1.3.a Procedure change control process 12 IFI 2.1.3.a.l) Revise surveillance test procedure to include monitoring the diesel generator (DG) l~l fuel oil belly tank 1 evel 13 IFI 2.1.3.a.4) Revise the fuel oil transfer system checklist 14 IFI 2.1.3.b~2) Control of transient equipment 15 IFI 2.1.3.b.3) Role of Operations department personnel in the operability process 16 IFI 2,1.3.b.4) Auxiliary operators did not critically assess plant material conditions during rounds .,

17 IFI 2.1.3.b Operators not maintaining logs in accordance with management expectations 18 IFI 2.1.4 Inadequate protective tagging of equipment 19 IFI 2.1.5.2.e SFHM did not receive formal proficiency evaluations prior to handling fuel. ,. 20 IFI 2.1.5.2.d Onshift Operations supervision received limited root cause and event investigation * training. 21 IFI 2.1.5.2.e Operators received limited training and written guidance on NRC notification requirements. 22 IFI 2.1.5.3.a Aggressive action was not taken to fully resolve the problems with TS .

39

LIST OF OPEN ITEMS 23 IFI 2.1.5.3 Quality of Licensing's recommendations. to Operations for reporting events 24 IFI 2. l.6 Weak operations self assessments. 25 IFI 2.2.l.c Weaknesses were identified by the team during a monthly test of DG 1-1 26 . IFI 2.2.2.l.a Corrective actions for the D-PAL-93-272 27 IFI 2.2.2.2.b Root cause of the stroke time increase. 28 IFI 2.2.2.4 Verify that relief valve data sheets accurately reflect their design requirements. 29 VIO 2.2.2.5 Failure to test check

valves full flow open position. 30 IFI 2.2.2.6' Resolution of FW-150 31 IFI 2.2.3 Oversight of maintenance activities by supervisors and managers. 32 IFI 2.2.3 Poor support from Engineering contributed* to inadequate maintenance work procedures and poor root cause evaluations. 33 IFI 2.2.3.c Foreign material exclusion 34 IFI 2.2.4 .Several material deficiencies.existed due to communications and expectations. 35 IFI 2.2.4.a Root cause for* the darken oil 40

LIST OF OPEN ITEMS 36 IFI 2.2.5 Numerous fundamental weaknesses regarding material control and supply of parts from the warehouse. 37 IFI 2.2.6 Poor support for PM activities. 38 . IFI 2.2.7 Work control process exhibited weaknesses in tracking and reporting. 39 IFI 2.3 Roles and responsibilities of the two onsite engineering organizations and the interfaces between them were not well defined. 40 IFI 2.3.1 Support to the plant from both NECO and Systems Engineering was often weak. 41 IFI 2.3.1.1 A geheral weakness

concerning training of engineers in evaluating degraded equipment for operability. ' 42 IFI 2.3.1.1.c Modification to change the air start motors actuation circuits . . -43 IFI 2.3.1.2 Weak or untimely root cause analyses. 44 IFI 2.3.1.2.a Preventive maintenance program for the voltage regulator 45 IFI 2.3.1.2.b Installation of the modification for the AFW low suction pressure trip. 46 IFI 2.3.1.2.c Root cause evaluation for the slow starts for EOG. - 47 IFI 2.3.1.3 Engineering support for revising the plant operating and maintenance procedures was poor .

41

. . ~ r\\.'. 48 49 50 51 52 ' 53 54 55 56 57 LIST OF OPEN ITEMS IFI 2.3.1.3.a Engineering contra ls *for assuring operating procedures were appropriately revised following plant modifications were weak. IFI 2.3.1.3.b EOPs needed to be revised in three different areas due to concerns with the size of the cross-connect line between two tanks (T- 81 and T-2). IFI 2.3.1.3.d FOTP surveillance test procedure M0-7C did not verify pump operability because the procedure lacked quantitative acceptance criteria. . IFI 2.3.1.4 Poor oversight over contractors' work. IFI 2.3.2 Engineering. was often slow to evaluate these problems. IFI 2.3.2.d PCS was cooled to below the temperature limit of 70 degrees F. VIO 2.3.2.e Modifying the- plant by allowing the CST to operate above 120 degrees without fully evaluating the effects on plant operation or the design basis. IFI- 2.3.3 Over-reliance on operator actions to meet design basis accident requirements IFI 2.3.3 Examples of over-reliance on operator actions to meet design basis accident- requirements.

• IFI

2.3.4 Design, implementation and control of plant modifications were sometimes deficient. 42

LIST OF OPEN ITEMS 58 IFI 2.3.4.a Instances where the temporary modification (TM) process should have been used but was not. 59 IFI 2.3.4.b Modifitations that involved mounting equipment on safety-related masonry

• block walls had not been

controlled. 60 IFI 2.3.4 Causes for the weaknesses included a historical lack of design basis information, lack of* clearly defined roles and responsibilities between NECO and System Engineering, etc .. . 61 IFI 2.3.5 Control of plant configuration weaknesses still exist. 62 IFI 2.3.5.a. Weaknesses in the implementation of program to control electrical load growth. 63 IFI 2.3.5.c Fuse control program, was found to have several weaknesses and was still incomplete. 64 IFI 2.3.5.d Weak coritrol and maintenance of vendor manuals. 65 IFI 2.3.5.d.3) Vendor recommendations for EOG and AFW not fully evaluated by Systems Engineering. 66 IFI 2.3.5 .. d.4) Vendor Information Program did not ensure that_ updated vendor bulletins were routinely requested. 67 IFI 2.4.1 Ineffectiveness of management to provide adequate control and oversight 43

.*

LIST OF OPEN ITEMS 68 IFI 2.4.1.1 Failure of the licensee to integrated programs and processes. 69 IFI 2.4.1.2 Failure to provide clearly defined roles and responsibilities. 70 IFI 2.4.1.3 Causes for problems and events observed during outages were not unique to outage periods. 71 IFI 2.4.1.4 Failure to provide proper resource allocation and utilization 72 IFI 2.4.2 Licensee was not effective in addressing problems associated with human

performance. 73 IFI 2.4.3 Corrective action process was ineffective. 74 IFI 2-. 4. 4 Ineffective quality oversight and self assessment .

44 }}