ML20138A369

Insp Rept 50-416/86-02 on 860118-0224.Violations Noted: Three Examples of Failure to Perform Safety Evaluations Per 10CFR50.59

ML20138A369
Person / Time
Site:	Grand Gulf
Issue date:	03/05/1986
From:	Butcher R, Caldwell J, Dance H NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:
Shared Package
ML20138A319	List: ML20138A313 ML20138A334 ML20138A369
References
50-416-86-02, 50-416-86-2, GL-81-06, GL-81-6, NUDOCS 8603140209
Download: ML20138A369 (12)

See also: IR 05000416/1986002

Text

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p afr UNITE 3 STATES

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/j o,' NUCLEAR REGULATORY COMMISSION

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REGION 88

101 MARIETTA STREET,N.W.

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• ATL ANTA. GEORGI A 30323

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Report No.: 50-416/86-02

Licensee: Mississippi Power And Light Company

Jackson, MS 39205

Docket no.: 50-416 License No.: NPF-29

Facility Name: Grand Gulf 1

Inspection Conducted: January 18, 1986 to February 24, 1986

Inspectors: ( A ,_. o

R.' C. Butch 6r, Seni'od Resident Inspector

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' Datt Signed

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hC /s~:o f/]v

. Caldwell, Rp[ dent Inspector

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Approved by: a

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H. C. Dance, Citief, Project Section 2B CatefSigned

Division-of Reactor Projects

SUMMARY

Scope: This routine inspection entailed 213 resident inspector-hours at the site

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in the areas of Operational Safety Verification, Maintenance Observation,

Surveillance Observation, ESF. System Walkdown, ' Reportable Occurrences, Operating

Reactor Events, Inspector Followup and Unresolved Items, Information Meetings

with Local Officials and SALP Meetings.

Results: Violation - Three examples of failure to perform safety evaluations per

10 CFR 50.59.

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REPORT DETAILS

1. Licensee Employees Contacted

+#J. E. Cross, Site Director

+#T. H. Cloninger, Vice President, Nuclear Engineering & Support

+#0. D. Kingsley, Vice President, Nuclear Operations

1. L. F. Dale, Director, Nuclear Licensing & Safety

+#J. G. Cesare, Manager, Nuclear Licensing

+#S. M. Feith, Director, QA

1. M. A. Dietrich, Supervisor, QA

+#F. W. Titus, Director, Nuclear Plant Engineering

• C. R. Hutchinson, General Manager

R. F. Rogers, Technical Assistant

• J. D. Bailey, Compliance Coordinator

M. J. Wright, Manager, Plant Operations

L. F. Daughtery, Compliance Superintendent

D. G. Cupstid, Start-up Supervisor

R. H. McAnuity, Electrical Superintendent

R. V. Moomaw, Manager, Plant Maintenance

W. P. Harris, Compliance Coordinator

J. L. Robertson, Operations Superintendent

L. G. Temple, I & C Superintendent

J. H. Mueller, Mechanical Superintendent

1. S. Bennett, Nuclear Licensing Supervisor

+S. Hobbs,. Manager, Nuclear Safety

Other licensee employees contacted included technicians, operators, security

force members, and office personnel.

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NRC Personnel

+W. R. Butler, Director, BWR Directorate, NRR

+R. D. Walker, Director, Division of Reactor Projects, RII

+A. F. Gibson, Director, Division of Reactor Safety, RII

+#L. L. Kintner, Licensing Project Manager, NRR

+#V. W. Panciera, Chief Reactor Projects Branch 2, RII

+#H. C. Dance, Chief, Project Section 28, RII

+G. A. Belisle, Arting Section Chief, Quality Assurance Programs Section, RII

+J. H. Moorman, Inspector, QA, RII

• Attended exit interview

1. Attended meeting of February 7,1986

+ Attended SALP meeting of February 20, 1986

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2. Exit Interview

The inspection scope and findings were summarized on February 24, 1986, with

those persons indicated in paragraph 1 above. The licensee did not identify

as proprietary any of the materials provided to or reviewed by the

inspectors during this inspection. The licensee had no comment on the

following inspection findings:

a. 416/86-02-01, Violation. Three examples for failure to perform safety

evaluations per 10 CFR 50.59. (Paragraph 3.a)

b. 416/86-02-02, Inspector Followup Item. Replacement of HPCS generator

during first refueling outage. (Paragraph 9.a)

c. 416/86-02-03, Inspector Followup Item. Restrict plant operation to

require at least 19 SRVs be operable. (Paragraph 9.b)

d. 416/86-02-04, Inspector Followup Item. Need for essential or emergency

lighting in the diesel generator building and/or the upper control

panel room. (Paragraph 7)

3. Licensee Action on Previous Enforcement Matters (92702)

a. (0 pen) Violation 416/84-16-01. By letter dated December 1,1985 the

licensee submitted the initial Final Safety Analysis Report (FSAR)

update for the Grand Gulf Nuclear Station. The letter addressed three

unique items concerning Fire Hazard Analysis, Environmental Equipment

Qualification and High Groundwater Level. The letter also stated that

the updated FSAR was prepared considering the additional guidance

provided by Generic Letter 81-06, Periodic Updating of Final Safety

Analysis Reports.

While reviewing the updated FSAR (UFSAR) for corrective action

implementation for a previous violation (416/84-16-01) it was found

that the UFSAR did not incorporate the action committed in the

licensee's response. The licensee removed a commitment concerning

protective tagging responsibility from the UFSAR. A cursory review of

the USFAR versus the original FSAR (OFSAR) revealed several

discrepancies. Some examples of the differences noted were as follows:

(1) 0FSAR, paragraph 13.1.2.2.3.1, Shift Superintendent, states "The

shift superintendent is responsible for all protective tagging at

GGNS."

UFSAR, paragraph 13.1.2.2.16.1, Shift Superintendent, does not

address protective tagging. Paragraph 18.1.13, Guidance on

Procedures for Verifying Correct Performance of Operating

Activities (1.C.6), does not address who is responsible for

protective tagging.

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This change removes a commitment that the shift superintendent is

4. responsible for all _ protective tagging at GGNS and does not

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maintain the same' level of detail as the OFSAR. A safety analysis '

required by 10 CFR 50.59 was not performed.

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(2). 0FSAR, paragraph 6.3.2.2.1, HPCS System, states " Vortex formation

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in the condensate storage tank is precluded by providing

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approximately 2 1/2 feet submergence for the suction piping

i entrance at. the time of switchover and by the use of a vortex

>L breaker." -

UFSAR, paragraph 6.3.2.2.1, HPCS System, states " Vortex formation

in the condensate storage tank is precluded by providing

approximately 3/4 . foot submergence over the suct un piping

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entrance at the time of switchover and by the use of a vortex

breaker."

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l This change reduces the submergence of the suction pipe entrance

, for the HPCS pump. The pipe is 20 inch diameter and HPCS pump run

out flow is 9100 gpm. This change to the facility (as reviewed by

the NRC) did not receive a 10 CFR 50.59 review and an evaluation

! of its safety impact was not made until January 22, 1986 when

, questioned by the inspectors.

I (3) 0FSAR, paragraph 3.8.1.2.2.1, Design Codes, subparagraph c lists  !

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the applicable code for welding in ' building construction, AWS

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D1.1-72 with noted exceptions.

UFSAR, paragraph 3.8.1.2.2.1, Design Codes, subparagraph c lists

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numerous additional exceptions.

This change modifies the design codes commitment and was made

without a 10 CFR 50.59 safety analysis.

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10 CFR 50.71 (e), periodic updating of Final Safety Analysis Reports,

_ became effective July 22,- 1980 and Generic Letter 81-06 was issued

) February 26, 1981 to provide guidance regarding the FSARs legal status,

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format and content. The Federal Register was incorporated as part of

- the Generic . Letter and requires that the submittal shall . include a

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certificatice by a duly authorized officer of the licensee that either ,

the information accurately presents changes made since the previous j

submittal, necessary to reflect information and analysis submitted to

the Commission or prepared pursuant to Commission requirement, or that  !

, no such changes were made; and an identification of changes made under i

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the provisions of 10 CFR 50.59 but not previously submitted to the

Commission.' 10 CFR 50.59 states that the licensee may make changes in

the facility as described in the safety analysis report, make changes

i in the ' procedures as described in the safety analysis report and i

j conduct tests or. experiments not described in. the safety analysis

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report without prior Commission approval unless the prope sed change,

test 'or experiment involves a change in the technical specifications

incorporated in the license or an unreviewed safety question. Also the

licensee is required to maintain records which include a written safety

evaluation which provides the basis for the determination that no

unreviewed safety question exists.

The inspectors review of the changes noted above indicated that the

licensee failed to conduct 10 CFR 50.59 safety evaluations as required.

The inspectors only reviewed a few selected examples of the changes in

the UFSAR but the licensee has agreed that there were other changes

that fell in this same category. Failure to perform a 10 CFR 50.59

safety evaluation for the above three examples is a violation

(416/86-02-01).

Discussions with NRR indicated that the change in the UFSAR as

described in item (2) above was questionable as to being acceptable for

HPCS pump operability at the time of switchover from the condensate

storage tank to the suppression pool. A telecon was held on

January 29, 1986 between Mr. L. Kintner & Mr. A. Serkiz of NRR, the

Senior Resident Inspector and Mr. G. Cessar & Mr. F. Titus of MP&L to

discuss the required submergence depth of the HPCS pump suction line.

The licensee was requested to submit their evaluations verifying that

7 1/2 inches submergence at the time of switchover was adequate.

Pending the resolution of the acceptability of the 7 1/2 inches

submergence, the plant issued night orders to the operators directing

them, in the case of an event causing HPCS and RCIC initiation, to

manually switch the HPCS and/or RCIC suction from the Condensate

Storage Tank (CST) to the suppression pool at or above 6 feet level in

the condensate storage tank. This then required the minimum CST level

to be administrative 1y controlled at 24 feet indicated level. The

licensee subsequently subditted a -letter to the NRC dated February 15,

1986, addressing this issue.

In summary, the following problems appear to indicate a lack of

management attention and control when updating the FSAR.

(1) Contrary to the guidance given in Generic Letter 81-06, the level

of detail of the original FSAR was not always maintained in the

updated'FSAR.

(2) Although 10 CFR 50.71(e) allows the UFSAR to include all charges

made based on safety evaluations performed by the licensee,

apparently many changes did not have a safety evaluation performed

as required by 10 CFR 50.59.

(3) Changes in the UFSAR to reflect the as built configuration of the

plant were not submitted to or approved by the NRC nor were 10 CFR

50.59 safety evaluations performed. l

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A meeting was held at the Grand Gulf facility on February 7,1986 to

discuss the FSAR update problem. Attendees are noted in paragraph 1

above. MP&L has proposed a review program that will ensure the

accuracy and completeness of the UFSAR. This review program will

consist of the following.

(1) Screening of previous UFSAR changes to ensure commitments have not

been eliminated and/or '10 CFR 50.59 safety evaluations have been

performed. The following items may be eliminated from the

screening program: changes described in a Safety Evaluation

Report; changes properly reviewed under 10 CFR 50.59 provisions;

changes documented in correspondence to and from the NRC prior to

licensing; changes documented by closure correspondence post

operating license, and editorial changes.

(2) The incorporation of questions and responses will be reviewed for

deleted commitments.

The licensee also stated that they will prioritize the 10 CFR 50.59

reviews involving plant changes, changes in instrumentation setpoints,

etc; will notify the NRC by letter of any physical differences between

the actual plant configuration and that described in the original FSAR;

incorporate any changes found into the next UFSAR submitted which is

due December, 1986, and that they consider commitments in the FSAR

require NRC concurrence to delete.

b. (Closed) Violation 416/85-27-01. The licensee modified administrative

procedure 01-S-07-3, Calibration & Control of Measuring & Test

Equipment, requiring evaluations be completed within 30 days unless

retesting or recalibration of equipment necessary to evaluate the

nonconformance cannot be performed due to plant conditions. In this

case a material nonconformance report must be generated.

4. Operational Safety Verification (71707)

The inspectors kept themselves informed on a daily basis of the overall

plant status and any significant safety matters related to plant operations.

Daily discussions were held with plant management and various members of the

plant operating staff.

The inspectors made frequent visits to the control room such that it was

visited at least daily when an inspector was on site. Observations included

instrument readings, setpoints and recordings status of operating systems,

tags and clearances on equipment controls t.nd switches, annunciator alarms,

adherence to limiting conditions for operation, temporary alterations in

effect, daily journals and data sheet entries, control room manning, and

access controls.

This inspection activity included numerous informal discussions with

operators and their supervisors.

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Weekly, when onsite, selected ESF systems were confirmed operable. The

l confirmation is made by verifying the following: Accessible valve flow path

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alignment, power supply breaker and fuse status, major component leakage,

lubrication, cooling and general condition, and instrumentation.

l General plant tours were conducted on at least a biweekly basis. Portions

of the control building, turbine building, auxiliary building and outside

l areas were visited.

I Observations included safety related tagout verifications; shift turnover,

j sampling program, housekeeping and general plant conditions, fire protection

i equipment, control of activities in progress, radiation protection controls,

l physical security, problem identification systems, and containment

I isolation.

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The following comments were noted:

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l a. In inspection report 85-46 violation 416/85-46-01 was given for failure

l to follow Integrated Operating Instruction (I0I) 03-1-01-1, Cold

l Shutdown to Generator Carrying Minimum Load. Subsequently, on

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February 10, 1986 the Manager, Plant Operations informed the Senior

l Resident Inspector that contrary to previous discussions, control rods

were pulled while shutdown cooling was in effect. The following

l sequence of events occurred on December 22, 1985:

Recirculation

l Loop

l Time Event Temperature

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11:30 a.m. Placed mode switch in startup 176 F

11:31 a.m. Commenced rod pulls 181 F

l 12:21 p.m. Stopped rod pulls at step 14 188 F

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12:25 p.m. Shutdown cooling placed in service 184 F

12:36 p.m. Recommenced rod pulls 176 F

1 1:34 p.m. Stopped rod pulls at step 32 165 F

i 5:45 p.m. Minimum temperature reached 154 F

! 8:55 p.m. Shutdown cooling secured 176 F

f 9:04 p.m. Recommenced rod pulls 179 F

10:35 p.m. Reactor critical at step 41 196 F

Note - the noted loop temperatures are approximate since temperature

readings did not correspond to event times.

l The licensee stated that the last criticality occurred on December 7,

1985 at step 40 and 167 F. It appears that although the Manager, Plant

Operations and the Shift Superintendent discussed what evolution was to

occur to put shutdown cooling in service, thero was a misunderstanding.

This failure of communications is critical since no detailed procedure

existed to control this evolution. The inspector has requested the

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licensee to provide corrective action for preventing a recurrence of

this event. This will be an Inspector Followup Item and will be

inspected as part of IFI 416/85-46-03.

b. IE Information Notice 85-94, Potential for loss of Minimum Flow Path

Leading to ECCS Pump Damage During a LOCA, was previously discussed in

inspection report 416/85-46. Additional information has been brought

to the inspectors attention concerning the ability to close the minimum

flow . isolation valve during a condition where the pump initiation

signal had been received but the pump doesn't start. The ability to

close the valve during a no flow condition such as the pump not

operating may be necessary to establish containment isolation. For the

case of Low Pressure Core Spray (LPCS) and Low Pressure Coolant

Injection (LPCI) syrtems, the minimum flow isolation valves are

normally open and automatic operation of these valves during conditions

of varying flows can only occur with the pump breaker closed. However,

with the pump breaker closed the minimum flow isolation valves can only

be closed and remain closed by using the hand switch or manual

handwheel to close the valves and then opening their control power

breakers. Normally if the pump does not start the breaker will not

remain closed and with the pump breaker open the associated minimum

flow isolation can be closed with the hand switch in the control room

and will remain closed. For the High Pressure Core Spray (HPCS)

system, the minimum flow isolation valve is normally closed and will

not open unless the pump is operating with a discharge pressure greater

than 100 psig and flow less than approximately 10%.

5. Maintenance Observation (62703)

During the report period, the inspector observed selected maintenance

activities: The observations included a review of the work documents for

adequacy, adherence to procedure, proper tagouts, adherence to technical

specifications, radiological controls, observation of all er part of the

actual work and/or retesting in progress, specified retest requirements, and

adherence to the appropriate quality controls.

No violations or deviations were identified.

G. Surveillance Testing Observation (61726)

The inspector observed the performance of selected surveillances. The

observation included a review of the procedure for technical adequacy,

conformance to Technical Specifications, verification of test instrument

calibration, observation of all or part of the actual surveillances, removal

from service and return to service of the system or components affected, and

review of the data for acceptability based upon the acceptance criteria.

No violations or deviations were identified.

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I 7. ESF System Walkdown (71710) l

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f A complete walkdown was conducted on the accessible portions of the

essential and emergency 1tghting system. The walkdown consisted of an

inspection and ' verification, where possible, of the required system valve

alignment, including valve power available and valve locking, where

required; instrumentation valved in and functioning; electrical and

instrumentation cabinets free from debris, loose materials, jumpers and

evidence of rodents, and system free from other degrading conditions. Minor

discrepancies were noted and the licensee was notified and will correct the i

discrepancies. l

The inspector made an observation that neither essential or emergency

l lighting was provided in the diesel generator building nor the upper control i

i panel room. These areas are not described in the FSAR as requiring l

l essential or emergency lighting. The inspector has requested regional and

NRR evaluation for such lighting and this will be an Inspector Followup Item

l (416/86-02-04).

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No violations or deviations were identified.

8. Reportable Occurrences (90712 & 92700)

The below listed event reports were reviewed to determine if the information

provided met the NRC reporting requirements. The determination included

adequacy of event description and corrective action taken or planned,

existence of potential generic problems and the relative safety significance

of each event. Additional inplant reviews and discussions with plant

personnel as appropriate were conducted for the reports indicated by an

asterisk. The event reports were reviewed using the guidance of the general

j policy and procedure for NRC enforcement actions.

The following License Event Reports (LERs) are closed.

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LER No. Event Date Event

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l 85-017 April 12, 1985 Control room emergency l

filtration system charcoal

absorber test not performed.

85-032 December 18, 1984 Liquid effluent flow rate

i estimate exceeded LCO time l

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limit.

• 86-001 January 1, 1986 Operational error caused

i reactor scram on low vessel .

water level. l

• 85-034 September 6, 1985 SGTS efficiency below TS l

limits.

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85-035 September 11, 1985 MSIV leakage control system

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valve testing exceeded TS

limits.

• 86-002 January 10, 1986 Two isolation valves exceeded

leak test frequency.

• 85-010 February 23, 1985 Inadvertent ESF actuation while

shutdown.85-021 June 4, 1985 Reactor scram due to turbine

trip.

LER 86-001 discusses scram No. 36 which is discussed in inspection report

416/85-46.

LER 85-021 discusses scram No. 27 which is discussed in inspection report

416/85-28.

On April 29, 1985 the licensee reported a deficiency under the provisions of

10 CFR-21 regarding inadequate cooling in Transamerica Delaval, Inc. (TDI)

diesel generator control panels.

The licensee has taken the following corrective actions:

a. The affected linear reactors were replaced by new linear reactors which

incorporate a design change to reduce the operating temperature,

b. A design change was installed that provides cooling air flow to the

division I and II control panels.

These corrective actions have been comnleted. This item (P2185-08) is

closed.

No violations or deviations were identified.

9. Operating Reactor Events (93702)

The inspectors reviewed activities associated with the below listed reactor

events. The review included determination of cause, safety significance,

performance of personnel and systems, and corrective action. The inspectors

examined instrument recordings, computer printouts, operations journal

entries, scram reports and had discussions with operations maintenance and

engineering support personnel as appropriate.

a. On January 17, 1986, GE contacted Mr. C. E. Rossi, NRC, to inform the l

NRC of a condition that was determined to be not reportable but was I

considered to be germane to safety. During surveillance testing on

July 13,1985, the High Pressure Core Spray (HPCS) diesel generator

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failed and the generator was observed to be emitting sparks. The HPCS

generator was removed from service and a spare generator was installed.

The GE vendor Morrison-Knudson, supplier of the DG power source,

determined that the insulation failed at the generator (slip ring)

roller bearing end. GE attributed the insulation failure to a combined

creep-fatique mechanism. This insulation failure does not allow the

generator to meet the required service life requirement and failure

could occur without prior warning during an emergency demand. The

generator manufacturer is Northern Electric Industries Parson

Peebles-Electric Products, Inc. One foreign plant has the only other

operating HPCS configuration similar to Grand Gulf.

The GE evaluation of generator Mean Time To Failure (MTTF) has

identified 150-200 hours of operation for the HPCS generator as

providing adequate mitigation time for any major loss of offsite power

accident. The GE analysis concluded that the concern was not a

substantial safety hazard and was not reportable per 10 CFR 21. The

I removed Grand Gulf Unit 1 generator has been modified and it is

Morrison-Knudson's and GE's engineering judgement that the installed

HPCS generator can be operated safely until replaced by the modified

generator during the next refueling outage. The licensee's next

refueling outage is now scheduled to start on September 1, 1986.

By letter dated August 6,1985, the licensee reported this failure

pursuant to Technical Specification 4.8.1.1.3. The licensee plans to

replace the HPCS generator now installed with the modified generator at

the first refueling outage. This will be an Inspector Followup Item

(416/86-02-02),

b. On February 14, 1986, the licensee received a letter from GE regarding

the number of operable Safety Relief Valves (SRV) required by technical

specifications (TS).

Current TS allows operation with only 13 of the 20 SRVs in service. GE

concluded that there was no significant safety hazard but recommended

near term operation with no more than one SRV out of service until more

analytical work is completed. The licensee initiated a TS position

statement (TSPS No.83) that requires the safety and relief valve

functions of at least 19 SRVs for continued operation. This TSPS will

be effective until this issue is resolved. This will be an Inspector

Followup Item (416/86-02-03).

No violations or deviations were identified.

10. Inspector Followup And Unresolved Items (92701)

a. (Closed) Inspector Followup Item - 416/85-03-02, Minor Procedure

Discrepancies. The licensee has revised and updated the post trip

analysis procedure. This item is closed.

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b. (Closed) Inspector Followup Item -

416/85-27-03, Environmental

Conditions in the M&TE Calibration Lab. The licensee modified

administrative procedure 01-5-07-3, Calibration & Control of Measuring

& Test Equipment, to require control of environmental conditions at the

time of calibration if required. This item is closed.

c. (Closed) Inspector Followup Item - 416/85-46-05, Cold Weather Prepara-

tions Procedure. The Itcensee has issued Equipment Performance

Instruction 04-1-03-A30-1, Cold Weather Protection, to outline actions

to be taken prior to cold weather conditions. This item is closed.

11. Information Meetings With Local Officials (94600)

Mr. L. Kintner, Project Manager, NPR, Mr. V. Panciera, Branch Chief, RII,

Mr. H. Dance, Section Chief, RII, and the Resident Inspectors met with

Claiborne County and Tensas Parish representatives at 10:00 a.m. on February

6, 1986. The meeting was held in the Claiborne County Court House located

in Port Gibson, Ms. A handout was distributed with information describing

the NRC objectives in having meetings with local officials, described the

NRC organization, gave the location and information available in the public

document room and listed NRC phone numbers to call for information. A short

presentation was given on NRC Headquarters, Region II, and Resident

Inspectors locations and duties. A question and answer period followed.

12. SALP Meeting

A management meeting was held in the NRC Region II offices on February 20,

1986 to discuss the two areas of the Systematic Assessment of Licensee

Performance (SALP) program where the licensee received category 3 ratings

for two consecutive years. These two areas, Licensing and Quality Programs

and Administrative Controls affecting Quality, received category 3 ratings

for the SALP periods September 1, 1982 thru September 30, 1983 and October 1,

1983 thru April 30, 1985. The attendees are listed in paragraph 1. The NRC

presented their evaluation of the licensee's performance in the two areas

since the last SALP evaluation. The licensee emphasized that much management

attention has been devoted to these areas in order that positive improvements

be made. The licensee then presented their internal ovaluation of the noted

areas and explained the corrective actions they had taken or had planned.

Specifically, in the Quality Programs area, the licensee is pursuing increased

technical and management training, more indepth reviews and prompt resolution

of issues. In the licensing area the licensee is concentrating on accuracy

and completeness of submittals, adherence to commitments and management

attention as related to problem solving. Here also more attention to j

staffing, training, and effective assignment of personnel is vigorously

being pursued. In summary, the licensee stated they felt this meeting was

constructive in that it allowed an exchange of candid comments and would

allow them to improve performance during this SALP period.

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