ML20203F563

Insp Repts 50-302/97-12 on 971020-24,1208-12 & 980105-09. Violations Noted.Major Areas Inspected:Adequacy of EOPs Development Process

ML20203F563
Person / Time
Site:	Crystal River
Issue date:	02/23/1998
From:	Jaudon J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:
Shared Package
ML20203F553	List: ML20203F548 ML20203F556 ML20203F563
References
50-302-97-12, NUDOCS 9803020003
Download: ML20203F563 (43)

See also: IR 05000302/1997012

Text

U. S. NUCLEAR REGULATORY COMMISSION

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REGION 11

EMERGENCY OPERATING PROCEDURES TEAM INSPECTION

Docket No.: 50 302

License No.: DPR 72

Report No.: 50-302/97-12

Licensee: Florida Power Corporation

Facility: Crystal River 3 Nuclear Station

Location: 15760 West Power Line Street

Crystal . R1ver, F1orida

Dates: October 20 through 24. 1997. December 8 through 12, 1997,

and January 5 through 9, 1998

Team Leader: W. Rogers. Sr. Reactor Analyst. Division of Reactor Safety

Inspectors: J. Bartley. Resident inspector. Division of Reactor Projects

G. Galletti. Human Factors Specialist. Office of Nuclear

Reactor Regulation (NRR)

P. Harmon. Sr. React Inspector. Division of Reactor Safety

L. Me 1 . Re r Inspector. Division of Reactor Safety

Approved by: 4h 13[ff

.( Jhudgn. Direhor~. Date Signed

Division of Reactor Safety

~

9003020003 980223

PDR ADOCK 05000302

G PM Enclosure 2

EXECUTIVE SUMMARY

Crystal River Nuclear Plant. Unit 3

NRC Inspection Report 50 302/97-12

Five headquarters and regional inspectors used a sample approach to assess the

adequacy of the emergency operating procedures (EOPs) development process.

The team observed operating crews respond to numerous simulated emergency

conditions developed by the team to test specific sections of the E0Ps. The

inspection

Procedures.guidancewasInspectionProcedure42001."EmergencyOperating

Three weeks of on-site inspection were performed with draft E0Ps

and supporting documents inspected during the first on-site week. Plant

Review Committee approved E0Ps and supporting documents were used during the

other two on-site weeks.

Operatiom

. At the beginning of the inspection. the licensee had deviated from the

Technical Bases Document (TBD) numerous times without providing any

technical justification or adequate technical justification for the

deviations. Following NRC identification, the licensee upgraded the

technical justification documents and/or revised the E0Ps. After the

upgrade, some of the justifications were still not adequate. These

actions require additional justification or revision of the E0Ps to

ensure the mitigation strategy is accomplished. In addition. there were

other less significant actions differing from the TBD. Also. TBD

actions to be accomplished by the TSC were not incorporated into

procedures. The examples of inadequate justifications lack of

technical justifications, limited technical justifications and procedure

omissions were indicative of numerous E0P development process

weaknesses. A number of thes examples were part of a violation (section

03.1).

. At the beginning of the inspection the licensee's in-plant portion of

the verification and validation (V&V) process, which was being performed

on the draft E0Ps was insufficient. There were no specific concerns

regarding the control room portion. In response to the team's

perspectives. the licensee provided additional guidance for the in-plant

V&V. and the team noted improvements. However, even with the

improvements, there were other specific and general deficiencies

reflecting inadequacies in the in-plant V&V process. Also, some of the

team's original concerns were not adequately addressed partially due to

inadequate correction actions to a problem previously identified by the

licence associated with in-)lant o)erator accessibility. The disparity

between licensed operators )eing a)le to perform control room E0P

actions and non-licensed / support personnel not always being able to

perform in-plant E0P actions was consistent with the way in which the

V&V process was established and implemented. Consequently, the actions

directed by the E0Ps within tne control room could always be performed

but, numerous in-plant actions either could not be performed due to the

lack of support personnel. the lack of properly stagged equipment,

technically incorrect procedure steps, not incorporating the actions

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into procedures or the radiological consequences of performing the

actions had not been assessed. A number of these inadequacies were part

of a violation (section 03.2).

. The E0P Writer's Guide was comprehensive and adequately implemented in

the construction of the E0Ps. This contributed to operators rarely

having trouble reading or understanding the E0P steps during the

simulator scenarios (section 03.3).

. Following revisien, the licensee's E0P User's Guide was acceptable

(section 03.4).

. The maintenance and revision procedure was adequate. The scope of the

NRC review did not include set point control (section 03.5).

. The operating crews were capable of mitigal.ing the transients presented

by the team. However, there were some examples of performance

inconsistent with an E0P step. licensee management expectations or the

licensee's administrative guidance. These performance problems were

being dispositioned consistent with their significa.nce (section 04).

. The E0P//,P training program for licensed operators was adequate. There

was a program weakness of not training secondary plant operators on

resetting the emergency feedwater turbine's over speed trip. The

licensee provided corrective actions consistent with the significance of

the weakness (section 05).

Maintenance

. The work control process did not consider that work could inhibit access

to in-plant E0P action locations. The licensee was formulating

con active actions to this weakness (section M3.1).

. The licensee's program for implementing Technical Specification 5.6.2.4

was not adequate. but the actual external leakage did not exceed post-

accident dose consequences requirements. The licensee was taking

appropriate corrective actions to correct this non-cited violation.

(section M3.2)

. The technical content of the periodic inventory controls for in plant

E0P equipment was adequate (section M3.3).

Enaineerina

. Generally, calculations issued prior to 1995 contained numerous errors.

Occasionally, the calculations did not contain enough information to

enable a person. who was technically qualified in the subject to review

and understand the analyses and verify the adequacy of the results

without recourse to the originator. This was a violation. Prior to the

team's arrival, the corrective actions to known calculational

inadequacies had not extended to the E0P set point calculations which

was an example of a violation. Although a small sample size was

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reviewed by the team the calculations issued in 1997 to support E0P set

points were far better (section E1.1).

. During at least two time periods after the operating 11 cense was

granted. there was no procedural guidance to use the LPI crossover line

with flow split between the two LPI lines to mitigate the consequences

of a LOCA. Also, a recent change to the USAR regarding the LPI

crossover line method of long term core cooling was inconsistent with

applicable topical reports. The NRC will further review these

unresolved matters (section E1.2).

. The MUPs used for ECCS high pressure injection were not purchased to

specifications commensurate to the duty to be incurred during a

postulated post-accident LOCA. This was a violation. (section E1.3)

. The EDG air start circuitry was properly designed to prevent continued

application of startirg air to an EDG until depletion of the staring

air, and appropriate operator training had been provided on how to

respond to a tripped EXi (section El.4).

. The LPI injection valves were maintained normally closed, consistent

with the FSAR. However, in a letter dated 1/13/76 the licensee

committed to maintain the valves normally open and update the FSAR

accordingly, Those actions were never accomplished. The NRC will

further review this unresolved matter (section E1.5).

. The licensee identified a wiring error in the control room heating and

ventilation systern. T.e license was taking appropriate actions to

correct this non-cited violation. (section E8.1)

- .- . . _- . - . . . -- . . - .

,

Report Details

Summary of Plant Status

Crystal River Unit 3 was shutdown with Reactor Coclant System temperature

below 200* Fahrenheit during the inspection period.

Introduction

The primary objective of this inspection was to assess the adequacy of the

process used to develop and implement emergency o>erating procedures (EOPs).

The team used a sampling approach to evaluate teclnical content,

administrative controls, verification and validation and, engineering

calculations and analyses supporting the E0Ps.

I. Operations

03 Operations Procedures and Documentation

03.1 Conformance to the Technical Bases Document (TBD)

a. Insoection Scoce (42001)

The team reviewed substantial portions of the E0Ps against the

procedural guidelines of the B&W Owners' Group E0P TBD (74-1152414 Rev.

8) and two owners' group approved TBD changes which will be incorporated

into the next revision. W1ere deviations were noted. the team evaluated

the licensee's technical justification documents (TBD - E0P Cross Step-

Document & E0P - TBD Cross Step Document) to verify that deviations from

the TBD such as additions, omissions, and sequence changes were

technically justified and did not affect the mitigation strategy.

During the October onsite inspection, the team reviewed the draft E0Ps

scheduled for PRC approval in November, During the December onsite

inspection, the team reviewed the PRC conditionally approved E0Ps.

During the January onsite inspection. the team continued to review

select (PRC) conditionally ap3 roved E0Ps and, due to previous NRC team

findings, revisions to the E03s.

Due to the numerous design changes being implemented and outstanding

Technical Specification requests yet to be approved by the NRC Office of

Nuclear Reactor Regulation (NRR). the team based the review, assuming

that License Amendment Requests (LAR) 210 (dated June 14, 1997). (LAR)

214 (dated October 31. 1997) and (LAR) 218 (dated September 9, 1997).

would be acceptable to NRR without deviation. The team did not review

the technical adequacy of the E0P actions dealing with boron

precipitation control since the adequacy of tk. licensee actions in this

area was being reviewed by NRR.

b. Wservations and Findinas

1. During the October onsite inspection, the team determined that the

licensee deviated from the TBD guidelines numerous times. The

omi,sions and additions were typically identified in the desiation

__

2

documents. However, most of the justifications were not adequate.

Also, the licensee did not identify any step sequence changes as

deviations or confirm that the sequence deviations were non-

consequential with regard to the mitigation strategy.

(a) Specific examples of inadequately justified deviations were:

. TBD III.B. Lack of Adequate Subcooling Margin, step

8.2.b provided direction to maintain OTSG tube to

shell temperature differentials within limits. The

licensee omitted this step and documented its omission

in the deviation document. However, the justification

was very general and did not provide adequate details

to assess the deviation.

. TBD. SBLOCA/SBLOCA Cooldown, step 17.4 directed

establishing auxiliary spray, if desired. The

licensee omitted this step and justified its omission

solely on it being an optional action.

. TBD. SBLOCA/SBLOCA Cooldown. step 8.0. directed

verifying flow in each LPl line > [ min flow). The

E0Ps stated to verify flow in any LPI line. TBD

Vo ume III stated the basis was to verify adequate LPI

.

flow for core cooling prior to transitioning to LBLOCA

CD. The licensee's justification discussed

identifying aressure below LPI pump head without

discussing w1 ether there was adequate core cooling.

. TBD. LBLOCA Cooldc,;n. ste) 1.2 directed opening the

LPI crosstie if only one _PI pump was available to

ensure injection through both lines The ECPs omitted

this step. The justification was that the motor

oaerated valves may or may not have power available

w1ich didn't addrese why the step could not be

accomplished or its impact on the mitigation strategy.

(b) Specific examples of deviations that wr.re not identified and

justified were:

. TbD lil.A. Immediate Actions and Vital System Status

Verification (VSSV). steps 2.3 and 2.4. directed that

adequate primary to secondary heat transfer be

attempted and to begin maximum boric acid addition if

reactor power was not decreasing when the reactor was

required to be tripped (i.e. an Anticipated Transient

Without a Scram (ATWS)). E0P-02. VSSV. did not

address primary to secondary heat transfer or

initiating boric acid addition until much later in the

procedure. Consequently. during a complete ATWS from

i

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90% reactor power simulator scenario, the operating

crew was not able to perform the TBD mitigation

strategy.

. TBD lli.B. Lack of Adequate Subcooling Margin. step

4.0. directed isolating possible RCS Leaks (4.1) and

verifying RB Noling (4.2). The licensee did not

direct isolating possible RCS leaks until step 3.17 of

E0P03.InadequateSubcoolingMargin. Verification of

RB Cooling was performed in step J.9. The sequence

deviation and impact on delaying corrective actions

was not identified in the deviation document.

. TBD lil.B. Lack of Adecuate Subcooling Margin, steps

1B.0 18.6. were movec to E0P-14. E0P Enclosures.

Enclosure 16. RCP Recovery, without technical

justification.

. The TBD periodically repeated critical checks and

procedural transitions. The licensee re) laced these

periodic checks with carryover steps witlout technical

justification.

. E0P 03. Inadequate Subcooling Margin. Steps 3.37 -

3.55. were imported from TBD SBLOCA Cooldown without

technical justification as to why the steps were not

contained in E0P-08. LOCA Cooldown.

. The following steps were sequenced differently in E0P-

07. Inadequate Core Cooling, than TBD lli.F.

Inadequate Core Cooling without justification.

TBD Sten E0'-07 Sten

_10.0 3.29

12.0 3.31

12.1 3.31

12.2 3.33/3.34

12.3 3.35

13.1 3.31

13.3 3.30

13.7 3.32

. The following steps were sequenced diffarently than

the SBLOCA/SBLOCA Cooldown TBD without justification.

TBD Sten LOP-07 Sten

2.1 3.10

2.2 3.25

4.1 3.15

4.2 3.32

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

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5.0 3.20

6.0 3.14

7.0 3.36

2. Following NRC identification to the licensee of the generally goor

justifications from the TBD. the licensee began upgrading the BD

- Cross step documents and/or revising the E0Ps. Consequently,

the draft E0P 02 procedure was revised for responding to an ATh'S.

and TBD step 17.4 of SBLOCA/SBLOCA Cooldown. directing the

establishment of auxiliary spray, was added to E0P 08. LOCA

Cooldown. Also, in concert with the B&W Owners' Group, the TBJ

was changed to indicate that steps could be preformed out of

sequence provided the mitigation strategy was not compromised.

3. During the December onsite inspection the team identified

inadequacies and weaknesses in the upgraded TBD Cross step

documents.

(a) The inadequacies included:

. TBD. LBLOCA CD. step 3.0. directed securing HPI when

LPl flow of *x" (the minimum flow for adequate core

cooling derived by the licensee) amount existed for

greater than 20 minutes. TBD Volume 3 identified that

this v:as due to concerns of: 1) increasing radiation

levels in the auxiliary building iAB) during RB sump

retirc while in the piggyback mode. 2) pump failure.

and 3) possibly avoiding the complex evolution of

switching to the piggyback mode. The licensee had

removed this guidance and opted for long term

operation of the HPI pumps in piggyback mode. The

technical justification was not adequate in that it

did not address the above items of concern.

. TBD. LBLOCA CD. Step 1.2. directed opening the LPI

crosstie if only one LPI pump was available to allow

injection through both LPI lines. The licensee

omitted this guidance without adequate technical

justifitation since LPI operation in this manner was a

licensing basis requirement. FSAR. Chapter 6. Section

6.1.2.1.2 specifically stated that "the LPI System is

provided with a crossover line to permit one LPI

string flow of 3.000 gpm to be split equally. thus

providing a minimum of 1.500 gpm flow to both core

flooding injection nozzles simultaneouGy should a

core flooding line or one LPI pump fail." Also, the

B&W topical reports approved by the NRC verifying

licensee compliance to 10 CFR 50.46. Acceptance

criteria for emergency core cooling systems for light

water reactors, listed. ~one LPI pump operating with

crossover line valves open; flow split Detween the two

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5

LPI lines by the control valves." as one of three

required long term core cooling methods. Section El.2

of this report contains additional discussion of the

licensing pasis for this operation.

• TBD Section Ill.B. Lack of Adequate Subcooling Margin,

step 8.0 provided time critical guidance for starting

an emergency cooldown if HPl was not available.

Volume Ill of the TBD stated that for SBLOCAs where

HPI flow could not be established. " Plant cooldown

must start immediately upon a loss of mbcooling

margin in order to avoid severe core ( age." The

licensee added nine steps prior to the step which

initiated the emergency cooldown due to no HPl. The

justification for adding these steps did not address

delaying the cooldown. The team o) served that an

operations crew on the simulator, responding to a

total loss of HPl. took 29 minutes to commence the

emergency cooldown.

. Step 2.2.1 of E0P 02. Vital System Status

Verification, directed de-energizing the CRD system to

insert control rods if the reactor protection system

failed. Step 2.2.2 directed re energizing the CR0

buses by closing 4B0 VAC supply breakers. 3305 and

3312. There was no corresponding TBD section or step

for re-energizing the buses. and a technical

justification for inserting the step was not included

in the cross step document. Breaker 3312 was between

4160 VAC ES Bus 3B and the 480 VAC Plant Aux Bus. The

effects of re-closure of breaker 3312 on the 4160 VAC

ES Bus 3B had not been analyzed. During an ATVS

simulator scenario, the team observed an operator

momentarily open the 3312 breaker and then reclose it.

Subsequent analysis indicated that breaker 3312 must

be open for at least three seconds to assure that the

currently connected bus loads would not re-tri) the

bus on over current. Also, there was another areaker.

3222 (the supply breaker from the 4160 VAC ES Bus 3B).

in line with breaker 3312 and 480 VAC Plant Aux Bus.

Neither breakers. 3222 or 3312. had been tested under

these conditions.

By letters dated October 31. 1980 and December 17. 1982.

from D. Eisenhut (NRC) to all licensees of operating plants

and applicants for operating licenses and holders of

construction permits. the post-Three Mile Island (TM1)

requirements. NUREG-0737. " Clarification of TMl Action Plan

Requirements." and Supplement 1 to NUREG 0737. " Requirements

for Emergency Response Capability " were issued. NUREG-0737

criterion 1.C.l. " Guidance for the Evaluation and

..

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Development of Procedures for Transients and Accidents." I

provided clarification regarding the requirements for i

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reanalysis of transients and accidents. Item 7 of

Supplement 1 to NUREG 0737. " Upgrade Emergency Operating

Procedures (E0Ps)" directed that licensees develop a

procedures generation package (PGP) which included a ,

,

description of the validation program for the E0Ps.  !

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By letter dated March 25, 1983. Florida Power Corooration '

(FPC) submitted a PGP in res

of NUREG 0737. Supplement 1.ponsecontained

The response to the I.C.1 a requiremen

. discussion of the upgraded E0P validation program which t

stated. in part that the purpose of the validation program

.

was to demonstrate the usability of emergency procedures.

The instructions to operators were to be complete.

j understandable and, compatible with conditions. Licensee

3rocedure Al 402C AP and E0P Verification and Validation

)lan. enclosure 3. required differences between the

procedure and the TBD be documented and justified.

On February 21. 1984, the NRC issued an Order modifying the

Operating License which confirmed the licensee's

-

implementation of I.C.1. These above examples of inadequate

technical

were examples justifiestions affecting

of violation . VIOthe miti50 302/97 12-01. gation strategy

" Inadequate Implementation of TM1 Action item E0P Order."

Also, the significance and number of the examples, was

indicative of a weakness in the process for developing the

'

<

E0Ps.

(b) In addition to the inadequacies, there were other actions

different from the TBD that were not fully justified in the

Cross step documents, but did not appear to affect the >

mitigation strategy. As an example, the licensee inserted

steps 3.4. 3.5. and 3.6 into E0P 05. Excessive Heat

Transfer, which were not part of the owners' group guidance.

This resulted in step 3.7 (which would have corresponded to

step 3.4 in the TBD) being moved to later in the E0P. The

only justification for this change was that step 3.7 was

placed where it was because " steps 3.4. 3.5, and 3.6 were

added to the procedure.' While this explanation may

account for how the step numbers changed, it provided no

technical justification for the change. The new steps

appeared minor in terms of effect (both mitigation strategy

and time delays). However, the licensee provided no

technical basis for this change. Other similar step

sequence changes were identified in this and other E0Ps. and

referred to the licensee. None of the changes appeared to

'

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. change the accideL., mitigation strategy or the timeliness of '

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procedur61 steps, but the lack of or limited technical

' '

justification and documentation was indicative of a weakness

in the process for developing the E0Ps.

i

4. Also in December, during a review of PRC conditionally a> proved '

i- E0P 8. LOCA Cooldown, the team recognized that several TB) ste)

i actions were omitted from the E0Ps and were justified in the T3D-

Cross step documents on the basis that the TSC would )rovide the

j guidance required to perform the actions. However, tie licensee ,

had not developed any TSC guidance to address the actions stated i

-

in the TBD and therefore the documentation to support the

i justification for deviation from the B&W guidance was incomplete.

Examples of the steps affected included:  :

_ lBD  !

Step 2.2 Trip RCPs if running.

Step 6.2 Monitor and Control hydrogen concentration i

in RB in accordance with plant specific  :

method.

!

Step 6.4 If sump is being diluted...

'

a. check for and attempt to isolate

leaks into the RB 1

'

'

b. If leaks into the RB are found and -

cannot be isolated. Then commence

boron addition to the RCS as

'

necessary to maintain adequate

shutdown margin. .

Step 6.6 Maintain RB sump level within appropriate

<

high-low limits.

Step 6.7 If sump water level must be drained THEN

ensure radioactive water will be

appropriately stored.

I These inadequately technically justified actions are additional

examples of--violation VIO 50/302 97-12 01. ~1nadequate

j Implementation of TMl Action Item E0P Order.~

5. The team observed implementation of the revised E0P 02. VSSV. in -i

i response to an ATWS simulator scenario in December. The TBD

mitigation strategy'was accomplished.

j _. 6. During the January 98 onsite inspection, the team identified two

other actions that were not technically justified with respect to

the TBD. These actions were contained in E0P 06. SGTR. and were:

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• The time delay insertion of site specific steps 3.1, 3.2 and

3.3 between SGTR identification and determination that the

reactor was tripped. The additional steps were not in the

TBD. These additional actions impacted the timely attempts

to restore pressurizer level in step 3.5, which increased

the chances of manually tripping the reactor above the

secondary side steam pressure set points for the atmospheric

dump valves (ADVs) and main steam safety valves (MSSVs).

Opening these valves would increase the radiological dose to

t1e public since these are direct release pathways and

should be avoided. The team observed an o)erations crew on

the simulator responding to a SGTR in whic1 the crew did not

maximize makeu) (complete step 3.5) before manually tripping

the reactor a ligh power per step 3.6. Also, during another

SGTR c:enario in a previous week. the crew jumped ahead to

step J.5 to maximize makeup as soon as possible. The cross

step document indicated that the addition of site specific

steps 3.1, 3.2 and 3.3 were not consequential.

. The time delay possible in not isolating the EFWT steam

supply from the affected OTSG. If the affected OTSG's steam

is used to power the turbine driven EFW pump, the turbine's

exhaust would be a direct radiological release path. Step

3,3 of the TBD directed isolating all non essential steam

loads during a rapid power reduction prior to tripping the

reactor below the ADV and MSSV set points. The licensee did

not isolate the affected OTSG EFWf steam supply until step

3.45 or 3.46. The licensee did justify not isolating the

steam supply during the rapid power reduction since its

isolation could induce a system perturbation causing a

reactor tri? above the ADV and MSSV set points. However,

following t1e manual trip, the licensee did not technically

justify delaying the steam supply isolation. The team

observed an operations crew on the simulator responding to a

SGTR in which an hour elapsed before this action was done.

The licensee initiated PC-98-0151. based on the team's

observations.

These two inadequately technically justified actions are

additional examples of violation. VIO 50/302-97-12 01. " Inadequate

Implementation of TMI Action item E0P Order.".

c. Conclusions

At the beginning of the inspection. the licensee had deviated from the

TBD guidelines numerous times. The omissions and additions were

typically identified in the deviation documents. However, most of the

justifications were not adequate. Also, the licensee did not identify

any step sequence changes as deviations or confirm that the sequence

deviations were non consequential with regard to the mitigation

strategy. Following NRC identification of the generally poor

.-

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i justifications from the TBD the licensee upgraded the technical

. justification documents and/or revised the E0Ps. After the upgrade.

l some of the justifications were still not adequate to support deviating ,

~

from the TBD since the actions affected the TBD mitigation strategy.

These actions require additional justification or revision of the E0Ps  ;

. to ensure the mitigation strategy is accomplished. In addition to the

1 iradequacies there were other less significant actions differing from

) the TBD which did not appear to affect the mitigation strategy that were  ;

'

not fully technically justified. Also, the licensee failed to ensure

that TBD actions to be accomplished by the TSC were incorported into

4

procedures. The examples of inadequate technical justifications lack

i of technical justifications, limited technical justifications and

, procedure omissions were indicative of numerous process weaknesses in '

,

developing the E0Ps a number of these examples were part of a violation.

! 03.2 Verification & Validation (V&V) Guidelines

a. Inspection Stone (42001)

P

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The team reviewed the licensee's V&V instruction (Verification and

Validation Plan Al 402C Rev, 4) to ensure that it adequately addressed

the issues associated with verifying the technical and humaa factors

adecuacy of the procedures and validated that the procedures could be

usec by the operators to mitigate transients and accidents. The team

reviewed a sample of the V&V records maintained as part of the E0P

development program. The team observed licensed and non licensed

operators respond to simulated emergercy conditions developed by the

team to test specific sections of the E0Ps. The evaluation of operator

actions included the ability of the operators to carry out those

designated actions, both inside and outside the control room. From

these direct observations the team could partially determine whether the

V&V instruction and its implementation was adequate. Also, the team

independently walked down selected in plant operator actions to

determine whether the actions could be completed as written, components

were accessible, the necessary equipment was pre-staged and controlled,

and that environmental conditions such as post-accident radiation

levels, temperatures, and lighting would not hamper accomplishment of

the tasks. These direct observations also provided another method to

determine whether the V&V instruction and its implementation was

adequate. During the October onsite inspection, the team used the draft

E0Ps scheduled for PRC approval in Novem3er. During the December onsite

l inspection, the team used the PRC conditionally approved E0Ps. During

, - the January onsite inspection, the team continued to use select PRC

l conditionally approved E0Ps and, due to previous NRC team findings,

l revisions to the E0Ps,

-b. Observations and findinos

1. In October the team recognized that the licensee was in the

arocess of performing the V&V on the draft E0P in plant actions.

10 wever based upon the licensee's response as to how certain

P

aw a ++ +  %----,w-#%e- -e--,.-=---r---=r,r --ww ----.r~-,r-= * r- ee rr-e v--e -- w w w e ee w ww =,

._

10

areas of the V&V had been dealt with and direct observations from

in plant walkdowns, the team expressed a concern to the licensee

that the in plant portion of the V&V process was insufficient.

Specific findings and observations supporting this perspective

were:

• E0P 14. Enclosure 13. Ste)s 13.3 and 13.5. directed the PPO

to align four valves in t1e 119 feet AB penetration area.

These valves were required to be operated to initiate and

secure high pressure auxiliary spray. One of the valves was

approximately 10 feet above the floor and may be accessible

with a tall stepladder. However, only an extension ladder

was staged for the job and it could not be positioned to

3rovide access to the valve due to piaing configurations.

Jpon identification to the licensee. 3C3 C97 7324 was

initiated.

• E0P 14. Enclosure 20. Steps 20.12 detail item 6 and 20.27.

incorrectly identified "MVP 1A. A Makeup Pump." 4160 V

breaker being in cubicle 3A 3. The correct location was 3A-

10.

. E0P 14. Enclosure 21. Step 21.1. directed I&C to install

flow instrumentation. Numerous problems were identified

with this step such as: incorrect part numbers; the

equipment was available for general use; 1&C technicians

were not trained on the step; the equipment did not have a

current calibration; the transmitters were not wired up

requiring the technicians to obtain the tech manual and

wiring diagrams from document control (not always manned);

the parts were in the warehouse (not always manned) outside

the protected area and required operating a forklift to get

them off the shelves; and the required gaskets were not

identified or pre staged. The licensee initiated PC3 C97-

7365 regarding Enclosure 21.

. E0P-14. Enclosure 6. step 6.3.1 required the installation of

a hose between valves CXV-358 and MSV-524 to fill the OTSG

blowdown line. At the request of the team a non-licensed

operator attempted to perform this action. The hose to

accomplish this task was comprised of numerous segments

connected by Chicago fittings and was not long enough to

join the two points. Also, the hose reel storing the iose"

and the hose were not positively secured. Upon

identification the licensee initiated PC3-C97-7125.

. Based upon verbal licensee responses the radiological

mission doses for performing in-plant actions, except

initiating RB purge for hydrogen control, had not been

appropriately considered.

.

11

• The licensee did not have time studies for accomplishing in-

plant actions. Without such information there was no way to

ascertain the integrated effect on personnel resources that

the in plant actions would have.

• Following the team's inquiry as how chemistry sampling

actions could be accomplished under postulated electrical

bus failures, the licensee initiated PC3 C97 7244 : " ting

that chemistry did not have procedures or equipment to

support the E0Ps with a loss of ES train B power or during

an SBO,

• Based on the team's walkdowns, it was not apparent that the

licensee had taken into account that an extra operate' may

be necessary to stabilize some of the ladders used to

operate equipment based on physical constraints. Typically

it would take approximately 15 minutes to operate each valve

requiring a ladder for access. Also, in some cases, the

o)erators would be hampered by a lack of emergency lighting,

W11ch could not be compensated for by using a conventional

flashlight, e.g., the job took two hands and was 15 feet

above the floor.

2. In response to the team's perspectives, the licensee provided

additional guidance to the personnel performing the V&V to ensure

lighting, labeling, proper equipment staging and spatial

restrictions were appropriately addressed. Pictures were taken of

the equipment to be operated in detail enough to see the equipment

labeling, A time study was performed to help recognize any

conflict in resource allocation for in-plant actions. including

maps depicting the most probable routes non licensed operators

would use. Saecific equipment staging deficiencies such as the

hose for OlSG ] lowdown and the ladder for the pressurizer

auxiliary spray were quickly rectified. The team's observations

regarding mission dose were considered for action.

Extensive short term and long corrective actions for chemistry

sampling were established which would be implemented over a number

of months. However, the licensee's V&V process would not have

identified these problems since the V&V efforts as implemented

were exclusive to operator actions and did not extend to support

personnel. This limitation in the way the V&V process was

implemented also explained why the licensee had not identified the

need for TSC procedures as discussed in section 03.1.b.3. Failure

to ensure chemistry actions could be performed when directed by

the E0Ps was another example of violation. VIO 50/302-97-12 01.

" Inadequate Implementation of Teil Action Item E0P Order,' 'n that

instructions were not complete and compatible with condit Lns

(differing electr_ical bus availabilities).

3. In December 97 and January 98. following completion of the

_

.

(  !

12

-

licensee's V8V of the E0Ps. the team noted improvements with .

respect to delineating the preferred ingress egress pathways,

support tools and equipment, and determining expected duration '

times necessary to complete activities., These additional actions

were the result of management providing a list of expectations for

performing in plant validations which will be incorporated

directly into Al 402C.

However, some of the team's October 97 concerns were not

odequately addressed. These included the lack of radiological

mission dose assessments for numerous in plant E0P actions and the

questionable ability to perform post accident RB hydrogen control

actions.

(a) On 3/3/97 the licensee initiated PC3 C97-1533 identifying

concerns with operators accessing a MCC in the intermediate

building following a SBLOCA due to the environment. This

concern expanded into restart issue D65. " Post Small Break

LOCA access to Intermediate Building and Auxiliary Building

for required operator actions." As part of the resolution

to the extent of condition for the PC and D65 the licensee

determined that there were " required" and "not required"

actions primarily based on a vendor analysis of E0P in plant

operator actions completed in July of 1997. This analysis

was based upon whether alternate actions were available to

perform the same function. The analysis did not evaluate

whether the actions could be accomplished based upon

radiological conditions. Also, the E0Ps or the V&V of the

E0Ps did not take into consideration whether an action was

" required" or "not required." Therefore, all E0P actions

would be attempted, whether accessible or not.

On 10/18/97 the licensee initiated PC3-C97 7125 on the lack

of a radiological dose assessment for initiating OTSG

blowdown following a SGTR. The PC was dispositioned to

perform the dose calculation by 3/30/98, after the scheduled ,

restart of the reactor. The PC further stated that this was

not a required action. following the )hilosophy used to

disposition PC3 C97-1533. This was tie rationale as to why

a large number of in plant E0P actions such as initiating

OTSG blowdown, aligning high pressure auxiliary spray and

equalizing pressure across the MSIVs did not have dose

assessments.

As previously mentioned. NUREG 0737, l.C.1. required in

part, via the Confirmatory Order issued February 21. 1984,

that licensee validation programs ensure that instructions

to operators in emergency procedures be compatible with the

conditions. Also. NUREG 0737, ll.B.2. " Design Review of

Plant Shielding and Environmental Qualification of Equipment

for Spaces / Systems Which May be Used in Postaccident

_ _ . . . . _._.._._____ _ _ _ _ _ _ ._ _ _ . _ . _ . _

__. ___ __ . _ _ . _ _ _ . _ _ _ . . _ _ _ _ _ _ _ _ _ _ _ . _ _ _ _ ._ _

(

l

13 - 1

Operations.' stated that licensees were to provide adequate

'

access to vital areas to increase the capability of  ;

operators to control and mitigate the consequences of an

accident. Per 11 B.2, a vital area was defined as, "Any

'

area which will or may require occupancy to permit an

operator to aid in the mitigation of or recovery from an

i accident is designated as a vital area." The licensee was i

required to comply with NUREG 0737. Criterion II.B.2 in a

-

Confirmatory Order issued March 14, 1983.

'

'

Due to the incdequate disposition of PC3 C97-1533, an

untimely corrective action was specified in PC3 C97 7125.

Also, due to an inadequate extent of condition disposition

of PC3 97 1533 the licensee did not comply with the 2/21/84

Confirmatory Order associated with NUREG 1.C.l. the 3/14/83

Confirmatory Order associated with NUREG 11.B.2 or

Administrative procedure Al 402C AP and E0P Verification

and Validation plan. Enclosure 5. Evaluation Criteria for

Procedure Validation, which required an assessment to ensure

in plant actions are not hampered by inaccessibility or

environmental conditions. 10 CFR 50. Appendix B, Criterion

XVI. Corrective Action, requires conditions adverse to

quality be promptly identified and corrected. Failure to

adequately and promptly correct the conditions adverse to

quality identified in PC3 C97 1533 and PC3-C97 7125 is an

exemple of violation. VIO 50/302 97-12-02. ~1nadequate

Corrective Actions." of 10 CFR 50. Appendix B. Criterion

XVI. ,

(b) The licensee wrote a new E0P 14. Enclosure 21. RB Hydrogen

Management, to bring the actions for post accident

containment hydrogen management into the E0P network.

During the inspection the licensee decided to leave these

actions in OP 417. Containment Operating Procedure. Rev. 73,

due to questions concerning equipment and personnel

availability to install flow elements and the actions would

not be required until at least ten days after the accident.

However, neither the E0Ps nor the TSC 3rocedures directed

the operators to implement OP 417 if R3 hydrogen levels

increased. This is another example of the 1984 Confirmatory

Order violation. VIO (50/302-97-12 01) ~1nadequate

'

Implementation of TMl Action item E0P Order." in that

instructions were not complete. Also. OP 417. step 4.8.2.

directed I&C to install flow instrumentation but, no 6se

calculations were performed for this job. This is another

example of inadequate corrective action violation. V10

50/302 97 12 02 ' Inadequate Corrective Actions."

--

-. - - - .

14

4. In December 98 and January 98, the team identified other s

and general deficiencies reflecting inadequacios in theV V&pecific

process for in plant actions. These included: ,

• During a SGTR simulator scenario, the SPD was unable to find

the correct fitting in the E0P box for venting the OTSG

blowdown line prior to placing the line in service per E0P.

14. Enclosure 6. step 6.3. There were cver ten fittings in

the box but only one of the fittings would have fit. This

box contained equipment associated with numerous E0P

enclosures, not just Enclosure 6. and the licensee did not

dedicate this unique fitting for Enclosure 6 within the box.

The licensee initiated PC3-C97-8459.

• Adequate support staff was not designated to perform the E0P

actions. Two chemistry personnel were necessary to

reasonably accomplish E0P actions. Although two were

normally on shift, only one was required by the licensee's

administrative procedures. E0P 06. SGTR. step 3.15 required

maintenance personnel to repair a MSSV that would not

reseat. The licensee did not maintain qualified maintenance

personnel on back shifts to perform this E0P action and no

administrative procedure required their presence.

• In January 97, during an SB0 simulator scenario, the team

observed operators attempt to implement Enclosure 1 of AP-

770, Failed EDG Recovery, when directed to by E0P 12. 5B0.

At step 3.1 the crew could not perform a reset of relay EDG

86, stopping the recovery. The location and the alpha-

numeric designator of the lockout relay was mis stated in

the procedure. The licensee initiated PC3-C98 0103.

These inadequacies were indicative of not always dedicating E0P

equipment to a s

expanding the V&pecific

V process task or enclosure,

to include notperformed

E0P actions adequately

by

personnel other than operators and, less rigorous V&V efforts for

E0P actions not specifically delineated in an E0P. Also, these

were additional examples of violation. V10 50/302-97-12 01.

" Inadequate implementation of TMI Action item EDP Order " in that

the E0P instructions were not complete or usable.

5. Other less significant weakness observed by the team in Occember

97 and January 98 were:

. During the performance of a simulator scenario on 12/9/97,

the team observed the PPO performing the actions specified

in E0P-14. Enclosure 18. Control Complex Chiller Startup, as

directed by the control room operators. The PPO completed

the enclosure and verified proper operation of the cailler.

Subsequently the PPO was requested by the control room

operators to perform step 17.8 of Enclosure 17. Control

_ _ _ _ _ _ _ __ -_

15

Complex Emergency Ventilation, which required actions to

align the chilled water source to the running fan. The PPO

opened the CHV-2 valve and closed the CHV 4 valve to

complete the alignment. During the scenario activities, it

was determined that if the alignment actions required in

step 17.8 of Enclosure 17 (i.e , flow balancing) were not

performed properly, the running chiller unit could trip.

Additionally if the chiller unit was tripped in this manner,

re establishing chiller operation could require an

additional 30 minutes. T11s possible negative interaction

between the actions specified in the enclosures was not

recognized as part of the licensee's verification and

validation efforts. This is an open item pending further

analysis and review. IFI 50/302 97-12 03. " Enclosure 17/18

Interaction."

. While performing an 580 simulator scencrio the PPO was

directed to open the EFIC cabinet doors to enhance cooling.

He accomplished the task within the time critical criteria

but was slowed down by the lack of specific labeling as to

which key went to which EFIC cabinet door.

. Some of the signs. indicating which EFIC doors were to

opened in an SBO were not placed in the optimum human

factored location. Subsequently, the licensee placed the

signs in the optimum location.

'

. The ladder for operating valve SWV 60 in E0P-14. Enclosure

18. Control Complex Chiller Startup, was not optimal.

6. Throughout the inspection (including October), the team observed

that the operator actions within the control room could always be

performed with the labeling in the procedure consistent with the

simulator.

7. Throughout the inspection period the tearn found the V&V records to

be a comprehensive accounting of the issues raised during the E0P

development process, including operator comments, training

personnel observations. in plant walk down evaluations, and the

resolutions im)lemented for each issue. Additionally, the

validation boot contained a list of all procedural steps evaluated

during similar exercises with the operating crews to ensure all

potential mitigation paths through the E0Ps were formally

evaluated during the V&V process. Overall, the team considered

the detail captured in the V&V evaluation records to well be

detailed and thorough. However. the V&V efforts as captured in

these records concentrated upon control room operator actions and

discrete in plant operator actions. There had been limited V&V

efforts integrating control room and the in plant operator actions

and no efforts involving non-operators.

_ .

- - - -

- - . - _ . - - -- - - - - - ._.-

! i

!

1

l

,

16  !

6

c. Conclusions

At the beginning of the inspection, the licensee's in plant portion of

i the V&V process, which was being performed on the draft E0Ps while the

i

team was onsite. was insufiicient. There were no specific concerns  !

l regarding the control room portion, based upon documentation. In

! response to the team's perspectives, the licensee provided additional

l guidance to the personnel performing the V&V. and the team noted

i im>rovements. However, even with the improvements, the team identified

'

otler specific and general deficiencies reflecting inadequacies in the

i V&V process for in plant actions due to not always dedicating E0P l

l equipment to a specific task or enclosure, not adequately ex)anding the

i V&V process to include E0P actions performed by personnel otler than

operators and, using less rigorous V&V efforts for E0P actions not

specifically delineated in an E0P. There were examples of a violation.

Also, some of the team's original concerns were not adequately

addressed, partially due to inadequate correction actions to a problem

previously identifed by the licensee associated with operator in plant

,

accessibility.

This disparity between licensed operators being able to perform control

room E0P actions and non licensed and support personnel not always being

j able to perform in plant E0P actions was consistent with the way in

which the V&V process was established and implemented. Consecuently.

l the actions directed by the E0Ps within the control room coulc always be

performed, but numerous in plant actions either could not be performed  ;

i due to the lack of support perr.onnel. lack of properly stagged

equipment, technically incorrect procedure steps, not incorporating the

i

'

actions into procedures or the radiolog1 cal consequences of performing

the actions had not been assessed,

,

03.3 Writer's Guide for E0Ps

a. Insnection Stone (42001)

i

The team reviewed the liansee's E0P Writer's Guide for Abnormal and

. Emergency Opnating Trc edures (Al 402A. Rev. 8) to ensure that it

. adequately addressed e n eloping procedures consistent with NUREG 1358.

Supplement 1. " Lessons Learned from the Special Inspection Program for

'

Emergency Operating Procedures," The team reviewed the E0Ps to

,

determine if the guidance in procedure Al-402A, Rev. 8 was adhered to

,

during the development of the E0Ps and referenced procedures. The team

observed operators during simulator scenarios to determine whether the

steps were readable and the actions clear.

>

b. Observations and Findinos

The team determined that the writer's guide described the aspects of

procedure step development, including format and layout considerations.

4 procedure developer responsibilities, and step construction requirements

in a comprehensive manner The E0Ps adequately conformed to procedure

i

-._,-.--,..._.-__-m-.. ,,..w., ,,-,-,m_rm-,n_._-.,-,_,r. ..,_ .,-., v_ ,,,,,.,% r,v-_-___.

_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ . _ _ _ _ _ _ _ _ _ _

17

'

Al 402A, Rev. 8. The definition section did reveal ambiguity in the

definitions of the terms " verify" and " ensure." Because of the

significance of these terms as implemented in the E0Ps. a clear

differentiation between the definitions was imperative. The licensee

stated the definitions would be reviewed and rewording considered to

better reflect the expectations for the terminology. However, rarely,

during simulator scenarios, did the team observe operators having

trouble reading or understanding the direction provided in any E0P step.

c. Conclusions

The E0P Writer's Guide was comprehensive and adequately implemented in

the construction of the E0Ps. This contributed to operators rarely

having trouble reading or understanding the E0P steps during the

simulator scenarios.

03.4 [0P User's Guide

a. Insoection Stone (42001)

In October 97 the team reviewed the licensee's draft E0P 'Jser's Guide.

Conduct of Operations During Abnormal and Emergency Events (Al 505. Rev.

2). to ensure that it adequately addressed roles and responsibilities of

crew members and described the expectations for procedure usage. This

included the communications protocols required to correctly implement

the E0P mitigation strategies. In December the team reviewed the PRC

approved guide.

b. Observations and findinas

The team determined that procedure Al 505 provided sufficient guidance

regarding the roles and res)onsibilities of the operating crew members,

communication protocols to )e observed during transient response,

methods and expectations for procedure step usage including transitions

and immediate actions. The guidance also described the expectations for

procedure compliance, priority of symptoms for entry into the E0Ps. and

exceptions to the arioritization scheme. Generally, the draft guidance

was sufficient wit 1 the following weaknesses:

. Section 4.1.1.3 Performing steps out of Sequence, allowed the

crew to de) art from the pre defined sequence of mitigation steps

provided t7e step transitioned to: 1) could be carried out to

completion. 2) was within the. current procedure in use and 3)

delaying carrying out the step would negatively impact the

mitigation attempts. Additionally. the procedure recommended

prior Nuclear Shift Supervisor (NSS) concurrence with such a

departure. During an October simulator exercise. the team

observed the crew implement this rule. When questioned the crew

responded that NSS concurrence was required not merely

recommended. The team noted that the licensee did not have any

administrative controls to evaluate sequence deviations and

_ _ _ _ _ _ _ _ _ _ _ - __ _ _____ _ __ _ . _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _

18

'

operating crews could consistently use this method without

realizing that a step was mis placed. Additionally, a departure

from the pre determined mitigation strategy might negatively

impact the mitigation strategy and any such departures should have )

a sound technical basis. In the December version of Al-505 ,

sequence deviations were required to be evaluated. l

• Section 4.2.1.3, Exceptions to Symptoms, defined four situations

which were exceptions to the protocol of entering the highest

)riority E0P based on the ap)earance of the predefined symptoms.

~

rom the initial review of t1e E0Ps it was not clear that these

exceptions were directly defined in the E0Ps which might be

affected by such conditions. Subsequently, the licensee

highlighted the four situations in the applicable E0P sections.

c. Conclusions

following revision, the licensee's E0P User's Guide was acceptable.

03.5 E0P Maintenance J Revision Guide

a. Insnection Scone (42001)

The team reviewed the licensee's E0P Maintenance & Revision Guide, New

Procedures and ProcedJre Change Processes for E0Ps, APs, and Supporting

Documents (Al 400F, Rev. 4), except for sections 4.11 and 4.12. to

ensure that it adequately addressed aspects of procedure maintenance and

revision necessary to ensure the retention of quality procedures during

the facility operating life.

b. Observations and F1ndinos

, The team verified that the guidance adequately described the

responsibilities of individuals sked with E0P revisions,

differentiated between minor and gnificant changes. and described the

processes to be implemented for revision and modification of the

procedures and supporting bases documentation.

c. Conclusions

The maintenance and revision procedure was adequate. The scope of the

NRC review did not include set point control.

04 Operator Knowledge and Performance

a, insocction Scope (4200D

During the three onsite weeks, the team observed licensed and non-

licensed ope:itors respond to simulated emergency conditions developed

by the team to test specific sections of the E0Ps. The licensed

operators were in the simulator and the non licensed operators were in

-. . -. _.

_ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ __ _ ___ - _ _- _ ___ - _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ - _ _ _

10

the actual facility.

'

'

The non licensed and licensed operators

communicated to each other via portable radios. The team evaluated )

operator performance with respect to whether the procedures were l

foll0wed, the administrative controls of procedure Al 505 were followed I

and whether management expectations were met,

b. DMervations and Findinos

The team determined that the operating crews were capable of mitigating

the transients presented. Three party communications were routinely

used by all operating crews and place keeping was adecuate to maintain

control of the mitigation actions. Also, the crews acequately

implemented the required carry over actions when the conditions were

satisfied for entry into specific carry over ste)s. Indicative of this

performance was the successful execution of the E0Ps in response to a

simulated SBLOCA with a failure of the B battery. All operators

accomplished their tasks and all time critical tasks, such as starting

the control rooms fans and chillers, were accomplished within their

required time frames.

However, there were some examples of performance inconsistent with an

E0P step. licensee management expectations as emphasized in operator

training or the licensee's administrative guidance. These examples were

partially due to individual performance errors and partially due to

training deficiencies. Specifically:

. In October 97. during a SGTR scenario with a stuck open MSSV the

crew elected not to transition from E0P 06. SGTR. to the higher

priority E0P 05. Excessive Heat Transfer, even though they met the

entry conditions. Follow up questioning revealed that the SR0s

could not state that E0P 06 contained all the required steps the

crew missed by not transitioning to the excessive heat transfer

E0P.

. In December 97, during a LOCA, the procedure reader had to be

reminded to review the symptoms after completing the immediate

actions of E0P 02. Also, in January during a S80, the team

continued to observe a weakness in scanning for symptoms after

performing immediate o)erator actions. The operating crew did not

enter E0P 12. Station 31ackout. until prom)ted twice during the

5B0. Six minutes elapsed from the time EO) 04. Inadequate Heat

Transfer (a lower priority symptom) was entered until the crew

transitioned to E0P 12. The licensee initiated PC3 C98 0104 on

this situation.

. In December 97 and January 98. when given an additional task while

performing another task. SP0s occasionally continued with the

first task before performing the second task. The SPGs did not

inform the control room licensed operators of the conflict and

request direction as to which task to perform first, which aer the

licensee was the appropriate response. As an example, an S'O

__

_ - - __ - __ __ _- - - ._- _. - .. _ _ - _ - _ _ . - - - . - .

I

20

-

continued closing MSV 301 & 303 once directed to shut a failed I

open ADV during a SGTR scenario in January.

. In December, during tube ruptures in both OTSGs the crew was

confused at E0P 03, Step 3.15 for securing feed to the affected

OTSG since both OTSGs had tube ruptures.

Depending upon the significance of the problem: the licensee initiated a

precursor card, was evaluating the observation for feedback into the

training program, or was providing feedback to the individual involved

as part of the continuing training process,

c. Conclusions

The operating crews were capable of mitigating the transients presented

by the team. However, there were some examples of performance being

inconsistent with an E0P step, licensee management expectations or the

licensee's administrative guidance. These performance problems were

being dispositior.ed consistent with their significance.

05 Opitator Trainina and Qualification

a. Inspection Stone (42001)

The team reviewed selected training records to determine whether

licensed personnel had been trained on the recently revisad E0Ps. The

trainirg records reviewed included lesson plans, simulator exercise

descriptions. E0P simulator evaluations, and E0P/AP revision

documentation. The team reviewed one aspect of non licensed operator

training associated with the turbine driven emergency feedwater pump.

b. Qugervations and findinas

The team determined that the lesson plan information was detailed. The

simulator exercise evaluation forms were self critical and ex) licit

regarding performance weaknesses and the reasons for such weacnesses.

The E0P training update packages. information considered different from

the initial training due to E0P/AP changes, were dctailed.

During one of the December scenarios. consistent with the E0Ps. a

licensed operator directed an SP0 to monitor the performance of the

turbine driven emergency feedwater pump for proper performance. The

team ascertained that the SP0s did not receive formal training on

resetting the over speed trip on this equipment. This was considered a

weakness of the SP0 training program. Prior to the end of the

inspection period, SP0s were trained on resetting the over speed trip.

The team satisfactorily reviewed the training material along with the

list of SPO attendees.

. - _ - _ - - , . - - - . _ _

. _ _ _ _ _ - _ _ _ _ _ - _ _ _ _ _ _ _- _ _ _ _ _ _ _ . . _ _ ___ __ _ ______

21

c.

'

Con _tlusions

,

The E0P/AP training program for licensed operators was adequate to

familiarize operators with the E0Ps/APs, including procecure changes,

end to assess operator performance while using E0Ps/APs while in

training. There was e program weakness of not training non licensed

secondary plant operators on resetting the emergency feedwater turbine's

over s)eed trip. The licensee provided corrective actions consistent

with t1e significance of the weakness.

08 Misse.llangppsOperationsissurs

08.1 [0PContentWeaknesse51 While observing the simulator scenarios, the

team noted select areas where the licensee's E0Ps did not optimize the

equipment available to mitigate the situation. These were:

. Not optimizing existing plant systems to provide makeup water to

the secondary or primary sides of the plant, if necessary, in E0P-

02, VSSV, in response to an ATWS.

. Not including procedural direction in E0P 07, Inadequate Core

Cooling, to consider using the condensate booster pumas if all the

other supply source (EFW, AFW, MFW) prime movers to tle OTSGs were

not available.

. Not providing a local procedure to start the AFW diesel if it

should not start from the control room.

The licensee acknowledged these observations and indicated that they

would be reviewed for possible action.

08.2 ICloseO URI 51 v ?/96 06 10: Justification for Removal of Thermo Lag

Protection from aurce Range Instrumentation

lhe immediate actions of E0P 02. Vital System Status Verification. Rev.

4. step 3.3, required immediate emergency boration of the RCS until the

reactor was shutdown if nuclear instrumentation did not indicate the

reactor was shutdown following depression of the reactor trip push-

button. These actions were consistent with the TBD. E0P-10. Post-Trip

Stabilization. Rev. 3. step 3.4 recuired RCS boron sampling if the

source range instrumentation failec. These actions addressed the loss

of source range instrumentation via fire which would not involve

evacuation of the control room. Therefore, this matter is considered

resolved.

II. Main _tenance

M3 Maintenance Procedures and Documentation

M3.1 [ontrols for Maintrnance in PrpximitY to In-Plant E0P Actions

. . _ _ _ _ _ _ _ _ _ _ _ _ .. _ _. _ _ _ __ _ _ _ . _ _ _

l

22  ;

3

r

4  :

a. Insoection Scone (42001) i

As a result of the extensive scaffolding erected within the facility  !

! while the plant was in cold shutdown, the teem evaluated whether the

work control process included consideration that the work could impact

in plant E0P actions by inhibiting access to those locations. ,

1

b. Observations and Findinas , t

i

As a-result of the team's questions in this area, the licensee

determined that no procedural controls existed to evaluate whether

'

maintenance activities could affect E0P in plant actions. The licensee

'

initiated PC 3 C97 7923 on this matter. At the end of the inspection

the licensee was formulating the corrective actions which the licensee

verbally indicated would include adding these administrative controls to

the work control process.

'

c. Conclusions

The work control process did not consider that the work could inhibit  :

access to in plant E0P action locations. The licensee was formulating

corrective actions to this weakness under their established corrective

> action program.

M3.2 Surveillance Proaram for ECCS Exte,nal Leakaae Associated with HPI

1

Picavback

a. Insoection Stone (42001)

The team reviewed the licensee's program to meet TS 5.6.2.4. " Primary

Coolant Sources Outside Containment." to ascertain whether components

(piping, valves, etc.) of the HPl piggyback function had been included

l in the program. TS 5.6.2.4 required a program to provide controls to

minimize leakage from those portions of systems outside containment that

could contain radioactive fluids during a serious transient or accident

to levels as low as practicable. The systems include Low Pressure

. Injection. Reactor Building Spray, and Makeup and Purification. The

'

program included the following: a) Preventative maintenance and

periodic visual inspection requirements: and b) Integrated leak test

requirements for each system at refueling cycle intervals or less.

b. Observations and Findinos

'

The team determined that Com311ance Procedure (CP) 149. Primary Coolant

Sources Outside Containment Program. Revision 2. implemented this TS

'

required program. In response to the team's westions regarding the-

piggyback function, the licensee reviewed-the issue in detail and

identifled that portions of the HP1 system were not included in CP 149.

4 The' licensee initiated PC 3 C97-8496 on December 13, 1997, to resolve

this deficiency. -During the PC follow up, the licensee further

identified that there was not a program to meet the periodic inspection

_ _ . - _ _ . - _ _ _ _ . _ _ _ _ _ . _ . _ . _ _ _ _ ___ . _ . . __

_ _ _ _ _ _ . _ _ _ _ . _ _ _ . _ . _ _ _ _ _ _ _ . . _ _ _ _ _ _ _ _ _ _

-

l

,

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'

23

<

requirement. These inadequacies were a violation of TS 5.6.2.4. The  :

team reviewed the licensee's planned corrective actions for the PC and

determined that the corrective actions would adequately correct the ,

deficiencies. Also, when all applicable external leakage that presently l

existed was tabulated, the post-accident dose consequences requirements -

were not exceeded. This licensee identified and corrected violation is

being treated as a Non Cited Violation. NCV 50/302 97 12 04. " Inadequate

External Leakage Surveillance Procedure." consistent with Section

,

VII.B.1 of the NRC Enforcement Policy.  ;

c. Conclusions

The licensee's program for implementing TS 5.6.2.4 was not adequate, but

the actual external leakage did not exceed post-accident dose

consequences requirements. The licensee was taking appropriate

corrective actions to correct this non-cited violation.

M3.3 echnical Content of Periodic Inventory Proaram for In Plant E0P,

inment

a. Insce-tion Scoce (42001)

In January the team reviewed the E0P/AP toolbox surveillance checklist

to ensure that the necessary tools were properly staged in the

designatedlocationsconsistentwithSP-306.WeeklysurveillanceLog.

This was accomplished by selectively observing whether the contents of

E0P/AP tool buxes contained the equipment listed on the licensee's

surveillance checklist. The team also verified whether all the keys

required for E0P/AP implementation per SP-306 were in the designated key

box in the control room,

b. Observations and Findinas

The team observed one difference between the box and the checklist for

the boxes reviewed. E0B-06 contained two female fittings while the

checklist required at least three. The licensee immediately placed

another fitting into the box and initiated a precursor card. After

preliminary evaluation the licensee verbally informed the team that the

checklist was in error. All keys were present in the control room key

box. The keys contained a number ossignator consistent with the E0Ps.

They did not include a label with the s)ecific pur)ose for the key which

could reduce confusion in identifying tie correct cey. Most of the tool

boxes were not physically restrained. When the team questioned the

licensee, the team was informed that~the boxes had been previously

walked down and satisfactorily evaluated by engineering personnel.

c. Conclusions

The technical content of the periodic invantory controls for in pla ;

E0P equipment was adequate.

- .. -- -. - . - . . - _ _ _ . - _ - _ - - - . _ . - - , - . -- --

_ _ _ _ _ _ _ _ _-__ _ _ _ _ . _ _ _ _ _ _ _ _ _ _ _ _ _

24

' III. Enaineerina

El Conduct of Engineering

E1.1 Csiculations Sucoortina E0P Actions

a. Insoection ScoDe (42001)

During the onsite weeks the team reviewed several engineering

<

calculations supporting E0P actions or set points. The team reviewed

these calculations for accuracy, appropriate assumptions, and compliance

with applicable standards. The applicable standards included:

Instrument Society of America (ISA) 67.04, part 11. as referenced by

instrumentation and controls Design Criteria Instrument String Error / Set

point Determination Methodology and ANSI 45.2.11. 1974. Quality

Assurance Requirements for the Design of Nuclear Power Plants,

b. Observations and Findinas

,

The team's observations and findings were:

1. During the first onsite week (October), the majority of the

calculations su) porting the E0Ps were being created or revised.

Therefore, the aulk of the calculations reviewed during the first

nnsite week were issued prior to 1995. During the second onsite

week (December) some of the calculations were still being created

-

or being revised, partially due to corrective actions from the

team's observations during the first onsite week. A substantial

portion of the calculations were completed just prior to the '

team's arrival onsite. Therefore. during the second on-site week.

only a limited number of these newer calculations were reviewed.

During the third onsite week (January), a slightly larger sample

of the newer calculations were reviewed.

2. During the first onsite week, numerous E0P instrument loop

calculations contained the same errors as discussed in NRC

Inspection report 50-302/97 01. The calibration temperatures were

not specified and the procedures for calibration of instruments

located in the AB did not assure that the AB temperatures were

maintained within the temperature ranges assumed in the instrument

loop uncertainty set point calculations. Additionally, other '

calculational assumptions were not verified. An example was

calculation 190-0022. Revision 0, associated with EFW flow which

assumed the transmitters in the AB were calibrated at 75'F.

However, the full temperature range was 55 - 95*F. Therefore, the

instrumentation could be calibrated at the low end of the

temperature band and operated in the high end. This would induce

a process bias in the instrument loop uncertainty not accounted

for in the calculation, The licensee documented the error in

calculation 190-0022 on PC 3-C97 7154. Another example was

.

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- .- - --. - - - - . - . - - - . - - - - - - - - . - . . -

l

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1

25

1

'

5

documented in PC 3 C97 8447. The PC was written to document

Analysis / Calculation deficiencies identified when assessing the '

loop uncertainties in 191 0028 Revision 1. FWP-7 Flow Indication,

j The calculation failed to include ambient temperature effects,

static pressure zero effect, static pressure span effect, static ,

pressure, span shift. and other process effects due to temperature

and pressure.

The extent of the licensee's corrective actions to Violation 50- I

'

302/97 01 07. Instrument Loop Uncertainty Set point Calculation

Assumptions Not Translated into Procedures, was inadequate. 10 '

l

1 CFR 50. Appendix B. Criterion XVI. Corrective Action, requires

l conditions adverse to quality be promptly identified and

3

corrected. The licensee's failure to identify and correct

calculations supporting E0P related set points as part of the

2 corrective actions for Violation 50 302/97 01 07 is an example of

'

an inadequate corrective actions violation. V10 50 302/97-12 02.  :

" Inadequate Corrective Actions."

3. During the December onsite week, one of the few existing <

'

radiological dose calculations was determined as inadecuate.

Calculation M93 0006. Rev. O. determined the post accicent mission

, doses to purge the RB for hydrogen control. The calculation

'

assumed a non conservative time frame to initiate the purge as

well as other errors. The doses were calculated starting 25 days

after the accident. FSAR Section 148.3.3 stated that purging may

start as early as 250 hours0.00289 days <br />0.0694 hours <br />4.133598e-4 weeks <br />9.5125e-5 months <br /> after the accident. Also, the time

'

assumptions for operating valves were not validated. Step 4.9.8.2

of OP 417. Containment Operating Procedure, directed throttling

open LRV-121 or 123 and establishing a calculated flow rate, lhe

i time to accomplish this step was assumed to be 5 minutes. This.

time was not validated and may be non conservative since the valve

>

was located approximately 10 feet from the flow indicator and the

flow indicator would be facing away from the valve. The licensee

documented the problems with this calculation in PC 3 C97 8366.

The licensee's Quality Assurance Program as described in the USAR

listed ANSI 45.2.11. 1974 " Quality Assurance Requirements for the

Design of Nuclear Power Plants." under the committed standards.

ANSI 45.2.11, subsection 3.2 states in part "The design input

"

shall include but is not limited to ... Environmental conditions

anticipated during ... operation such as ... nuclear radiation."

and .. " Operational requirements under various conditions such ,

as ... plant emergency operation . " Failing to consider

radiological effects properly during the design input is an

examale of - violation. VIO 50/302 97-12 05. " Poor Calculations."

of A4SI 45.2.11.-

>

4. Numerous other calculations issued prior to 1995 were not

consistent with ANSI 45.2.11. subsection 4.2. This subsection

. states " Analysis shall be sufficiently detailed as to purpose. '

.

k

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. . _ . , w. ,7___m., y v-e w,.--,,.- ,m ,,w-,.-,- %,.. ,,.m ,,-.--_.,_.,_w.myw,-wy my_ _ _

. ._ _ __ _ _ _ . _ _ _ _.__ _ _ _ ._ ._ _ _ _ _ _ _ ._ ,

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26 )

-

method, assumptions, design input. references and units such that

a person technically qualified in the subject can review and

understand the analyses and verify the adequacy of the results

without recourse to the originator." As an example.. Calculation

"

E 90 0023. Evaluation for Containment Spray between pH 4.0 and

12.5. assumed a corrosion rate for carbon steel pi j

,

a boric acid containment spray of 50 mil per year. The ping exposed to ,

, calculation stated that the expected corrosion rate was 10 mils

but, corrosion rates could be greater than 50 mils. Nowhere in '

the calculation was the rational for the selected corrosion rate

provided. Upon identification to the licensee, the licensee

initiated a precursor card report. This is an example of '

. violation. VIO 50/302 97 12 05. " Poor Calculations," of ANSI

. 45.2.11.

5. Although a small sample size was reviewed by the team, the

calculations issued in 1997 were far better and did not contain

any of the errors discussed above. Only one minor problem in the

"new" calculations was observed. This was the failure to

reference an affected calculation when a value in the base

calculation changed.

c. Conclusions

calculations issued prior to 1995 contained numerous errors.

q

Generally,ly,

Occasional the calculations did not contain enough information to

enable a person, who was technically qualified in the subject, to review

and understand the analyses and verify the adequacy of the results.

This was a violation. Prior to the team's arrival, the corrective

actions to known calculational inadequacies had not extended to the E0P

set point calculations which was an example of an violation. Although a

small sample size was reviewed by the team, the calculations issued in

1997 to support E0P set points were far better.

El.2 Low Pressure in.iection Crossover Mode of Operation

'

a. Insoection Scone (42001)

Due to the licensee not directing the crossover mode of LPI operation be

used in the E0Ps, the team reviewed the licensing basis documents for

long term core cooling following a LOCA as discussed in 10 CFR 50.46 and

10 CFR 50. Appendix K, These documents included B&W topical re) orts,

the licensee's FSAR, a safety evaluation to change the current SAR and

applicable correspondence. Also, the team reviewed the NRC's SERs

associated with ECCS with respect to long term core cooling.-

b. Observa.1fons and Findinas

1. The team determined that during at least two time periods after

the operating license was vranted. there was no procedural

guidance to use the LPI crossover line with flow split between the

.- .- -. _ - - .- .- -.--.- -

-- - .- . . -- - ----.- _.

I

27

two LPI lines (the crossover line method of long term core ,

cooling, option #1 in BAW 10103A and BAW 10104) to mitigate the  !

'

consequaices of a LOCA. The first time period was from 7/79 until  !

6/89. The second time period was 5/2/96 until the issuance of

, Procedure EH 225E. Guidelines for Long Term Cooling, on 1/27/98.

EM 225E was issued, due to the NRC E0P inspection team identifying

the lack of such a procedure to the licensee in December, 1997.

Originally, depending upon plant conditions, the licensee used the  !'

. crossover line method of long term core cooling in two procedures.

l The procedures were EP 106. Loss of RC/RC Pressure, and OP 404.

Decay Heat Removal. In 1979 both 4

that EP 106 referenced OP 404 and, procedures

in Revision 24 dated were7/3/79

revised of such i

OP 404, the use of the crossover line method was deleted.

.

in June 1983 the licensee instituted the first set of symptom

based procedures for dealing with transients and accidents with

AP 380. Engineered Safeguards Actuation, superseding EP 106. In

Revision 20. dated 6/29/92 of AP-380. a new step 3.8 was added

directing use of the crossover method if an LPI pum) was

unavailable. Also. Revision 73, dated 6/12/89 of 0) 404, re.

'

instituted the use of the crossover lines with flow in both

injection lines provided there was adequate subcooled margin in

section 4.13. In Revision 83, dated 3/4/92 to OP 404, the use of

the crossover line method of core cooling was transferred to

section 4.12. However, step 3.8 to AP-380 was deleted in Revision

22 on 4/8/93 and, section 4.12 to OP 404 was revised on 5/2/96 in

revision 101. Revision 101 removed the crossover method along

with the deleting the pressurizer auxiliary spray as a boron

precipitation control method. Therefore, for a second time

period. 5/2/96 until the NRC E0P inspection identified to the

licensee in 1997, there was no procedural guidance on using the

crossover line method of long term core cooling. Section

6.1.2.1.2. Low Pressure injection, in the licensee's USAR stated

"The LPI System is provided with a crossover line to permit one

LPI string flow of 3.000 gpm to be split equally, thus providing a

minimum of 1.500 gpm flow to both core flooding injection nozzles

simultaneously should a core flooding line or one LPI pump fail.

Redundant transmitters and indicators are provided for LPI flow

me:surement and indication. The LPI crossover injection mode of

operation is accomplished by opening the crossover line, provided

with a two way flow element between the separate and independent

LPI strings, and remotely adjusting the flow through the crossover

line to 1.500 gpm via two (one in each LPI string) electric motor

operated valves (see Figure 9 6).'

Section 14.2.2.5.4 ECCS Qualification, stated that "In order to

qualify the ECCS. the NRC placed requirements on the ECCS to

ensure that the health and well being of the puolic is not

impacted. These requirements are specified in 10 CFR 50.46 and 10

CFR 50. Appendix K. The criteria contained in Part 50.46 are

.

F

'

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__ . . __ _ . _ _ _ _ ____ _ _ _ .__. _ . _ _ _ ._ _ __._-

t

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28

applicable to all sizes of LOCAs and are necessary in order to

verify adherence These criteria are as follows ... A path to i

long term cooling must be established." This section further

stated that BAW 10104. Rev. 3, was the methods report on how the

computer model used to ensure compliance with 10 CFR 50.46 will be

assembled and run. Also, the "The LBLOCA application report for

'

the 177 FA lowered loop plants is BAW 10103A

Topical Report BAW 10103A. Rev. 3. "ECCS Analysis of B&W 177 Fuel

Assembly Lowered loo) NSSS." and Topical Report BAW 10104. Rev. 3.

"ECCS Analysis Of B&W's 177-FA Lowered loop NSS ~ discussed use of

the LPI crossover in Chapter 10. Long Term Cooling. Section 10.2

stated in part that "Several alternate modes of operation of the

ECC systems can be used during long term cooling, if necessary,

while maintenance is being performed on normal equipment:

1. One LPI pump operating with crossover line valves open: flow

split between the two LPI lines by the control valves.

2. Each LPI string operating and the LPI pump in each LPI

string operating and pumping through its own injectio,' line.

3. One LPI pump operating with injection through its associated

injection line and with the crossover to the associated HPI

string open: the associated HPl pump would be pumping

through its HPI lines."

'

Section 10.2 further stated in part that "With either of the two

LPI pumps operable. ECCS injection flow can be maintained through

two flow paths."

Pending further NRC review of the safety evaluations associated

with these procedural changes (revision 101 to OP-404 on 5/2/96

and revision 24 to OP 404 on 7/3/79), this matter is considered

unresolved. URI 50 3t?/97-12 06. " Previous LPl Crosstie Safety

Evaluations."

'

2, The team determined that the a recent change to the FSAR

describing the LPI crossover method of long term core cooling

following a LOCA was not consistent with the topical reports

mentioned above.

Prior the initial licensing of Crystal River, a number of issues

arose regarding the ECCS performance evaluation. Earlier versions

- of Topical Report BAW 10103A. BAW 10104 and BAW-10064 "Multinode

Analysis of Core flood Line Break for B&W 2568 MWL Internal Vent

Valve Plants." made u) a part of the a)plicant's method of showing

compliance with 10 CF1 50.46 and 10 CFR 50.- Appendix K. In NRC

i

l

-

, _ _ ,, _ _ _ . - - _ , --

. -. -,_.,..-,...._,_..-..,- _ .- - _ . , . . _ _ _ -

,

-

i .

.

'

29

SER supplement 3, 12/30/76. the NRC concluded that the method used

by B&W in calculating the fuel cladding temperature during the

blowdown Dhase did not conform to the requirements of 10 CFR 50,

i' Appendix K. This directly impacted BAW 10064. which was a <

com) uter analysis that essentially terminated once ECCS flow (via 7

an eiP! pump and the intact core flood tank) exceeded the boil off  :

rate. Therefore, the analysis terminated within a half hour of  !

accident initiation. Subsequently. B&W properly performed the

analysis and submitted it as A

which was accepted by the NRC.ppendix 3AW 10103. C Rev. to 3.The nev' analysis als

'

once the ECCS exceeds the boil off rate within 20 minutes of

, accident initiation. Therefore, the NRC accepted Topical Report '

BAW 10103A. Rev. 3. *ECCS Analysis of B&W 177 Fuel A:;sembly

! Lowered loop NSSS." and Topical Report BAW 10104. Rev. 3. *ECCS

Analysis Of B&W's 177 FA Lowered loo) NSS." as the method and

<

applications for complying with 10 C:R 50.46.

Never was the applicability of the long term core cooling methods

described in the original versions of BAW-10103 and 10104 an

issue. The original SER of 7/5/74, stated in part "The low

pressure injection system lines are equip)ed with a crossover line

inside the auxiliary building so that eac1 LPIS pump is connected

to both core flooding tank (CFT) nozzles on the reactor vessel.

Manually operated valves in the crossover line will be arranged so

in the unlikely event of the simultaneous occurrence of a break at

,

the worst location in a CFT line and the loss of one LPIS. half of

! the flow of the other LPIS pump will reach the reactor pressure

'

vessel to insure adequate long term t. ore cooling."

On 1/2/98 the licensee's onsite review committee, the Plant Review

Committee, approved a safety evaluation completed the day before '

authorizing a change to the Updated Safety Analysis Report (USAR).

The USAR charge was FSAR6 R24-33 and concluded that no unreviewed

safety question existed. The USAR change revised a portion of

section 6.1.2.1.2. Low Pressure injection, and inserted a new

,

section. 6.1.3.1.3. Core Flood Tank (CFT) Line Break SBLOCA. The

'

section 6.1.2.1.2 revision did not address the use of the LPI

crossover if a core flood tank line failed and/or one LPI pump

failed due to plant s)ecific design limitations. The new section ,

'

6.1.3.1.3 discussed t1e CFf line break consistent with BAW 10103.

Rev. 3. Appendix C. This USAR change appeared 'o be in response 1

to the NRC's E0P inspection team identifying ti . previous

.

procedure changes el minated using the crossover line for long

term core cooling.  !

Pending further NRC review of the safety evaluation surrounding

this change, this matter is unresolved. URI 50 302/97 12-07.

" Current LPI Crosstic Safety Evaluation."

'

,

J

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c. fanclusions

During at least two time periods after the operating license was >

granted there was no procedural gu: ' ..;e to use the LPI crossover line <

with flow split between the two LPI sines (the crossover line method of

,

long term core cooling, chapter 10 option #1 in BAW 10103A and BAW

I 10104) to mitigate the consequences of a LOCA. The first time period

was from 7/79 until 6/89. The second tima period was 5/2/96 until the

"

i present. A recent change to t'1e USAR regbrding the LPI crossover line

! method of long term core cooling was inconsistent with applicable i

! topical rC ,ts. The NRC will further review these unresolved matters,

i El.3 ECCS Piaavbeck Mode of 00eration

'

a. Insoection Stone (42001)

Due to the licensee directing unrestricted HPI operation in piggyback,

in December and January the team reviewed the technical requirements

'

contained in the original purchase order for the HUPs (HPI) and compared

these requirements to how the E0Ps directed use of the pumps.

-

b. Observations and Findinas

The team determined that the original purchase order only specified one

! day of post accident operation. Whereas, post accident LOCA operation

of the MUPs while taking suction from the discharge of the LPI pumps

which in turn take suction from the reactor building sump, known as the

piggyback mode, could be necessary for 30 days. E0P 08 directe

1 use of

1 the piogyback mode for an unspecified period of time. Operatim in this

4 piggyback mode was option #3 of the long term core coolina options

stated in BAW 10103A and 10104 (see El.2 above). Chapter 10 of BAW

4

10103A and BAW 10104 stated in part. "The durat!cn of long-term cooling

is the per.iod between the onset of long term cooling and the end of core

cooling requirements, . . , The exact duration of long-term cooling will

'

vary. . .. A realistic assessment of the duration for the worst case is

approximately one month,"

Not purchasing the pumps for the appr,,'opriate post-accident time duration

"

is violation. VIO 50/302 97 12 08. Incorrect HPl Pump Purchase Order,"

, of 10 CFR 50, Appendix B. Criterion IV, Procurement Document Control.

This criterion requires that measures be established to assure

applicable regulatory requirement and design bases are suitably included

in the documents for procurement of. equipment.

,

C, ConcluligD}

The MUPs used for ECCS high pressure injection were not purchased to

specifications commensurate to the duty to De incurred during a

y postulated post accident-LOCA_, This was a violation.

,

W

.

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_

31

El.4 (EDG) Start Loaic

a. Insoection Scoce (42001)

The team reviewed the EDG logic and control arrangement interface with

the air start motor controls to ensure that the design was consistent

with regulatory requirer.ats. The review was prompted by a discussion

with a licensed operatoi shen it was inferred that the EDG start

circuitry could allow the continued application of starting air to an

EDG until depletion of the staring air.

b. Observations and Findinas

The team determined that the air start circuitry did not allow such a

set of conditions. and was designed to 3revent such an occurrence

automatically. Operator training was peing provided to prevent

restarting a tripped EDG until after an emerger y shutdown relay was

allowed to " time out" for at least 60 seconds r.ior to attempting a

restart. The team reviewed training records and intervicwed operators

to assure operators were aware of this requirement.

3

c. Conclusions

) The EDG air ctart circuitry was properly designed to prevent continued

application of starting air to an EDG until depletion of the staring

air, and appropriate operator training had been provided on how to

respond to a tripped EDG.

E1.5 Position of LPI iniection Valves. DHV-5 and DHV 6

a. Insoection Scooe (42001)

Due to discussions with the licensee as to why the LPI crossover lines

were not being used in the E0Ps. the team reviewed the circumstances

surrounding why the LPI injection valves. DHV-5 and 6 (originally

. designated DH-V4A and DH-V4B). were normally closed.

I

I b. Observations and Findinas

The team determined that as part of the licensing review for Crystal

River, the NRC issued a 12/8/75 request for information regarding the

ECCS analysis. One question s3ecifically addressed the normal position

of valves DH-V4A and DH-V4B. t7e LPI injection valves. Question 2c

stated "FSAR Figure 9-6 shows LPI valves DH-V4A and DH-V4B to be

normally closed. To allow low pressure injection subsequent to a CFT

line break and a single active component failure. '.hese valves must be

E

recuired by Station Technical S]ecifications to be. open, power removed,

anc breakers locked open. . T1ese changes provide assurence that

abundant core cooling is available for a CFT line break and further

minimize the potential for a LOCA outside containment."

E

_ _ _ _ _ - _ _ _ _ _ . _ _ -

32

The license applicant responded to the question in a letter dated

1/13/76 which stated in part "Volves DH-V4A and DH-V4B will be placed in

the normally open position. FSAR Figure 9-6 will be revised in

Amendment No. 48 to indicate this revision to the Decay Heat Removal

System. How?ver, as previously committed to and accepted by the NRC and

ACRS. power mst be oailable to these valves as they are required to be

throttled ir. cie- to split the decay heat (LPI) flow. The Low Pressure

Injection Systel is provided with a crossover line to permit one LPI

string flow of 3000 gpm to be split equally, thus providing a minimum of

1500 gpm flow to both core flooding injection nozzles simultaneously

should a core flooding line or one LPI pump fail. The LPI crossover

injection mode of operation is accomplished by opening the crossover

line. 3rovided with a two-way flow element, and remotely adjusting the

flow t1 rough the crossover line to 1500 by throttling the two el.ctric

motor operated valves DH-V4A and DH-V4B. Acceptance of this mode of

operation by the NRC is further exemalified in the staff's SER on page

6-13 and 6-14. Section 6.3.2 System Jesign. Therefore, valves DH-V M

~

and DH-V4B will be placed in the normally open position.

On 3/15/76 the applicant submitted FSAR Amendment 48 without indicating

the injection valves as normally open or changing operating procedu es.

Subsequently, an operating license was granted on 12/3/76 which

considered the information contained in amendments 1 through 49 as a

description of the facility. At no time since license approval had the

-

LPI injection valves been "normally open." nor has the FSAR ever shown

them as open. Pending further NRC review. the matter is unresolved. URI

50-302/97-12-09. " Failure to Normally Position LPI Injection Valves

Open."

c. Conclusions

The LPI injection valves are maintained ar mally closed. consitent with

the FSAR. However, in a letter dated 1/lm .. the liccnsee committed to

maintain the valves normally open and update the FSAR accordingly.

Those actions were never accomplisheu. The NRC will further review this

unresolved matter.

E8 Miscellaneous Engineering Issues

E8.1 As-Built Plant Discrepancy

During a simulator scenario observed by the team, an operator determined

that a control room HVAC fan control switch operated differently when

changing fan speed than 'n the actual facility. Subsequent follow up

identified that the switch in the simulator was consistent with the

approved schematic drawina and the switch in the facility was not

consistent with the drawing. 10 CFR 50. Appendix B. Criterion V.

Instructions. Procedures and Drawings, requires drawings be appropriate

to the circumstance. Having the drawing and switch reflect different

wiring configurations was a violation of that requirement. The licensee

initiateo PC3-C93-0161 and established corrective actions. The team

_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _

____ _ _ _

33

reviewed the licensee's planned corrective actions for the PC and

determined that the root cause analysis was appropriate and the

corrective actions specified in the PC would adequately correct the

deficiency. The mis-wiring did not affect the ESF feature of the fan.

This licensce identified and corrected violation is being treated as a

Non Cited Violation. NCV 50 302/97-12-10. ' Wiring Error. consistent

with Section VII.B.1 of the NRC Enforcement Policy.

E8.2 (Closed) VIO 50-302/97-01-07: Instrument i. cop Uncertainty Set point

Calculation Assumptions Not Translated into Procedures

As discussed in section E.1.1.b.2 abwe. the licensee failed to identify

and correct calculations supporting 20P related set points as part of

the corrective actions for Violation 50-302/97-01-07. Consequently,

these cciculations contained the same type of errors. Violation 50-

302/97-01-07 is considered closed and the balance of the corrective

actions associated with this violation will be tracked as part of the

corrective actions for the violation identified in section E.1.1.b.2.

IV. MANAGEMENT HEETINGS

, X1 Exit Meeting Summary

The team leader discussed the progress of the inspection with licensee

representatives on a daily basis and presented the inspection results to

members of licensee management and staff listed below at an interim exit

on December 12. 1997 and at the conclusion of the inspection on January

9. 1998. The licensee acknowledged the findings presented.

At the final exit the team leader asked the licensee whether any

materials examined during the inspection should be considered

proprietary. No proprietary information was identified.

--

34

PARTIAL LIST OF PERSONS CONTACTED

LICENSEE:

• J. Baumstark. Director. Quality Programs

• 1. G. Becker, E0P Project

• M Collins. Operations Engineer

1. J. Cowan, Vice-President. Nuclear Production

• R. Davis, Assistant Plant Director. Operations

• 1. R. Grazio. Director, Regulatory Affairs

• S. Greenlee. Manager, Nuclear Operations Engineering

• 1. B. Gutherman, E0P Project

• 1. J. Holden, Site Director

• 1. M. Kelly, E0P Project

• D. Kunsemiller, Manager, Nuclear Licensing

• 1. J. Lind, Manager Nuclear Operator Training

• 1. C Pardee, Director, Plant Operations

• W, Pike, Manager, Nuclear Regulatory Compliance

• 1. D. Porter E0P Project

• 1. K. Rass. E0P Project

• M. Rencheck Director Engineering

• 1. T. Taylor. Director, Nuclear Training

• G, Wadkins, Licensing Engineer

• 1. R.Widell,E0PProject

NRC:

• S. Cahill, Senior Resident Inspector

• 1. G. Galletti. NRR

• 1. P. Harmon, RII

• 1. L. Mellen, RII

• 1. J. Bartley, RII

1. L. Reyes, RII. Regional Administrator

1. J. Jaudon, RII. Division Director. Division of Reactor Safety

• 1. W. Rogers. RII

1. personnel present at the 12/12/96 interim exit

• personnel present at the 1/9/98 exit

LIST OF INSPECTION PROCEDURES USED

IP 42001 Emergency Operating Procedures

LIST OF ITEMS OPENED

50-302/97-12-01 VIO InadequM( Implementation 01 TMI Action Item E0P

Order.(Sections 03.1.b.3.(a) 03.1.b.4. 03.1.b.6.

03.2.b.2. 03.2.b.3(b). 03.2.b.4)

50-302/97-12-02 VIO Inadequate Corrective Actions (Sections

03.2.b.3(a). 03.2.b.3(b). E1.1.b.2)

- _ _ _ _ _ _ . _ _ _ _ _ _ _ _ _ . _ _ _ _ _ _ _ . . _ _ _ _ _ ._ _ . - . _

)

'

35

50-302/97-12-03 IFI Enclosure 17/18 Interaction. (Section 03.2.b.5)

'

50-302/97-12-04 NCV Inadecuate External Leakage Surveillance

,

Procecure. (Section M3.2)

50-302/97-12-05 VIO Poor Calculations. (Section E1.1.b.3 and

E1.1.b.4)

50-302/97-12-06 URI Previous LPI Crosstie Safety Evaluations.

(Section E1.2.b.1)

50-302/97-12-07 URI Current LPI Crosstie Safety Evaluation. (Section

E1.2.b.2)

50-302/97-12-08 VIO Incorrect HPI Pump Purchase Order. (Section

El.3)

,

50-302/97-12-09 URI failure to Normally Position LPI Injection

Valves Open. (Section E1.5)

50 302/97-12-10 NCV Wiring Error. (Section E8.1)

T

LIST OF ITEMS CLOSED

50-302/96-06-10 URI Justification for Removal of Thermo-Lag

Protection from Source Range Instrumentation.

>

(Section 08.2)

,

50-302/97-01-07 VIO Instrument Loop Uncertainty Set point

Calculation Assumptions Not Translated into

Procedures. (Section E8.2)

,

._ ., - e . - - - . . .- , . , - - -

36

' Appendix A

LIST OF DOCUMENTS REVIEWED

LIST OF INDUSTRY INFORMATION DOCUMENTS REVIEWED

ISA-S67.04. Part I. " Set points for Nuclear Safety-Related Instrumentation."

dated September 1994

ISA RP67.04. Part II. " Methodologies for the Determination of Set points for

Nuclear Safety-Related Instrumentation." dated 1994

NRC Regulatory Guide 1.105. " Instrument Set points for Safety-Related

Systems." Revision 2. dated February 1984

__ . LIST OF PROCEDURES REVIEWED

AI-400F. New Procedures and Procedure Change Processes for E0Ps. APs. and

Sup)orting Documents. Rev. 4

AI-402A, E0P Writer's Guide for Abnormal and Emergency Operating Procedures,

Rev. 8

AI-402C. AP and E0P Verification and Validation Plan. Rev. 04

Al-505 Conduct of Operations During Abnormal and Emergency Events. Rev. 02

AP-380 Engineered Safeguards Actuation. Rev. 20 & 22

AP-510. Rapid Power Reduction. Rev. 01. Rev. 01 Draft

AP-581. Loss of NNI-X. Rev. 07 Draft

AP-582. Loss of NNI-Y. Rev. 06 Draft

AP-770. Emergency Diesel Generator Actuation. Rev. 23. Rev. 23 Draft J.

Rev. 23 Draft 0

CP-149. Primary Coolant Sources Outside Containment Program Rev. 02

OP-404. Decay Heat Removal. Rev. 6, 8. 12, 22. 24, 26, 44, 48. 51. 56, 63,

66. 67. 68. 73. 74. 75. 78. 87. 99. 101, 102

OP-417. Containment Operating Procedure. Rev. 73

SP-306. Weekly Surveillance Log. Rev. 17

E0P-01, E0P Entry Conditions. Rev. 02. Draft Rev. 02 Draft

E0P-02. Vital System Status Verification. Rev. 04. Draft L

E0P 03. Inadequate Subcooling Margin. Rev. 05. Rev. 05 Draft P

E0P-04. Inadequate Heat Transfer. Rev. 04. Rev. 04 Draft T

E0P-05. Excessiver Heat Transfer Rev. 03. Rev. 03 Draft T

E0P-06. Steam Generator Tube Rupture. Rev. 05. Rev. 05 Draft F. Rev. 05

Draft H. Rev. 06

E0P-07. Inadequate Core Cooling. Rev. 04. Rev. 04 Draft J

E0P-08. LOCA Cooldown. Rev. 05. Rev. 05 Draft N

E0P-10. Post-Trip Stabilization. Rev. 03. Rev. 03 Draft M

E0P-12. Station Blackout. Rev. 02. Rev. 02 Draft J

E0P-13. E0P Rules. Rev. 03. Rev. 03. Draft J

E0P-14. Enclosure 1. SP0 Post-Trip Actions Rev. 02. Rev. 02 Draft T

E0P-14. Enclosure 2. PPO Post Event Actions. Rev. 02 Rev. 02 Draft T

E0P-14. Enclosure 5. MSIV Recovery. Rev. 02 Draft S. Rev. 02 Draft T

._ _ _ _ __

37

E0P-14. Enclosure 6, OTSG Blowdown Lineup, Rev. 02, Rev. 02 Draft R.

Rev. 02 Draft T

E0P 14. Enclosure 7. EFP 2 Management. Rev 02. Rev. 02 Draft S. Rev. 02

Draft T

E0P 14. Enclosure 8. MFW Restoration. Rev. 02. Rev. 02 Draft S. Rev. 02

Draft T

E0P-14. Enclosure 10. Alternate OTSG Feedwater Supply, Rev. 02, Rev, 02

Draft N Rev. 02 Draft T

E0P-14. Enclosure 11. EDG Load Management, Rev. 02 Draft R. Rev. 02

Draft T

E0P-14. Enclosure 13. High Pressure Aux Spray Lineup Rev. 02 Draft R. Rev. 02

Draft T .

E0P-14. Enclosure 14, Station Blackout Main Generator Purging. Rev. 02 Draft T

E0P-14. Enclosure 15. E0P Temperature Log, Rev. 02. Rev. 02 Draft 0. Rev. 02

Draft T

E0P-14. Enclosure 17. Control Complex Emergency ventilation, Rev. 02.

Rev. 02 Draft R. Rev, 02 Draft T

E0P 14. Enclosure 18. Control Complex Chiller Startup Rev. 02. Rev. 02 Draft

S. Rev. 02 Draft T

E0P-14. Enclosure 20. Boron Precipitation Control. Rev. 02 Draft T

E0P-14. Enclosure 21 RB Hydrogen Management. Rev. 02. Rev. 02 Draft P. Rev.

02 Draft T

E0P-14. Enclosure 24. Tables, Rev. 02 Draft L

EP-106, Loss of RC/RC Pressure, Rev. 8, 13, 16. 17. 20

LIST OF CALCULATIONS REVIEWD

M96-0035. Rev. O. Criteria for Termination of RB Saray

M95-0016. Rev. 2. BWST Swapover and Minimum Allowa)le Level

M93-0015. Rev. 1. Condensate Storage Tank Volume

191-0026, Rev. 2. CR-3 CFT Press /LPI Flow Evaluation

M95-0009. Rev,1. CR-3 Sump Solution pH Calculation -Report

188-0027. Rev. O. Responses to NRC Ouestions Regarding Tripping RC Pumps on

Loss of Subcooling Margin

191-0002. Rev. O. MU Tank Level loop Accuracy

M93-0056. Rev. O. LOCA RB Spray Sensitivity Study

184-0006. Rev. O. Analytical Justification for the Treatment of RCP During

Accident Conditions

190-0022 Rev. O,

191-0028. Rev. 1. FWP-7 Flow Indication

M93-0006. Rev.,O. RB Purge Dose Evaluation

E90-0023. Rev. 1. Evaluation for Containment Spray between pH 4.0 and 12.5

_ - - - - - .. . . . . - _ -

38

>

Appendix B

List of Acronyms Used

.

AB Auxiliary Building

ACRS Atomic Concerns and Reactor Safety

ADV Atmospheric Dump Valve

4 AFW Auxiliary Feedwater

Al Administrative Instruction

ANSI American National Standards Institute

AP Abnormal Procedures

ATWS Anticipated Transient Without Scram

CFR Code of Federal Regulations

CFT Core Flood Tank

CHV Chilled Water Valve

CP Compliance Procedure

CR Crystal River

CR0 Control Rod Drive

CXV Cross-tie Valve

DH Decay Heat

DHV Decay Heat Valve

ECC Emergency Core Cooling

ECCS Emergency Core Cooling System

EDG Emergency Diesel Generator

EFIC Emergency Feedwater Isolatio,' Logic

EFW Emergency Feedwater

EFWT Emergency Feedwater Tank

E0P Emergency Operating Procedure

ES Engineered Safeguards

ESF Engineered Safeguards Features

FPC Florida Power Corporation

FSAR Final Safety Analysis Report

FWP- Feedwater Pump

HPI High Pressure Injection

HVAC Heating, Ventilating and Air-conditioning

IFI Inspector Followup Item

ISA Instrument. Society of America

LBLOCA large Break Loss of Coolant Accident

LOCA Loss of Coolant Accident

LPI Low Prersure Injection

_

LPIS Low Pressure Injection System

LRV Leak Rate Valve

MCC _ Motor Control Center

. MFW' Main Feedwater

MOV Motor Operated Valve

MSIV Main Steam Isolation Valve

MSSV Main Steam Safety Valves

MSV Main Steam Valve

MVP Make-up Pump

MWt Megawatt Thermal

F

39

NRC Nuclear Regulatory Commission

NRR Nuclear Reactor Re ulation

NSS Nuclear Steam Supp y

NSSS Nuclear Steam Supp y System

OP Ooerating Procedure

OTSG Once Through Steam Generator

PGP Procedures Generation Package

PPO Primary Plant-0perator

PRC Plant Review Committee

RB Reactor Building

RC Reactor Coolant

RCP Reactor Coolant Pump

RCS Reactor Coolant System

SBLOCA Small Break Loss of Coolant Accident

SB0 Station Blackout

SER Safety Evaluation Report

SGTR Steal Generator Tube Rupture

SP Surveillance Procedure

SP0 Secondary Plant Operator

SR0 Senior Reactor Operator

SWV Service Water Valve

TBD Technical Bases Document

TMI Three Mile Island

TS Technical Specification

TSC Technical Support Center

URI Unresolved Item

USQ Unreviewed Safety Question

UFSAR Updated Final Safety Analysis Report

VAC Volts - Alternating Current

VIO Violation

VSSV Vital System Status Verification